For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial ~~reporting.~~reporting and have not yet selected the year in which we will adopt the standard.

ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows in order to reduce diversity in practice.

For public entities, ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and is effective for interim periods in the year of adoption. An entity that elects early adoption must adopt all of the amendments in the same period. Entities must apply the guidance retrospectively to all periods presented, but may apply it prospectively if retrospective application would be impracticable. We plan to adopt the standard in the fourth quarter of 2017. If we had adopted ASU 2016-15 effective January 1, 2017, there would have been no impact to the Sempra Energy, SDG&E or SoCalGas Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2017, based on the timing of cash receipts and cash payments impacted by the ASU.

ASU 2016-18, “Restricted Cash”: ASU 2016-18 requires amounts described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents.

For public entities, ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We plan to adopt the standard in the fourth quarter of 2017. If we had adopted ASU 2016-18 effective January 1, 2017, cash and cash equivalents at the beginning of the period would have included restricted cash of $76 million and $12 million, and cash and cash equivalents at the end of the period would have included restricted cash of $87 million and $14 million in Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2017, respectively.

ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments are to be applied on a prospective basis. We have not yet selected the year in which we will adopt the standard.

ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”: ASU 2017-05 clarifies the scope of accounting for the derecognition or partial sale of nonfinancial assets to exclude all businesses and nonprofit activities. ASU 2017-05 also provides a definition for in-substance nonfinancial assets and additional guidance on partial sales of nonfinancial assets. For public entities, ASU 2017-05 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. Entities may apply a full retrospective or modified retrospective approach. Under a modified retrospective approach, entities are required to apply the guidance to any transactions that are not completed as of the adoption date. We will adopt the standard in conjunction with our adoption of ASU 2014-09 on January 1, 2018 using the modified retrospective transition method.

ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan note in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We are currently evaluating the effect of the standard on our ongoing financial reporting and will adopt the standard on January 1, 2018. Based on our assessment to date, we have determined that we will elect the practical expedient available under the transition guidance.

NOTE 3. ACQUISITION AND DIVESTITURE ACTIVITY

We consolidate assets acquired and liabilities ~~acquired~~assumed as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date. We did not complete any acquisitions during the six months ended June 30, 2017 or 2016. At June 30, 2017, the purchase price allocations for the acquisitions of Ventika in December 2016 and IEnova Pipelines (formerly known as GdC) in September 2016 were preliminary and subject to completion. Adjustments to the fair value estimates may occur as various valuations and assessments are finalized, primarily related to tax assets, liabilities and other attributes.

~~ACQUISITIONS~~

ACQUISITION

Sempra Renewables

InOn July ~~2016,~~10, 2017, Sempra Renewables ~~invested $22~~paid $124 million ~~to acquire~~in cash for an asset acquisition of a ~~100-percent interest in the Apple Blossom Wind~~solar project ~~a 100-megawatt (MW) wind farm~~located near Fresno, California, which is currently under ~~development in Huron County, Michigan. The wind farm has a 15-year power purchase agreement with Consumers Energy that will commence upon commercial operation, expected in late 2017.~~

In March 2015, Sempra Renewables invested $8 million to acquire a 100-percent interest in the Black Oak Getty Wind project, a 78-MW wind farm currently under construction in Stearns County, Minnesota. The wind farm has a 20-year power purchase agreement with Minnesota Municipal Power Agency that will commence upon commercial operation, expected in late 2016.

~~PENDING ACQUISITION~~

~~Sempra Mexico~~

IEnova and Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company) are 50-50 partners in the joint venture Gasoductos de Chihuahua S. de R.L. de C.V. (GdC). GdC develops and operates energy infrastructure in Mexico. On July 31, 2015, IEnova entered into an agreement to purchase PEMEX's 50-percent interest in GdC. The assets involved in the acquisition included three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal.

In December 2015, Mexico's Comisión Federal de Competencia Económica (COFECE or Mexican Competition Commission) objected to the transaction based upon previous antitrust rulings on PEMEX's indirect ownership of two of the assets, the TDF S. de R.L. de C.V. liquid petroleum gas pipeline (TDF Pipeline) and the San Fernando natural gas pipeline (San Fernando Pipeline), included in the acquisition as proposed. COFECE specified that these assets must be offered by PEMEX in a competitive bidding process as a prerequisite for approval of any transaction involving these two assets. COFECE's decision did not object to IEnova's acquisition of the assets on a market concentration basis.

In July 2016, IEnova announced that the parties reached an agreement to restructure the transaction to allow PEMEX to satisfy the conditions imposed by the COFECE to hold the TDF Pipeline and San Fernando Pipeline for sale in an open bidding process. The open bidding process was held in July 2016 and ended with no bidders participating. Subject to final approval by the COFECE, IEnova expects to acquire GdC's assets consistent with the original agreement, including the TDF and San Fernando pipelines, for a purchase price of approximately $1.1 billion. Also consistent with the original agreement, we expect the transaction to exclude the Los Ramones Norte pipeline that is owned under a separate joint venture with GdC, PEMEX, BlackRock and First Reserve, keeping IEnova's interest in the pipeline at the current 25 percent. We expect the transaction to close in the third quarter of 2016. The transaction remains subject to the satisfactory completion of the Mexican antitrust review and customary closing conditions, and may require further approvals from other Mexican authorities.

IEnova currently accounts for its 50-percent interest in GdC as an equity method investment. At closing, GdC will become a wholly owned, consolidated subsidiary of IEnova. We anticipate that we will recognize a noncash gain associated with the remeasurement of our equity interest in GdC upon consummation of the transaction; however, as the assets to be included in the transaction are not yet confirmed and the valuation of such assets is not finalized, we are unable to reasonably estimate the gain at this time.

~~Sempra Energy has committed to provide interim financing to close the transaction.~~construction. We expect to ~~ultimately finance~~place the ~~acquisition~~project into service in phases during the fourth quarter of 2017 and the first half of 2018 and, when fully constructed, it will be capable of producing up to 200 MW of solar power. The solar project is fully contracted under four long-term PPAs, with ~~a combination~~an average contract term of ~~debt and equity at IEnova based on market conditions.~~18 years.

ASSETS HELD FOR SALE

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 12 ~~months.~~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.

~~The following table summarizes the carrying amounts of the major classes of assets and related liabilities held for sale at June 30, 2016, and we discuss each group of assets below.~~

ASSETS HELD FOR SALE AT JUNE 30, 2016
(Dollars in millions)
Termoeléctrica de Mexicali EnergySouth Inc.

Cash and cash equivalents $ 1 $ 1
Inventories 8 3
Other current assets 21 13
Regulatory assets ― 12
Goodwill ― 72
Other assets 17 53
Property, plant and equipment, net 250 203
Total assets held for sale $ 297 $ 357

Accounts payable $ 1 $ 9
Other current liabilities 6 12
Long-term debt ― 67
Deferred income taxes 13 38
Regulatory liabilities ― 22
Asset retirement obligations 4 12
Other liabilities 19 19
Total liabilities held for sale $ 43 $ 179

Sempra Mexico

Termoeléctrica de Mexicali

In February 2016, management approved a plan to market and sell Sempra ~~Mexico's Termoeléctrica de Mexicali (TdM),~~Mexico’s TdM, a 625-MW natural gas-fired power plant located in Mexicali, Baja California, ~~Mexico.~~Mexico, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. As a result, we stopped depreciating the plant and classified it as held for sale.

In connection with ~~classifying~~the sales process, Sempra Mexico received new market information indicating that the fair value of TdM at June 30, 2017 is lower than previously estimated. As a result, and after further analysis, Sempra Mexico further reduced the carrying value of TdM by recognizing a noncash impairment charge of $71 million in the three months and six months ended June 30, 2017, recorded in Impairment Losses on Sempra Energy’s Condensed Consolidated Statements of Operations. We discuss non-recurring fair value measures and the associated accounting impact on TdM in Note 8.

In connection with TdM’s classification as held for sale, we recognized ~~expense of~~a $3 million ~~($2~~and $8 million ~~after noncontrolling interests)~~tax benefit for the three months and six months ended June 30, 2017, respectively, and $3 million and $32 million ~~($26 million after noncontrolling interests)~~ in tax expense for the three months and six months ended June 30, 2016, respectively, ~~in Income Tax Expense on Sempra Energy's Condensed Consolidated Statements of Operations for~~related to a deferred Mexican income tax liability related to the excess of carrying value over the tax basis. As the Mexican income tax on this outside basis difference is based on current carrying value, foreign exchange rates and inflation, such amount could change in future periods until the date of sale.

We ~~considered~~are actively pursuing the ~~estimated fair value~~sale of ~~the plant, less costs to sell, and determined that no adjustment to carrying value was required. In estimating fair value,~~TdM, which we used both a market approach and discounted cash flow valuation techniques. In the event that the estimated sales price, less transaction costs, is less than the carrying value, or updated market information indicates fair value may be less than carrying value, we would recognize a loss in our results of operations at that time. We expect to ~~complete the sale~~be completed in the second half of ~~2016.~~2017.

At June 30, 2017, the carrying amounts of the major classes of assets and related liabilities held for sale associated with TdM are as follows:



ASSETS HELD FOR SALE AT JUNE 30, 2017
(Dollars in millions)
	Termoeléctrica de Mexicali
Inventories	$	10
Other current assets	19
Property, plant and equipment, net	55
Other noncurrent assets	25
Total assets held for sale	$	109

Accounts payable	$	11
Other current liabilities	4
Asset retirement obligations	5
Other noncurrent liabilities	27
Total liabilities held for sale	$	47

DIVESTITURE

Sempra ~~Natural Gas~~LNG & Midstream

~~EnergySouth Inc.~~

In April 2016, Sempra Natural Gas signed a definitive agreement to sell 100 percent of the outstanding equity of EnergySouth Inc. (EnergySouth), the parent company of Mobile Gas and Willmut Gas. We expect to receive cash proceeds of approximately $323 million, subject to normal adjustments at closing, and the buyer will assume existing debt of approximately $67 million. Litigation at Mobile Gas, discussed in Note 11, will be retained by Mobile Gas at the close of the transaction. The transaction is subject to customary regulatory approvals. In addition, the State of Missouri Public Service Commission (MPSC) in July 2016 opened an investigation into whether the transaction will have any effect on Missouri ratepayers and is subject to MPSC's jurisdiction. We expect the sale to close in 2016.

~~DIVESTITURES~~

~~Sempra Natural Gas~~

Investment in Rockies Express Pipeline LLC

In March 2016, Sempra ~~Natural Gas~~LNG & Midstream entered into an agreement to sell its 25-percent interest in Rockies Express ~~Pipeline LLC (Rockies Express) to a subsidiary of Tallgrass Development, LP~~ for cash consideration of $440 million, subject to adjustment at closing. The transaction closed in May 2016 for total cash proceeds of $443 million.

At the date of the agreement, the carrying value of Sempra ~~Natural Gas'~~LNG & Midstream’s investment in Rockies Express was $484 million. Following the execution of the agreement, Sempra ~~Natural Gas~~LNG & Midstream measured the fair value of its equity method investment at $440 million, and recognized a $44 million ($27 million after-tax) impairment in Equity Earnings (Losses), Before Income Tax, on the Sempra Energy Condensed Consolidated Statement of Operations in the first quarter of 2016. We discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 8.

~~In the second quarter of 2016, Sempra Natural Gas permanently released pipeline capacity that it held with Rockies Express and others, as we discuss in Note 11.~~

~~Mesquite Power Plant~~

~~In April 2015, Sempra Natural Gas sold the remaining 625-MW block~~10 of the ~~Mesquite Power plant, together with a related power sales contract, for net cash proceeds of $347 million. We recognized a pretax gain on~~Notes to Consolidated Financial Statements in the ~~sale of $61 million ($36 million after-tax), included in Gain on Sale of Assets on our Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2015.~~Annual Report.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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 provide additional information concerning our equity method investments in Note 3 above and in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.

SEMPRA SOUTH AMERICAN UTILITIES

In February 2017, Sempra South American Utilities recorded the equitization of its $19 million note receivable due from Eletrans, resulting in an increase in its investment in this unconsolidated joint venture.

SEMPRA MEXICO

~~In June 2016, Infraestructura Marina del Golfo (IMG), a~~Sempra Mexico invested cash of $72 million in its unconsolidated joint venture, between IEnova and a subsidiary of TransCanada Corporation (TransCanada), was awarded the right to build, own and operate the Sur de Texas – Tuxpan natural gas pipeline by the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE). IEnova has a 40-percent interestIMG, in the project and TransCanada owns the remaining 60-percent interest. The project is expected to be completed in late 2018 and is fully contracted under a 25-year natural gas transportation service contract with the CFE.

six months ended June 30, 2017.

SEMPRA RENEWABLES

Sempra Renewables invested cash of $18 million in its unconsolidated joint ventures ~~during both~~in the six months ended June 30, ~~2016 and 2015.~~

2016.

SEMPRA ~~NATURAL GAS~~LNG & MIDSTREAM

Sempra ~~Natural Gas~~LNG & Midstream capitalized $24 million of interest during both the six months ended June 30, ~~2016~~2017 and ~~2015~~2016 related to its investment in Cameron LNG ~~Holdings, LLC (Cameron LNG JV),~~JV, which has not commenced planned principal operations. ~~In addition, during~~During the six months ended June 30, ~~2015,~~2017, Sempra ~~Natural Gas~~LNG & Midstream invested cash of $3$1 million in ~~the~~this unconsolidated joint ~~venture and accrued $7 million for a project capital call due and subsequently paid in July 2015.~~venture.

In May 2016, Sempra ~~Natural Gas~~LNG & Midstream sold its 25-percent interest in Rockies Express, as we discuss in Note 3. ~~In April 2015, Sempra Natural Gas invested $113 million of cash in Rockies Express to repay project debt that matured in early 2015.~~

GUARANTEES

At June 30, 2017, we had outstanding guarantees aggregating a maximum of $4.7 billion with an aggregate carrying value of $44 million. We discuss these guarantees ~~that we have provided, which have a maximum aggregate amount of $4.5 billion,~~below and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. ~~These guarantees have an aggregate carrying value of $63 million at June 30, 2016.~~

Sempra Mexico

IMG is a joint venture between a subsidiary of IEnova and a subsidiary of TransCanada. IEnova has an indirect 40-percent ownership interest and TransCanada has an indirect 60-percent ownership interest in IMG. IEnova and TransCanada have each provided guarantees to third parties associated with construction of IMG’s Sur de Texas - Tuxpan natural gas marine pipeline. The aggregate amount of the obligations guaranteed by IEnova shall not exceed $288 million and will terminate upon completion of all guaranteed obligations. IEnova expects the construction giving rise to these guarantees to be completed by the end of 2018.

NOTE 5. OTHER FINANCIAL DATA

INVENTORIES

The components of inventories by segment are as follows:



INVENTORY BALANCES
(Dollars in millions)
	Natural gas				Liquefied natural gas				Materials and supplies				Total
	June 30, 2017		December 31, 2016		June 30, 2017		December 31, 2016		June 30, 2017		December 31, 2016		June 30, 2017		December 31, 2016
SDG&E	$	1	$	2	$	—	$	—	$	88	$	78	$	89	$	80
SoCalGas(1)	—		11		—		—		45		47		45		58
Sempra South American Utilities	—		—		—		—		33		27		33		27
Sempra Mexico	—		—		12		6		2		1		14		7
Sempra Renewables	—		—		—		—		4		4		4		4
Sempra LNG & Midstream	51		79		3		3		—		—		54		82
Sempra Energy Consolidated	$	52	$	92	$	15	$	9	$	172	$	157	$	239	$	258

INVENTORY BALANCES
(Dollars in millions)
Natural gas Liquefied natural gas Materials and supplies Total

June 30,
2016

December 31,
2015
June 30,
2016
December 31,
2015
June 30,
2016
December 31,
2015
June 30,
2016
December 31,
2015
SDG&E $ 1 $ 6 $ ― $ ― $ 70 $ 69 $ 71 $ 75
SoCalGas(1) ― 49 ― ― 44 30 44 79
Sempra South American
Utilities ― ― ― ― 43 30 43 30
Sempra Mexico ― ― 7 3 2 10 9 13
Sempra Renewables ― ― ― ― 3 3 3 3
Sempra Natural Gas 96 94 4 3 ― 1 100 98
Sempra Energy
Consolidated $ 97 $ 149 $ 11 $ 6 $ 162 $ 143 $ 270 $ 298
(1) At both June 30, 2016 and December 31, 2015, SoCalGas' natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas leak, which we discuss in Note 11.


(1)	At June 30, 2017 and December 31, 2016, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas leak, which we discuss in Note 11.

GREENHOUSE GAS ALLOWANCES

The Condensed Consolidated Balance Sheets include the following amounts associated with GHG allowances and obligations.



GHG ALLOWANCES AND OBLIGATIONS
(Dollars in millions)
	Sempra Energy Consolidated				SDG&E				SoCalGas
	June 30, 2017		December 31, 2016		June 30, 2017		December 31, 2016		June 30, 2017		December 31, 2016
Assets:
Other current assets	$	40	$	40	$	16	$	16	$	24	$	24
Sundry	334		295		190		182		140		109
Total assets	$	374	$	335	$	206	$	198	$	164	$	133

Liabilities:
Other current liabilities	$	40	$	40	$	16	$	16	$	24	$	24
Deferred credits and other	202		171		88		72		111		96
Total liabilities	$	242	$	211	$	104	$	88	$	135	$	120

GOODWILL

We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The ~~decrease~~increase in goodwill from ~~$819~~$2,364 million at December 31, ~~2015~~2016 to ~~$786~~$2,379 million at June 30, ~~2016~~2017 is due to ~~the reclassification of EnergySouth goodwill at Sempra Natural Gas to assets held for sale, offset by~~ foreign currency translation at Sempra South American Utilities. We record the offset of ~~the~~this fluctuation ~~from foreign currency translation~~ in ~~Other Comprehensive Income (Loss).~~OCI.

VARIABLE INTEREST ENTITIES

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~~on qualitative and quantitative analyses, which assess

§
▪	the purpose and design of the VIE;

§
▪	the nature of the ~~VIE's~~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

SDG~~&E's~~&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.

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~~&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~~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.

Otay Mesa VIE

SDG&E has an agreement to purchase power generated at ~~the Otay Mesa Energy Center (OMEC),~~OMEC, a 605-MW generating facility. In addition to tolling, the agreement provides SDG&E with the option to purchase OMEC at the end of the contract term in 2019, or upon earlier termination of the ~~purchased-power agreement,~~PPA, 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,~~for $280 million, which we refer to as the put option.

The facility owner, ~~Otay Mesa Energy Center~~OMEC LLC, ~~(OMEC LLC),~~ is a VIE, ~~(Otay~~which we refer to as Otay Mesa ~~VIE),~~VIE, of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights, holds no equity in OMEC LLC 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~~consolidate Otay Mesa VIE. Otay Mesa ~~VIE's~~VIE’s equity of ~~$37~~$34 million at June 30, ~~2016~~2017 and ~~$53~~$37 million at December 31, ~~2015~~2016 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

OMEC LLC has a loan outstanding of ~~$310~~$300 million at June 30, ~~2016,~~2017, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is ~~secured~~collateralized by ~~OMEC's property, plant and equipment.~~OMEC’s assets. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 7.

The Condensed Consolidated Statements of Operations of Sempra Energy and SDG&E include the following amounts associated with Otay Mesa VIE. The amounts are net of eliminations of transactions between SDG&E and Otay Mesa VIE. The captions in the table below ~~generally~~ correspond to SDG~~&E's~~&E’s Condensed Consolidated Statements of Operations.

AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
Operating expenses
    Cost of electric fuel and purchased power $ (17) $ (21) $ (34) $ (39)
    Operation and maintenance 15 6 19 10
    Depreciation and amortization 10 6 17 12
        Total operating expenses 8 (9) 2 (17)
Operating (loss) income (8) 9 (2) 17
Interest expense (5) (5) (10) (9)
(Loss) income before income taxes/Net (loss) income (13) 4 (12) 8
Losses (earnings) attributable to noncontrolling interest 13 (4) 12 (8)
   Earnings attributable to common shares $ ― $ ― $ ― $ ―



AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
Operating expenses
Cost of electric fuel and purchased power	$	(21	)	$	(17	)	$	(39	)	$	(34	)
Operation and maintenance	5			15			9			19
Depreciation and amortization	7			10			14			17
Total operating expenses	(9		)	8			(16		)	2
Operating income (loss)	9			(8		)	16			(2		)
Interest expense	(5		)	(5		)	(10		)	(10		)
Income (loss) before income taxes/Net income (loss)	4			(13		)	6			(12		)
(Earnings) losses attributable to noncontrolling interest	(4		)	13			(6		)	12
Earnings attributable to common shares	$	—		$	—		$	—		$	—

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 of a ~~variable interest entity~~VIE at June 30, ~~2016.~~2017. 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. 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 could be significant to the financial position and liquidity of SDG&E and Sempra Energy. We provide additional information about ~~power purchase agreements~~PPAs with ~~peaker~~power plant facilities that are VIEs of which SDG&E is not the primary beneficiary in Note 11 below and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

We provide additional information regarding Otay Mesa VIE in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Renewables

Effective December 2016, certain of Sempra Renewables’ wind and solar power generation projects are held by limited liability companies whose members are Sempra Renewables and financial institutions. The financial institutions are noncontrolling tax equity investors to which earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. These entities are VIEs and Sempra Energy is the primary beneficiary, generally due to Sempra Energy’s power as the operator of the renewable energy projects to direct the activities that most significantly impact the economic performance of these VIEs.

As the primary beneficiary of these tax equity limited liability companies, we consolidate them. Sempra Energy’s Condensed Consolidated Balance Sheets included $912 million and $926 million of PP&E, net, and equity of $454 million and $468 million included in Other Noncontrolling Interests at June 30, 2017 and December 31, 2016, respectively, associated with these entities. Sempra Energy’s Condensed Consolidated Statements of Operations include the following amounts associated with the tax equity limited liability companies. The amounts are net of eliminations of transactions between Sempra Energy and these entities.



AMOUNTS ASSOCIATED WITH TAX EQUITY ARRANGEMENTS
(Dollars in millions)
		Three months ended June 30, 2017			Six months ended June 30, 2017
REVENUES
Energy-related businesses		$	18		$	31
EXPENSES
Operation and maintenance		(7		)	(9		)
Depreciation and amortization		(8		)	(16		)
Income before income taxes		3			6
Income tax expense		(4		)	(6		)
Net loss		(1		)	—
Losses attributable to noncontrolling interests(1)		7			10
Earnings		$	6		$	10

(1)	Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages.

We provide additional information regarding the tax equity limited liability companies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra ~~Natural Gas~~LNG & Midstream

Sempra ~~Energy's~~Energy’s equity method investment in Cameron LNG JV is considered to be a VIE ~~generally~~principally 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 JV. We will continue to evaluate Cameron LNG JV for any changes that may impact our determination of the primary beneficiary. The carrying value of our investment in Cameron LNG JV, including amounts recognized in ~~Accumulated Other Comprehensive Income (Loss) (AOCI)~~AOCI related to interest-rate cash flow hedges at Cameron LNG JV, was ~~$818~~$977 million at June 30, ~~2016~~2017 and ~~$983~~$997 million at December 31, ~~2015.~~2016. Our maximum exposure to loss includes the carrying value of our investment and the guarantees discussed ~~above~~ in Note 4 above and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Variable Interest Entities

Sempra ~~Energy's~~Energy’s other ~~operating units~~businesses also enter into arrangements which could include variable interests. We evaluate these arrangements and applicable entities based on 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; however, their financial statements are not material to the financial statements of Sempra Energy. 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.

PENSION AND OTHER POSTRETIREMENT BENEFITS

Net Periodic Benefit Cost

The following three tables provide the components of net periodic benefit cost:



NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	Three months ended June 30,
	2017			2016			2017			2016
Service cost	$	29		$	27		$	5		$	6
Interest cost	37			40			11			11
Expected return on assets	(40		)	(41		)	(17		)	(18		)
Amortization of:
Prior service cost	2			3			—			—
Actuarial loss	8			7			—			—
Regulatory adjustment	(29		)	(28		)	2			2
Total net periodic benefit cost	$	7		$	8		$	1		$	1

	Six months ended June 30,
	2017			2016			2017			2016
Service cost	$	57		$	55		$	11		$	11
Interest cost	74			80			20			22
Expected return on assets	(80		)	(83		)	(33		)	(35		)
Amortization of:
Prior service cost	5			6			—			—
Actuarial loss (gain)	16			13			(1		)	—
Regulatory adjustment	(41		)	(56		)	4			4
Total net periodic benefit cost	$	31		$	15		$	1		$	2

NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
Pension benefits Other postretirement benefits
Three months ended June 30,
2016 2015 2016 2015
Service cost $ 27 $ 29 $ 6 $ 7
Interest cost 40 39 11 11
Expected return on assets (41) (44) (18) (17)
Amortization of:
    Prior service cost 3 2 ― ―
    Actuarial loss 7 11 ― ―
Regulatory adjustment (28) (30) 2 ―
Total net periodic benefit cost $ 8 $ 7 $ 1 $ 1

Six months ended June 30,
2016 2015 2016 2015
Service cost $ 55 $ 59 $ 11 $ 14
Interest cost 80 78 22 23
Expected return on assets (83) (88) (35) (34)
Amortization of:
    Prior service cost (credit) 6 5 ― (1)
    Actuarial loss 13 19 ― ―
Regulatory adjustment (56) (59) 4 ―
Total net periodic benefit cost $ 15 $ 14 $ 2 $ 2



NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	Three months ended June 30,
	2017			2016			2017			2016
Service cost	$	7		$	8		$	2		$	1
Interest cost	10			11			2			2
Expected return on assets	(13		)	(13		)	(4		)	(2		)
Amortization of:
Prior service cost	1			1			1			1
Actuarial loss (gain)	2			2			—			(1		)
Regulatory adjustment	(7		)	(8		)	(1		)	(1		)
Total net periodic benefit cost	$	—		$	1		$	—		$	—

	Six months ended June 30,
	2017			2016			2017			2016
Service cost	$	15		$	15		$	3		$	2
Interest cost	19			21			4			4
Expected return on assets	(24		)	(25		)	(7		)	(5		)
Amortization of:
Prior service cost	1			1			2			2
Actuarial loss (gain)	4			5			—			(1		)
Regulatory adjustment	(14		)	(15		)	(2		)	(2		)
Total net periodic benefit cost	$	1		$	2		$	—		$	—



NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	Three months ended June 30,
	2017			2016			2017			2016
Service cost	$	18		$	18		$	3		$	3
Interest cost	24			25			8			9
Expected return on assets	(25		)	(27		)	(13		)	(14		)
Amortization of:
Prior service cost (credit)	2			2			—			(1		)
Actuarial loss (gain)	4			2			(1		)	—
Regulatory adjustment	(22		)	(20		)	3			3
Total net periodic benefit cost	$	1		$	—		$	—		$	—

	Six months ended June 30,
	2017			2016			2017			2016
Service cost	$	36		$	35		$	7		$	7
Interest cost	48			50			15			17
Expected return on assets	(51		)	(52		)	(26		)	(28		)
Amortization of:
Prior service cost (credit)	4			4			(1		)	(2		)
Actuarial loss (gain)	8			5			(1		)	—
Regulatory adjustment	(27		)	(41		)	6			6
Total net periodic benefit cost	$	18		$	1		$	—		$	—

NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
Pension benefits Other postretirement benefits
Three months ended June 30,
2016 2015 2016 2015
Service cost $ 8 $ 8 $ 1 $ 2
Interest cost 11 10 2 2
Expected return on assets (13) (13) (2) (3)
Amortization of:
    Prior service cost 1 1 1 1
    Actuarial loss (gain) 2 2 (1) ―
Regulatory adjustment (8) (7) (1) (2)
Total net periodic benefit cost $ 1 $ 1 $ ― $ ―

Six months ended June 30,
2016 2015 2016 2015
Service cost $ 15 $ 16 $ 2 $ 4
Interest cost 21 20 4 4
Expected return on assets (25) (27) (5) (6)
Amortization of:
    Prior service cost 1 1 2 2
    Actuarial loss (gain) 5 4 (1) ―
Regulatory adjustment (15) (12) (2) (4)
Total net periodic benefit cost $ 2 $ 2 $ ― $ ―

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
Pension benefits Other postretirement benefits
Three months ended June 30,
2016 2015 2016 2015
Service cost $ 18 $ 19 $ 3 $ 5
Interest cost 25 24 9 9
Expected return on assets (27) (27) (14) (14)
Amortization of:
    Prior service cost (credit) 2 2 (1) (2)
    Actuarial loss 2 6 ― ―
Regulatory adjustment (20) (23) 3 2
Total net periodic benefit cost $ ― $ 1 $ ― $ ―

Six months ended June 30,
2016 2015 2016 2015
Service cost $ 35 $ 38 $ 7 $ 10
Interest cost 50 49 17 18
Expected return on assets (52) (54) (28) (28)
Amortization of:
    Prior service cost (credit) 4 4 (2) (4)
    Actuarial loss 5 11 ― ―
Regulatory adjustment (41) (47) 6 4
Total net periodic benefit cost $ 1 $ 1 $ ― $ ―

Benefit Plan Contributions

The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in ~~2016:~~2017:



BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E		SoCalGas
Contributions through June 30, 2017:
Pension plans	$	28	$	2	$	17
Other postretirement benefit plans	1		—		—
Total expected contributions in 2017:
Pension plans	$	174	$	32	$	90
Other postretirement benefit plans	8		4		1

BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
Sempra Energy
Consolidated SDG&E SoCalGas
Contributions through June 30, 2016:
    Pension plans $ 23 $ 2 $ ―
    Other postretirement benefit plans 2 ― 1
Total expected contributions in 2016:
    Pension plans $ 123 $ 4 $ 77
    Other postretirement benefit plans 6 2 1

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 ~~$436~~$427 million and ~~$464~~$430 million at June 30, ~~2016~~2017 and December 31, ~~2015,~~2016, respectively.

EARNINGS PER SHARE

The following table provides ~~earnings per share (EPS)~~EPS computations for the three months and six months ended June 30, ~~2016~~2017 and ~~2015.~~2016. Basic EPS is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.



EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Three months ended June 30,				Six months ended June 30,
	2017		2016(1)		2017		2016(1)
Numerator:
Earnings/Income attributable to common shares	$	259	$	16	$	700	$	369

Denominator:
Weighted-average common shares outstanding for basic EPS(2)	251,447		250,096		251,290		249,915
Dilutive effect of stock options, RSAs and RSUs(3)	1,375		1,940		1,319		1,860
Weighted-average common shares outstanding for diluted EPS	252,822		252,036		252,609		251,775

EPS:
Basic	$	1.03	$	0.06	$	2.79	$	1.48
Diluted	1.03		0.06		2.77		1.47

EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
Numerator:
    Earnings/Income attributable to common shares $ 16 $ 295 $ 335 $ 732

Denominator:
    Weighted-average common shares
outstanding for basic EPS(1) 250,096 248,108 249,915 247,916
    Dilutive effect of stock options, restricted
stock awards and restricted stock units 1,842 3,383 1,771 3,348
    Weighted-average common shares
outstanding for diluted EPS 251,938 251,491 251,686 251,264

Earnings per share:
    Basic $ 0.06 $ 1.19 $ 1.34 $ 2.95
    Diluted 0.06 1.17 1.33 2.91
(1) Includes 568 and 501 average fully vested restricted stock units held in our Deferred Compensation Plan for the three months ended June 30, 2016 and 2015, respectively, and 562 and 476 of such units for the six months ended June 30, 2016 and 2015, respectively. These fully vested restricted stock units are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.


(1)	As adjusted for the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.

(2)

Includes 608 and 568 average fully vested RSUs held in our Deferred Compensation Plan for the three months ended June 30, 2017 and 2016, respectively, and 604 and 562 for the six months ended June 30, 2017 and 2016, respectively. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.


(3)	Due to market fluctuations of both Sempra Energy stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report, dilutive RSUs may vary widely from period-to-period.

The ~~dilution~~potentially dilutive impact from ~~common~~ stock options, RSAs and RSUs is ~~based on~~calculated under the treasury stock method. Under this method, proceeds based on the exercise price ~~plus~~and 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~~period, reducing the ~~assumed exercise~~number 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). For the three months and six months ended June 30, 2016 and 2015, we had no such antidilutive stock options outstanding. For the three months and six months ended June 30, 2016 and 2015, we had no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.

The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, related to the awards and units are assumedpotential new shares to be ~~used to repurchase shares on the open market at the average market price for the period.~~issued and sometimes causing an antidilutive effect. The ~~windfall tax benefits or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting~~computation 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 1,010 antidilutive RSUs from the application of unearned compensation in the treasury stock methoddiluted EPS for the three months ended June 30, ~~2016. There were no such~~2017 and 2016 excludes 3,010 and 1,010 potentially dilutive shares, respectively, because to include them would be antidilutive ~~RSAs and 2,408 such antidilutive RSUs~~ for the period. The computation of diluted EPS

for the six months ended June 30, ~~2016. There were no~~2017 and 2016 excludes 3,010 and 2,408 such ~~antidilutive RSAs and 4,715 such antidilutive RSUs for both the three months and six months ended June 30, 2015.~~

Our performance-based RSUs include awards that vest at the end of three-year (for awards granted during or after 2015) or four-year performance periods based on Sempra Energy's total return to shareholders relative to that of specified market indices (Total Shareholder Return or TSR RSUs) or based on the compound annual growth rate of Sempra Energy's EPS (EPS RSUs). The comparative market indices for the TSR RSUs are the Standard & Poor's (S&P) 500 Utilities Index and the S&P 500 Index. We primarily use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our EPS RSU targets. TSR RSUs represent the right to receive from zero to 1.5 shares (2.0 shares for awards granted during or after 2014) of Sempra Energy common stock if performance targets are met. EPS RSUs represent the right to receive from zero to 2.0 shares of Sempra Energy common stock if performance targets are met. If performance falls between the targets specified for each performance metric, we calculate the payout using linear interpolation. 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. We discuss performance-based RSU awards further in Note 8 of the Notes to Consolidated Financial Statements in our Annual Report.

Our RSAs, which are solely service-based, and those RSUs that are service-based or issued in connection with certain other performance goals represent the right to receive up to 1.0 share if the service requirements or certain other vesting conditions are met. These RSAs and RSUs have the same dividend equivalent rights as the performance-based RSUs described above. We include RSAs and these RSUs in potentialpotentially dilutive shares, ~~at 100 percent, subject to the application of the treasury stock method. We include our TSR RSUs and~~respectively. However, these shares could potentially dilute basic EPS 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 TSR RSU shares may vary widely from period-to-period. If it were assumed that performance goals for all performance-based 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 1,417,481 and 1,370,460 for the three months ended June 30, 2016 and 2015, respectively, and 1,491,195 and 1,424,855 for the six months ended June 30, 2016 and 2015, respectively.

~~SHARE-BASED COMPENSATION~~

~~We discuss our share-based compensation plans in Note 8 of the Notes to Consolidated Financial Statements~~ in the Annual Report. We recorded share-based compensation expense, net of income taxes, of $6 million and $7 million for the three months ended June 30, 2016 and 2015, respectively, and $13 million and $15 million for the six months ended June 30, 2016 and 2015, respectively. future.

Pursuant to our Sempra Energy share-based compensation plans, Sempra ~~Energy's compensation committee~~Energy’s Board of Directors granted ~~373,070 TSR RSUs, 94,760 EPS~~424,760 performance-based RSUs and ~~95,876~~93,619 service-based RSUs during the six months ended June 30, ~~2016,~~2017, primarily in January.

During the six months ended June 30, ~~2016,~~2017, IEnova ~~issued 183,970~~granted 1,034,086 RSUs from the IEnova 2013 Long-Term Incentive Plan, under which awards are cash settled at vesting based on the price of IEnova common stock.

We discuss share-based compensation plans and related awards further in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report.

CAPITALIZED FINANCING COSTS

Capitalized financing costs include capitalized interest costs and AFUDC related to both debt and equity financing of construction projects. We capitalize interest costs incurred to finance capital projects and interest on equity method investments that have not commenced planned principal operations.

Interest capitalized and AFUDC are as follows:



CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
Sempra Energy Consolidated	$	62	$	58	$	144	$	110
SDG&E	21		17		41		32
SoCalGas	15		14		30		27

~~The following table shows capitalized financing costs for the three months and six months ended June 30, 2016 and 2015.~~

CAPITALIZED FINANCING COSTS
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
Sempra Energy Consolidated:
    AFUDC related to debt $ 8 $ 7 $ 15 $ 13
    AFUDC related to equity 30 31 57 58
    Other capitalized interest 20 17 38 34
        Total Sempra Energy Consolidated $ 58 $ 55 $ 110 $ 105
SDG&E:
    AFUDC related to debt $ 4 $ 4 $ 8 $ 7
    AFUDC related to equity 13 10 24 18
        Total SDG&E $ 17 $ 14 $ 32 $ 25
SoCalGas:
    AFUDC related to debt $ 4 $ 3 $ 7 $ 6
    AFUDC related to equity 10 10 20 19
        Total SoCalGas $ 14 $ 13 $ 27 $ 25

COMPREHENSIVE INCOME

The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to noncontrolling interests:



CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
(Dollars in millions)
	Foreign currency translation adjustments			Financial instruments			Pension and other postretirement benefits			Total accumulated other comprehensive income (loss)
	Three months ended June 30, 2017 and 2016
Sempra Energy Consolidated:

Balance as of March 31, 2017	$	(481	)	$	(121	)	$	(94	)	$	(696	)
OCI before reclassifications	3			(26		)	—			(23		)
Amounts reclassified from AOCI	—			—			1			1
Net OCI	3			(26		)	1			(22		)
Balance as of June 30, 2017	$	(478	)	$	(147	)	$	(93	)	$	(718	)
							.
Balance as of March 31, 2016	$	(514	)	$	(221	)	$	(86	)	$	(821	)
OCI before reclassifications	11			(48		)	—			(37		)
Amounts reclassified from AOCI	—			5			1			6
Net OCI	11			(43		)	1			(31		)
Balance as of June 30, 2016	$	(503	)	$	(264	)	$	(85	)	$	(852	)
SDG&E:

Balance as of March 31, 2017 and June 30, 2017							$	(8	)	$	(8	)

Balance as of March 31, 2016 and June 30, 2016							$	(8	)	$	(8	)
SoCalGas:

Balance as of March 31, 2017				$	(13	)	$	(9	)	$	(22	)
Amounts reclassified from AOCI				—			1			1
Net OCI				—			1			1
Balance as of June 30, 2017				$	(13	)	$	(8	)	$	(21	)

Balance as of March 31, 2016 and June 30, 2016				$	(14	)	$	(5	)	$	(19	)


(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)
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
Foreign Total
currency Pension and other accumulated other
translation Financial postretirement comprehensive
adjustments instruments benefits income (loss)
Three months ended June 30, 2016 and 2015
2016:
Balance as of March 31, 2016 $ (514) $ (221) $ (86) $ (821)
Other comprehensive income (loss) before
   reclassifications 11 (48) ― (37)
Amounts reclassified from accumulated other
   comprehensive income ― 5 1 6
Net other comprehensive income (loss) 11 (43) 1 (31)
Balance as of June 30, 2016 $ (503) $ (264) $ (85) $ (852)
2015:
Balance as of March 31, 2015 $ (384) $ (145) $ (84) $ (613)
Other comprehensive (loss) income before
   reclassifications (43) 57 ― 14
Amounts reclassified from accumulated other
   comprehensive income ― 2 1 3
Net other comprehensive (loss) income (43) 59 1 17
Balance as of June 30, 2015 $ (427) $ (86) $ (83) $ (596)

Six months ended June 30, 2016 and 2015
2016:
Balance as of December 31, 2015 $ (582) $ (137) $ (87) $ (806)
Other comprehensive income (loss) before
   reclassifications 79 (130) ― (51)
Amounts reclassified from accumulated other
   comprehensive income ― 3 2 5
Net other comprehensive income (loss) 79 (127) 2 (46)
Balance as of June 30, 2016 $ (503) $ (264) $ (85) $ (852)
2015: .
Balance as of December 31, 2014 $ (322) $ (90) $ (85) $ (497)
Other comprehensive (loss) income before
   reclassifications (105) 3 ― (102)
Amounts reclassified from accumulated other
   comprehensive income ― 1 2 3
Net other comprehensive (loss) income (105) 4 2 (99)
Balance as of June 30, 2015 $ (427) $ (86) $ (83) $ (596)
(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)
(Dollars in millions)
	Foreign currency translation adjustments			Financial instruments			Pension and other postretirement benefits			Total accumulated other comprehensive income (loss)
	Six months ended June 30, 2017 and 2016
Sempra Energy Consolidated:

Balance as of December 31, 2016	$	(527	)	$	(125	)	$	(96	)	$	(748	)
OCI before reclassifications	49			(28		)	—			21
Amounts reclassified from AOCI	—			6			3			9
Net OCI	49			(22		)	3			30
Balance as of June 30, 2017	$	(478	)	$	(147	)	$	(93	)	$	(718	)
							.
Balance as of December 31, 2015	$	(582	)	$	(137	)	$	(87	)	$	(806	)
OCI before reclassifications	79			(130		)	—			(51		)
Amounts reclassified from AOCI	—			3			2			5
Net OCI	79			(127		)	2			(46		)
Balance as of June 30, 2016	$	(503	)	$	(264	)	$	(85	)	$	(852	)
SDG&E:

Balance as of December 31, 2016 and June 30, 2017							$	(8	)	$	(8	)

Balance as of December 31, 2015 and June 30, 2016							$	(8	)	$	(8	)
SoCalGas:

Balance as of December 31, 2016				$	(13	)	$	(9	)	$	(22	)
Amounts reclassified from AOCI				—			1			1
Net OCI				—			1			1
Balance as of June 30, 2017				$	(13	)	$	(8	)	$	(21	)

Balance as of December 31, 2015 and June 30, 2016				$	(14	)	$	(5	)	$	(19	)


(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)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)						Affected line item on Condensed Consolidated Statements of Operations
	Three months ended June 30,
	2017			2016
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments	$	(1	)	$	3		Interest Expense
Interest rate instruments	2			2			Equity Earnings (Losses), Before Income Tax
Interest rate and foreign exchange instruments	3			5			Equity Earnings (Losses), Net of Income Tax
Foreign exchange instruments	(1		)	—			Revenues: Energy-Related Businesses
Total before income tax	3			10
	(1		)	(1		)	Income Tax (Expense) Benefit
Net of income tax	2			9
	(2		)	(4		)	Losses (Earnings) Attributable to Noncontrolling Interests
	$	—		$	5
Pension and other postretirement benefits:
Amortization of actuarial loss	$	2		$	2		See note (1) below
	(1		)	(1		)	Income Tax (Expense) Benefit
Net of income tax	$	1		$	1

Total reclassifications for the period, net of tax	$	1		$	6
SDG&E:
Financial instruments:
Interest rate instruments	$	3		$	3		Interest Expense
	(3		)	(3		)	(Earnings) Losses Attributable to Noncontrolling Interest
Total reclassifications for the period	$	—		$	—
SoCalGas:
Pension and other postretirement benefits:
Amortization of actuarial loss	$	1		$	—		See note (1) below
Total reclassifications for the period, net of tax	$	1		$	—


(1)	Amounts are included in the computation of net periodic benefit cost (see “Pension and Other Postretirement Benefits” above).

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Amounts reclassified
Details about accumulated from accumulated other Affected line item on Condensed
other comprehensive income (loss) components comprehensive income (loss) Consolidated Statements of Operations
Three months ended June 30,
2016 2015
Sempra Energy Consolidated:
Financial instruments:
    Interest rate and foreign exchange instruments $ 3 $ 3 Interest Expense
    Interest rate instruments 2 3 Equity Earnings (Losses), Before Income Tax
    Interest rate and foreign exchange instruments 5 ― Equity Earnings, Net of Income Tax
Total before income tax 10 6
(1) (1) Income Tax Expense
Net of income tax 9 5
(4) (3) Earnings Attributable to Noncontrolling Interests
$ 5 $ 2

Pension and other postretirement benefits:
    Amortization of actuarial loss $ 2 $ 2 See note (1) below
(1) (1) Income Tax Expense
Net of income tax $ 1 $ 1

Total reclassifications for the period, net of tax $ 6 $ 3
SDG&E:
Financial instruments:
    Interest rate instruments $ 3 $ 3 Interest Expense
(3) (3) Losses (Earnings) Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax $ ― $ ―
(1) Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Amount reclassified
Details about accumulated from accumulated other Affected line item on Condensed
other comprehensive income (loss) components comprehensive income (loss) Consolidated Statements of Operations
Six months ended June 30,
2016 2015
Sempra Energy Consolidated:
Financial instruments:
    Interest rate and foreign exchange instruments $ 7 $ 9 Interest Expense
    Interest rate instruments 5 6 Equity Earnings (Losses), Before Income Tax
    Interest rate and foreign exchange instruments 6 ― Equity Earnings, Net of Income Tax
    Commodity contracts not subject to
rate recovery (7) (7) Revenues: Energy-Related Businesses
Total before income tax 11 8
(1) ― Income Tax Expense
Net of income tax 10 8
(7) (7) Earnings Attributable to Noncontrolling Interests
$ 3 $ 1

Pension and other postretirement benefits:
    Amortization of actuarial loss $ 4 $ 4 See note (1) below
(2) (2) Income Tax Expense
Net of income tax $ 2 $ 2

Total reclassifications for the period, net of tax $ 5 $ 3
SDG&E:
Financial instruments:
    Interest rate instruments $ 6 $ 6 Interest Expense
(6) (6) Losses (Earnings) Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax $ ― $ ―
(1) Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).

For the three months and six months ended June 30, 2016 and 2015, Other Comprehensive Income (Loss) (OCI), excluding amounts attributable to noncontrolling interests, at SDG&E and SoCalGas was negligible, and reclassifications out of AOCI to Net Income were also negligible for SoCalGas.



RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)						Affected line item on Condensed Consolidated Statements of Operations
	Six months ended June 30,
	2017			2016
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments	$	(4	)	$	7		Interest Expense
Interest rate instruments	4			5			Equity Earnings (Losses), Before Income Tax
Interest rate and foreign exchange instruments	5			6			Equity Earnings (Losses), Net of Income Tax
Foreign exchange instruments	1			—			Revenues: Energy-Related Businesses
Commodity contracts not subject to rate recovery	9			(7		)	Revenues: Energy-Related Businesses
Total before income tax	15			11
	(5		)	(1		)	Income Tax (Expense) Benefit
Net of income tax	10			10
	(4		)	(7		)	Losses (Earnings) Attributable to Noncontrolling Interests
	$	6		$	3
Pension and other postretirement benefits:
Amortization of actuarial loss	$	5		$	4		See note (1) below
	(2		)	(2		)	Income Tax (Expense) Benefit
Net of income tax	$	3		$	2

Total reclassifications for the period, net of tax	$	9		$	5
SDG&E:
Financial instruments:
Interest rate instruments	$	6		$	6		Interest Expense
	(6		)	(6		)	(Earnings) Losses Attributable to Noncontrolling Interest
Total reclassifications for the period	$	—		$	—
SoCalGas:
Pension and other postretirement benefits:
Amortization of actuarial loss	$	1		$	—		See note (1) below
Total reclassifications for the period, net of tax	$	1		$	—


(1)	Amounts are included in the computation of net periodic benefit cost (see “Pension and Other Postretirement Benefits” above).

~~SHAREHOLDERS'~~

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following tables provide reconciliations of changes in Sempra ~~Energy's~~Energy’s, SDG&E’s and ~~SDG&E's shareholders'~~SoCalGas’ shareholders’ equity and noncontrolling interests for the six months ended June 30, ~~2016~~2017 and ~~2015.~~2016.



SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Sempra Energy shareholders’ equity(1)			Non- controlling interests(2)			Total equity(1)
Balance at December 31, 2016	$	12,951		$	2,290		$	15,241
Comprehensive income	731			8			739
Preferred dividends of subsidiary	(1		)	—			(1		)
Share-based compensation expense	23			—			23
Common stock dividends declared	(413		)	—			(413		)
Issuances of common stock	55			—			55
Repurchases of common stock	(14		)	—			(14		)
Equity contributed by noncontrolling interest	—			1			1
Distributions to noncontrolling interests	—			(26		)	(26		)
Balance at June 30, 2017	$	13,332		$	2,273		$	15,605
Balance at December 31, 2015	$	11,809		$	770		$	12,579
Cumulative-effect adjustment from change in accounting principle	107			—			107
Comprehensive income	324			22			346
Preferred dividends of subsidiary	(1		)	—			(1		)
Share-based compensation expense	24			—			24
Common stock dividends declared	(377		)	—			(377		)
Issuances of common stock	56			—			56
Repurchases of common stock	(54		)	—			(54		)
Equity contributed by noncontrolling interest	—			1			1
Distributions to noncontrolling interests	—			(11		)	(11		)
Balance at June 30, 2016	$	11,888		$	782		$	12,670

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
Sempra Energy Non-
shareholders' controlling Total
equity interests(1) equity
Balance at December 31, 2015 $ 11,809 $ 770 $ 12,579
Comprehensive income 290 22 312
Preferred dividends of subsidiary (1) ― (1)
Share-based compensation expense 24 ― 24
Common stock dividends declared (377) ― (377)
Issuances of common stock 56 ― 56
Repurchases of common stock (54) ― (54)
Tax benefit related to share-based compensation 34 ― 34
Equity contributed by noncontrolling interest ― 1 1
Distributions to noncontrolling interests ― (11) (11)
Balance at June 30, 2016 $ 11,781 $ 782 $ 12,563
Balance at December 31, 2014 $ 11,326 $ 774 $ 12,100
Comprehensive income 634 33 667
Preferred dividends of subsidiary (1) ― (1)
Share-based compensation expense 26 ― 26
Common stock dividends declared (347) ― (347)
Issuances of common stock 59 ― 59
Repurchases of common stock (66) ― (66)
Tax benefit related to share-based compensation 52 ― 52
Equity contributed by noncontrolling interest ― 1 1
Distributions to noncontrolling interests ― (16) (16)
Balance at June 30, 2015 $ 11,683 $ 792 $ 12,475
(1) Noncontrolling interests include the preferred stock of SoCalGas and other noncontrolling interests as listed in the table below under "Other Noncontrolling Interests."


(1)	Amounts for the six months ended June 30, 2016 reflect the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.


(2)	Noncontrolling interests include the preferred stock of SoCalGas and other noncontrolling interests as listed in the table below under “Other Noncontrolling Interests.”



SHAREHOLDER’S EQUITY AND NONCONTROLLING INTEREST – SDG&E
(Dollars in millions)
	SDG&E shareholder’s equity(1)			Non- controlling interest			Total equity(1)
Balance at December 31, 2016	$	5,641		$	37		$	5,678
Comprehensive income	304			10			314
Common stock dividends declared	(175		)	—			(175		)
Equity contributed by noncontrolling interest	—			1			1
Distributions to noncontrolling interest	—			(14		)	(14		)
Balance at June 30, 2017	$	5,770		$	34		$	5,804
Balance at December 31, 2015	$	5,223		$	53		$	5,276
Cumulative-effect adjustment from change in accounting principle	23			—			23
Comprehensive income (loss)	236			(13		)	223
Common stock dividends declared	(175		)	—			(175		)
Distributions to noncontrolling interest	—			(3		)	(3		)
Balance at June 30, 2016	$	5,307		$	37		$	5,344

SHAREHOLDER'S EQUITY AND NONCONTROLLING INTEREST – SDG&E
(Dollars in millions)
SDG&E Non-
shareholder's controlling Total
equity interest equity
Balance at December 31, 2015 $ 5,223 $ 53 $ 5,276
Comprehensive income (loss) 229 (13) 216
Common stock dividends declared (175) ― (175)
Distributions to noncontrolling interest ― (3) (3)
Balance at June 30, 2016 $ 5,277 $ 37 $ 5,314
Balance at December 31, 2014 $ 4,932 $ 60 $ 4,992
Comprehensive income 273 9 282
Distributions to noncontrolling interest ― (8) (8)
Balance at June 30, 2015 $ 5,205 $ 61 $ 5,266


(1)	Amounts for the six months ended June 30, 2016 reflect the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.

SHAREHOLDERS' EQUITY ― SOCALGAS
(Dollars in millions)
SoCalGas
shareholders'
equity
Balance at December 31, 2015 $ 3,149
Comprehensive income 195
Preferred stock dividends declared (1)
Balance at June 30, 2016 $ 3,343
Balance at December 31, 2014 $ 2,781
Comprehensive income 285
Preferred stock dividends declared (1)
Balance at June 30, 2015 $ 3,065



SHAREHOLDERS’ EQUITY – SOCALGAS
(Dollars in millions)
	Total equity(1)
Balance at December 31, 2016	$	3,510
Comprehensive income	263
Preferred stock dividends declared	(1		)
Balance at June 30, 2017	$	3,772
Balance at December 31, 2015	$	3,149
Cumulative-effect adjustment from change in accounting principle	15
Comprehensive income	199
Preferred stock dividends declared	(1		)
Balance at June 30, 2016	$	3,362


(1)	Amounts for the six months ended June 30, 2016 reflect the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.

Ownership interests that are held by owners other than Sempra Energy and SDG&E in subsidiaries or entities consolidated by them are accounted for and reported as noncontrolling interests. As a result, noncontrolling interests are reported as a separate component of equity on the Condensed Consolidated Balance Sheets. Earnings or losses attributable to noncontrolling interests are separately identified on the Condensed Consolidated Statements of Operations, and comprehensive income or loss attributable to noncontrolling interests is separately identified on the Condensed Consolidated Statements of Comprehensive Income (Loss).

Preferred Stock

~~At Sempra Energy, the~~The preferred stock ofat SoCalGas is presented at Sempra Energy as a noncontrolling ~~interest and preferred stock dividends are~~interest. Sempra Energy records charges against income related to noncontrolling ~~interests.~~interests for preferred stock dividends declared by SoCalGas. We provide additional information ~~concerning~~regarding preferred stock in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Noncontrolling Interests

At June 30, ~~2016~~2017 and December 31, ~~2015,~~2016, 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~~Energy’s Condensed Consolidated Balance Sheets:



OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
	Percent ownership held by noncontrolling interests				Equity held by noncontrolling interests
	June 30, 2017		December 31, 2016		June 30, 2017		December 31, 2016
SDG&E:
Otay Mesa VIE	100	%	100	%	$	34	$	37
Sempra South American Utilities:
Chilquinta Energía subsidiaries(1)	22.9 – 43.4		23.1 – 43.4		22		22
Luz del Sur	16.4		16.4		184		173
Tecsur S.A.	9.8		9.8		3		4
Sempra Mexico:
IEnova	33.6		33.6		1,514		1,524
Sempra Renewables:
Tax equity arrangement – wind(2)	NA		NA		91		92
Tax equity arrangement – solar(2)	NA		NA		363		376
Sempra LNG & Midstream:
Bay Gas	9.1		9.1		28		27
Liberty Gas Storage, LLC	23.3		23.3		13		14
Southern Gas Transmission Company	49.0		49.0		1		1
Total Sempra Energy					$	2,253	$	2,270

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
Percent ownership held by others
June 30, December 31, June 30, December 31,
2016 2015 2016 2015
SDG&E:
   Otay Mesa VIE 100 % 100 % $ 37 $ 53
Sempra South American Utilities:
   Chilquinta Energía subsidiaries(1) 23.2 – 43.4 23.5 – 43.4 21 21
   Luz del Sur 16.4 16.4 175 164
   Tecsur 9.8 9.8 4 4
Sempra Mexico:
   IEnova 18.9 18.9 484 468
Sempra Natural Gas:
   Bay Gas Storage Company, Ltd. 9.1 9.1 26 25
   Liberty Gas Storage, LLC 23.3 23.2 14 14
   Southern Gas Transmission Company 49.0 49.0 1 1
      Total Sempra Energy $ 762 $ 750
(1) Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.


(1)	Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.


(2)	Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

TRANSACTIONS WITH AFFILIATES

Amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas are as follows:

AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
June 30, 2016 December 31, 2015
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates - current $ 6 $ 6

Sempra South American Utilities(1):
    Eletrans S.A. and Eletrans II S.A.:
        4% Note(2) $ 79 $ 72
    Other related party receivables 2 ―
Sempra Mexico(1):
    Affiliate of joint venture with PEMEX:
        Note due November 13, 2017(3) 2 3
        Note due November 14, 2018(3) 43 42
        Note due November 14, 2018(3) 35 34
        Note due November 14, 2018(3) 8 8
    Energía Sierra Juárez:
        Note due June 15, 2018(4) 17 24
Sempra Natural Gas:
        Cameron LNG JV 6 3
    Total due from unconsolidated affiliates - noncurrent $ 192 $ 186

Total due to various unconsolidated affiliates - current $ (8) $ (14)
SDG&E:
Sempra Energy(5) $ 163 $ ―
Other affiliates ― 1
Total due from unconsolidated affiliates - current $ 163 $ 1

Sempra Energy $ ― $ (34)
SoCalGas (7) (13)
Other affiliates (183) (8)
    Total due to unconsolidated affiliates - current $ (190) $ (55)

Income taxes due from Sempra Energy(6) $ 59 $ 28
SoCalGas:
Sempra Energy(7) $ ― $ 35
SDG&E 7 13
    Total due from unconsolidated affiliates - current $ 7 $ 48

Sempra Energy $ (25) $ ―
    Total due to unconsolidated affiliate - current $ (25) $ ―

Income taxes due from Sempra Energy(6) $ 9 $ 1
(1) Amounts include principal balances plus accumulated interest outstanding.
(2)

U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans S.A. and Eletrans II S.A., both of which are joint ventures at Chilquinta Energía.
(3)

U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (4.97 percent at June 30, 2016), to finance the Los Ramones Norte pipeline project.
(4)

U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 637.5 basis points (6.84 percent at June 30, 2016), to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.
(5) At June 30, 2016, net receivable included outstanding advances to Sempra Energy of $172 million at an interest rate of 0.35 percent.
(6) 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 each company having always filed a separate return.
(7) At December 31, 2015, net receivable included outstanding advances to Sempra Energy of $50 million at an interest rate of 0.11 percent.



AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	June 30, 2017			December 31, 2016
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates – current	$	26		$	26

Sempra South American Utilities(1):
Eletrans – 4% Note(2)	$	90		$	96
Other related party receivables	1			1
Sempra Mexico(1):
IMG – Note due March 15, 2022(3)	177			—
Affiliate of joint venture with Ductos y Energéticos del Norte – Notes due November 14, 2018(4)	92			90
Energía Sierra Juárez – Note(5)	13			14
Total due from unconsolidated affiliates – noncurrent	$	373		$	201

Total due to various unconsolidated affiliates – current	$	(11	)	$	(11	)
SDG&E:
Sempra Energy(6)	$	—		$	3
SoCalGas	1			—
Various affiliates	1			1
Total due from various unconsolidated affiliates – current	$	2		$	4

Sempra Energy	$	(18	)	$	—
SoCalGas	—			(8		)
Various affiliates	(8		)	(7		)
Total due to various unconsolidated affiliates – current	$	(26	)	$	(15	)

Income taxes due from Sempra Energy(7)	$	132		$	159
SoCalGas:
Sempra Energy(8)	$	55		$	—
SDG&E	—			8
Various affiliates	1			—
Total due from unconsolidated affiliates – current	$	56		$	8

Sempra Energy	$	—		$	(28	)
SDG&E	(1		)	—
Total due to unconsolidated affiliates – current	$	(1	)	$	(28	)

Income taxes due from Sempra Energy(7)	$	6		$	5


(1)	Amounts include principal balances plus accumulated interest outstanding.


(2)	U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans, which includes, collectively, joint ventures of Chilquinta Energía.


(3)	Mexican peso-denominated revolving line of credit for up to $9.0 billion Mexican pesos or approximately $500 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 basis points (9.60 percent at June 30, 2017), to finance construction of the natural gas marine pipeline.


(4)	Four U.S. dollar-denominated loans, at variable interest rates based on the 30-day LIBOR plus 450 basis points (5.72 percent at June 30, 2017), to finance the Los Ramones Norte pipeline.


(5)	U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 basis points (7.60 percent at June 30, 2017) with no stated maturity date, to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.


(6)	At December 31, 2016, net receivable included outstanding advances to Sempra Energy of $31 million at an interest rate of 0.68 percent.


(7)	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 each company having always filed a separate return.


(8)	At June 30, 2017, net receivable included outstanding advances to Sempra Energy of $84 million at an interest rate of 1.23 percent.

Revenues and cost of sales from unconsolidated affiliates are as follows:



REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
Revenues:
Sempra Energy Consolidated	$	8	$	5	$	15	$	10
SDG&E	2		—		4		3
SoCalGas	17		18		35		35
Cost of Sales:
Sempra Energy Consolidated	$	14	$	20	$	28	$	50
SDG&E	19		16		39		30

REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
REVENUES
    Sempra Energy Consolidated $ 5 $ 8 $ 10 $ 16
    SDG&E ― 2 3 5
    SoCalGas 18 17 35 36
COST OF SALES
    Sempra Energy Consolidated $ 20 $ 30 $ 50 $ 49
    SDG&E 16 13 30 18

Guarantees

Sempra Energy has provided guarantees to certain of its solar and wind farm joint ventures, ~~and~~ entered into ~~completion~~ guarantees related to the financing of the Cameron LNG JV project and has provided guarantees to IMG, as we discuss ~~above~~ in Note 4 above and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

OTHER INCOME, NET

Other Income, Net on the Condensed Consolidated Statements of Operations consists of the following:



OTHER INCOME, NET
(Dollars in millions)
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
Sempra Energy Consolidated:
Allowance for equity funds used during construction	$	40		$	30		$	112		$	57
Investment gains(1)	14			10			30			20
Gains (losses) on interest rate and foreign exchange instruments, net	31			(15		)	94			(12		)
Foreign currency transaction gains (losses)	7			(5		)	17			(7		)
Electrical infrastructure relocation income(2)	—			2			—			3
Regulatory interest, net(3)	—			1			2			3
Sundry, net	(1		)	—			5			8
Total	$	91		$	23		$	260		$	72
SDG&E:
Allowance for equity funds used during construction	$	16		$	13		$	31		$	24
Regulatory interest, net(3)	—			1			2			3
Sundry, net	(1		)	(1		)	—			—
Total	$	15		$	13		$	33		$	27
SoCalGas:
Allowance for equity funds used during construction	$	11		$	10		$	22		$	20
Sundry, net	(2		)	(4		)	(2		)	(4		)
Total	$	9		$	6		$	20		$	16

OTHER INCOME, NET
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
Sempra Energy Consolidated:
Allowance for equity funds used during construction $ 30 $ 31 $ 57 $ 58
Investment gains (losses)(1) 10 (2) 20 7
Losses on interest rate and foreign exchange instruments, net (15) (3) (12) (3)
Foreign currency transaction losses (5) (2) (7) (3)
Sale of other investments 1 6 2 6
Electrical infrastructure relocation income(2) 2 4 3 4
Regulatory interest, net(3) 1 1 3 2
Sundry, net (1) 2 6 5
   Total $ 23 $ 37 $ 72 $ 76
SDG&E:
Allowance for equity funds used during construction $ 13 $ 10 $ 24 $ 18
Regulatory interest, net(3) 1 1 3 2
Sundry, net (1) (2) ― (2)
   Total $ 13 $ 9 $ 27 $ 18
SoCalGas:
Allowance for equity funds used during construction $ 10 $ 10 $ 20 $ 19
Sundry, net (4) (1) (4) (2)
   Total $ 6 $ 9 $ 16 $ 17
(1) Represents investment gains (losses) 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.


(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, recorded in Operation and Maintenance on the Condensed Consolidated Statements of Operations.


(2)	Income at Luz del Sur associated with the relocation of electrical infrastructure.


(3)	Interest on regulatory balancing accounts.

INCOME TAXES



INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Income tax expense		Effective income tax rate		Income tax (benefit) expense			Effective income tax rate
	Three months ended June 30,
	2017				2016
Sempra Energy Consolidated	$	167	40	%	$	(106	)	95	%
SDG&E	54		26		48			36
SoCalGas	19		24		(29		)	100

	Six months ended June 30,
	2017				2016(1)
Sempra Energy Consolidated	$	462	39	%	$	2		1	%
SDG&E	144		32		113			34
SoCalGas	117		31		54			21


(1)	Reflects the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
Income tax Effective Effective
(benefit) income Income tax income
expense tax rate expense tax rate
Three months ended June 30,
2016 2015
Sempra Energy Consolidated $ (106) 95 % $ 98 25 %
SDG&E 48 36 54 29
SoCalGas (29) 100 16 18
Six months ended June 30,
2016 2015
Sempra Energy Consolidated $ 36 10 % $ 261 26 %
SDG&E 120 36 142 34
SoCalGas 58 23 111 28

Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted is factored into the forecasted effective tax rate, and the impact is recognized proportionately over the year. Items that cannot be reliably forecasted (e.g., ~~resolution of prior years' income tax items,~~foreign currency translation and inflation adjustments, remeasurement of deferred tax asset valuation allowances, ~~Mexican currency translation and inflation adjustments, deferred~~ income tax ~~benefits~~expense or benefit associated with the gain or loss on sale or impairment of a book investment, resolution of prior years’ income tax items, and certain impacts of regulatory ~~matters)~~matters) are recorded in the interim period in which they actually occur, which can result in variability in the effective income tax rate.

~~Sempra Energy Consolidated~~

The income tax benefit in the three months ended June 30, 2016 compared to income tax expense in the same period in 2015 was due to a pretax loss in the period in 2016. The pretax loss includes the charges associated with prior years' tax repairs deductions as a result of the 2016 General Rate Case Final Decision (GRC FD) issued by the CPUC in June 2016 affecting the California Utilities and losses from the permanent release of pipeline capacity at Sempra Natural Gas, as we discuss in Notes 10 and 11, respectively. Pretax income in 2015 included the gain from the sale of the Mesquite Power plant discussed in Note 3. Items affecting the effective income tax rate in 2016 include

§	~~higher flow-through items as a percentage of pretax loss;~~

§	~~higher income tax benefit from foreign currency translation and inflation adjustments; and~~

§	~~lower U.S. income tax expense as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries.~~

The decrease in income tax expense in the six months ended June 30, 2016 compared to the same period in 2015 was due to lower pretax income, as we discuss for the second quarter above, and a lower effective income tax rate, primarily due to:

§	~~higher flow-through items as a percentage of pretax income in 2016; and~~

§	~~higher income tax benefit in 2016 from foreign currency translation and inflation adjustments;~~ ~~offset by~~

§	~~$32 million deferred Mexican income tax expense in 2016 on our basis difference in TdM as a result of management's decision to hold the asset for sale. We discuss the planned sale further in Note 3.~~

~~SDG&E~~

The decrease in SDG&E's income tax expense in the three and six months ended June 30, 2016 compared to the same periods in 2015 was primarily due to lower pretax income, offset by a higher effective income tax rate. Pretax income in 2016 includes the charges associated with prior years' tax repairs deductions as a result of the 2016 GRC FD. The higher effective income tax rate was primarily due to:

§	~~favorable resolution of prior years' income tax items in 2015; and~~

§	~~Otay Mesa VIE's pretax loss in 2016 compared to pretax income in 2015, which is excluded from SDG&E's and Sempra Energy Consolidated's taxable income;~~ ~~offset by~~

§	~~higher flow-through items as a percentage of pretax income in 2016.~~

~~SoCalGas~~

SoCalGas' income tax benefit in the three months ended June 30, 2016 compared to income tax expense in the same period in 2015 was due to a pretax loss in the period in 2016. The pretax loss includes the charges associated with prior years' tax repairs deductions as a result of the 2016 GRC FD. In addition, the effective income tax rate in 2016 was affected by higher flow-through items as a percentage of pretax loss.

The decrease in SoCalGas' income tax expense in the six months ended June 30, 2016 compared to the same period in 2015 was primarily due to lower pretax income, as discussed for the second quarter above, and a lower effective income tax rate. The lower effective income tax rate was primarily due to higher flow-through items as a percentage of pretax income in 2016.

The 2016 GRC FD requires the establishment of a two-way income tax expense memorandum account for SDG&E and SoCalGas to track any revenue variances resulting from differences between the income tax expense forecasted in the GRC and the income tax expense incurred from 2016 through 2018. The variances to be tracked include tax expense differences relating to

§	~~net revenue changes,~~

§	~~mandatory tax law, tax accounting, tax procedural, or tax policy changes, and~~

§	~~elective tax law, tax accounting, tax procedural, or tax policy changes.~~

The account will remain open, and the balance in the account will be reviewed in subsequent GRC proceedings, until the CPUC decides to close the account. We believe the future disposition of these tracked balances may result in refunds being directed to ratepayers to the extent tax expense incurred is lower than forecasted tax expense as a result of certain flow-through item deductions (see description below) exceeding the amounts forecasted in the GRC process. In the second quarter of 2016, SoCalGas recorded a $9 million after-tax charge ($15 million pretax) and SDG&E recorded a negligible amount to earnings for the differences in the income tax expense forecasted in the GRC proceedings and the income tax expense that SDG&E and SoCalGas incurred for the six-month period ended June 30, 2016. We discuss the memo account further in Note 10.

~~Although the 2016 GRC FD requires the tracking described above for~~For SDG&E and SoCalGas, the ~~California Public Utilities Commission (CPUC) continues to require~~CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the current effective income tax rate. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the effective income tax rate. The following items are subject to flow-through treatment:

§
▪	repairs expenditures related to a certain portion of utility plant assets

§
▪	the equity portion of AFUDC

§
▪	a portion of the cost of removal of utility plant assets

§
▪	utility self-developed software expenditures

§
▪	depreciation on a certain portion of utility plant assets

§
▪	state income taxes

Differences arising from the forecasted amounts for these flow-through items will be tracked in the two-way income tax expense tracking account described above, except for the equity portion of AFUDC, which is not subject to taxation. We expect that amounts recorded in the tracking account may give rise to regulatory liabilities until the CPUC disposes with the account.

The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico ~~is also subject~~has similar flow-through treatment.

As we discuss in Note 10 below and in Notes 6 and 14 of the Notes to ~~flow-through treatment.~~Consolidated Financial Statements in the Annual Report, the 2016 GRC FD issued by the CPUC in June 2016 required SDG&E and SoCalGas to each establish a two-way income tax expense memorandum account to track certain revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred from 2016 through 2018. The tracking accounts will remain open, and the balance in the accounts will be reviewed in subsequent GRC proceedings, until the CPUC decides to close them. We expect that certain amounts recorded in the tracking accounts may give rise to regulatory assets or liabilities.

In the three months and six months ended June 30, 2017, we recorded $52 million ($34 million after noncontrolling interests) and $149 million ($99 million after noncontrolling interests), respectively, of income tax expense from the transactional effects of foreign currency and inflation as a result of significant appreciation of the Mexican peso. Such effects were partially mitigated by net gains of $32 million ($19 million after-tax) and $97 million ($58 million after-tax), respectively, recorded in Other Income, Net, on the Condensed Consolidated Statements of Operations, from foreign currency derivatives that are hedging Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova.

We provide additional information about our accounting for income taxes in Notes 1 and 6 of the Notes to Consolidated Financial Statements in the Annual Report.

NOTE 6. DEBT AND CREDIT FACILITIES

LINES OF CREDIT

At June 30, ~~2016,~~2017, Sempra Energy Consolidated had an aggregate of ~~$4.2~~$4.3 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~~paper. The principal terms of these committed lines of credit, which ~~we describe below.~~expire in October 2020, are described below and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report. Available unused credit on these lines at June 30, ~~2016~~2017 was approximately ~~$2.5~~$3.1 billion. Our foreign operations have additional general purpose credit facilities aggregating ~~$1.1~~$1.7 billion at June 30, ~~2016.~~2017. Available unused credit on these lines totaled ~~$843 million~~$1 billion at June 30, ~~2016.~~2017.



PRIMARY U.S. COMMITTED LINES OF CREDIT
(Dollars in millions)
		At June 30, 2017
		Total facility			Commercial paper outstanding(4)			Available unused credit
Sempra Energy(1)		$	1,000		$	—		$	1,000
Sempra Global(2)		2,335			(1,236		)	1,099
California Utilities(3):
	SDG&E	750			(5		)	745
	SoCalGas	750			—			750
	Less: combined limit of $1 billion for both utilities	(500		)	—			(500		)
		1,000			(5		)	995
Total		$	4,335		$	(1,241	)	$	3,094

~~Sempra Energy~~

Sempra Energy has a $1 billion, five-year syndicated revolving credit agreement expiring in October 2020. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share.

Borrowings bear interest at benchmark rates plus a margin that varies with 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 June 30, 2016, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.(1) The facility also provides for issuance of up to $400 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 June 30, 2016, Sempra Energy had no outstanding borrowings or~~ No letters of credit ~~supported by the facility.~~were outstanding at June 30, 2017.

~~Sempra Global~~

Sempra Global has a $2.21 billion, five-year syndicated revolving credit agreement expiring in October 2020. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share.

(2) Sempra Energy guarantees Sempra ~~Global's~~Global’s obligations under the credit facility. ~~Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy's credit ratings.~~

(3) 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 June 30, 2016, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.

~~At June 30, 2016, Sempra Global had $1.6 billion of commercial paper outstanding supported by the facility and $643 million of available unused credit on the line.~~

~~California Utilities~~

SDG&E and SoCalGas have a combined $1 billion, five-year syndicated revolving credit agreement expiring in October 2020. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $750 million, subject to a combined limit of $1 billion 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 $250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at June 30, 2017.

~~Borrowings bear interest at benchmark rates plus~~(4) Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a ~~margin that varies with~~reduction to the ~~borrowing utility's credit rating. The agreement requires each utility to~~available unused credit.

Sempra Energy, SDG&E and SoCalGas must maintain a ratio of ~~total~~ indebtedness to total capitalization (as defined in ~~the~~each agreement) of no more than 65 percent at the end of each quarter. ~~At June 30, 2016, the California Utilities were~~Each entity is in compliance with this and all other financial covenants under ~~the~~its respective 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 June 30, 2016, SDG&E had $54 million of commercial paper outstanding and SoCalGas had no outstanding borrowings supported by the facility. Available unused credit on the line~~facility at June 30, ~~2016 was $696 million and $750 million at SDG&E and SoCalGas, respectively, subject to the $1 billion maximum combined credit limit.~~

2017.



CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO
(U.S. dollar-equivalent in millions)
			At June 30, 2017
		Denominated in	Total facility		Amount outstanding				Available unused credit
Sempra South American Utilities(1):
	Peru(2)	Peruvian sol	$	379	$	(147	)	(3)	$	232
	Chile	Chilean peso	115		—				115
Sempra Mexico:
	IEnova(4)	U.S. dollar	1,170		(516		)		654
Total			$	1,664	$	(663	)		$	1,001

~~Sempra South American Utilities~~

~~Sempra South American Utilities has Peruvian Sol- and Chilean Peso-denominated credit facilities aggregating $547 million U.S. dollar equivalent, expiring between 2016 and 2018.~~(1) The credit facilities were entered into to finance working capital and for general corporate ~~purposes.~~purposes and expire between 2017 and 2020.

(2) The Peruvian facilities require a debt to equity ratio of no more than 170 ~~percent. At~~percent, with which we were in compliance at June 30, 2016, Sempra South American Utilities was in compliance with this financial covenant under the credit facilities. At June 30, 2016, Sempra South American Utilities had outstanding borrowings of $167 million and2017.

(3) Includes bank guarantees of ~~$16 million against the Peruvian facilities, and $252 million of available unused credit. There were no outstanding borrowings at June 30, 2016 under the $112 million Chilean facility.~~$4 million.

~~Sempra Mexico~~

~~IEnova has a $600 million, five-year revolving credit agreement~~(4) Five-year revolver expiring in August 2020. The lenders are Banco Santander (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander México, Banco Nacional de Mexico, S.A. Integrante del Grupo Financiero Banamex, The Bank2020 with a syndicate of Tokyo - Mitsubishi UFJ, LTD., The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation. At June 30, 2016, IEnova had $121 million of outstanding borrowings supported by the facility, and available unused credit on the line was $479 million.eight lenders.

WEIGHTED AVERAGE INTEREST RATES

~~The weighted average interest rates on the total short-term debt at Sempra Energy Consolidated were 1.21 percent and 1.09 percent at June 30, 2016 and December 31, 2015, respectively.~~ The weighted average interest rates on total short-term debt at ~~SDG&E~~Sempra Energy Consolidated were ~~1.06~~1.81 percent and ~~1.01~~1.51 percent at June 30, ~~2016~~2017 and December 31, ~~2015,~~2016, respectively.

The weighted average interest rate on total short-term debt at SDG&E was 1.15 percent at June 30, 2017. At December 31, 2016, the weighted average interest rate on total short-term debt at SoCalGas was 0.75 percent.

LONG-TERM DEBT

~~SDG&E~~Sempra Energy

In ~~May 2016, SDG&E~~June 2017, Sempra Energy publicly offered and sold ~~$500~~$750 million of ~~2.50-percent first mortgage bonds~~3.25-percent, fixed rate notes maturing in 2026. SDG&E used the proceeds from the offering to redeem, prior to a scheduled maturity in 2027, $105 million aggregate principal amount of 5-percent tax-exempt industrial development revenue bonds, to repay outstanding commercial paper and for other general corporate purposes.

~~SoCalGas~~

~~In June 2016, SoCalGas publicly offered and sold $500 million of 2.60-percent first mortgage bonds maturing in 2026. SoCalGas~~2027. Sempra Energy used the proceeds from the offering to repay outstanding commercial ~~paper~~paper.

SDG&E

In June 2017, SDG&E publicly offered and ~~for other general~~sold $400 million of 3.75-percent, first mortgage bonds maturing in 2047. SDG&E used the proceeds from the offering to repay outstanding commercial paper.

In 2015, SDG&E entered into a CPUC-approved 25-year PPA with a peaker plant facility. Construction of the peaker plant facility was completed and delivery of contracted power commenced in June 2017, at which time we recorded a $500 million capital lease obligation on SDG&E’s and Sempra Energy’s Condensed Consolidated Balance Sheets. We discuss commitments related to this capital lease obligation in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra South American Utilities

In February 2017, Luz del Sur publicly offered and sold $50 million of corporate ~~purposes.~~

bonds at 6.38 percent, maturing in 2023.

INTEREST RATE SWAPS

We discuss our fair value interest rate swaps and interest rate swaps to hedge cash flows in Note 7.

NOTE 7. 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, benchmark interest rate risk and foreign exchange rate exposures. 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 included in the tables below.

In certain cases, we apply the normal purchase or sale exception to derivative instruments 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.

In all other cases, we record derivatives at fair value on the Condensed Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (loss) (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Condensed Consolidated Statements of Cash Flows.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with 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 the future cash flows of a given 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, as follows:

▪

The California Utilities use ~~energy derivatives, both~~ natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Condensed Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.

▪

SDG&E is allocated and may purchase ~~congestion revenue rights (CRRs),~~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, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.

▪

Sempra Mexico, Sempra ~~Natural Gas,~~LNG & Midstream, and Sempra Renewables may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: ~~liquefied natural gas (LNG),~~LNG, natural gas transportation and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico may also ~~uses~~use 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 Condensed Consolidated Statements of Operations.

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 Condensed Consolidated Statements of Operations.

§
▪	From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel.

We summarize net energy derivative volumes at June 30, ~~2016~~2017 and December 31, ~~2015~~2016 as follows:



NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
Commodity	Unit of measure	June 30, 2017	December 31, 2016
California Utilities:
SDG&E:
Natural gas	MMBtu	44	48
Electricity	MWh	4	4
Congestion revenue rights	MWh	42	48
SoCalGas – natural gas	MMBtu	—	1

Energy-Related Businesses:
Sempra LNG & Midstream – natural gas	MMBtu	14	31
Sempra Mexico – natural gas	MMBtu	3	—

NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
June 30, December 31,
Segment and Commodity Unit of measure 2016 2015
California Utilities:
    SDG&E:
        Natural gas MMBtu(1) 72 70
        Electricity MWh(2) 1 1
        Congestion revenue rights MWh 30 36
    SoCalGas – natural gas MMBtu ― 1

Energy-Related Businesses:
   Sempra Natural Gas – natural gas MMBtu 30 43
(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 contractual obligations and assets, 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. WeThe California Utilities, as well as other Sempra Energy subsidiaries and joint ventures, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We may 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 and joint ventures. Interest rate derivatives are generally accounted for as hedges, and 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 energy derivatives. Separately, Otay Mesa VIE has entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes.

At June 30, ~~2016~~2017 and December 31, ~~2015,~~2016, the net notional amounts of our interest rate derivatives, excluding joint ventures, ~~and cross-currency derivatives discussed below,~~ were:



INTEREST RATE DERIVATIVES
(Dollars in millions)
	June 30, 2017			December 31, 2016
	Notional debt		Maturities	Notional debt		Maturities
Sempra Energy Consolidated:
Cash flow hedges(1)	$	897	2017-2032	$	924	2017-2032
SDG&E:
Cash flow hedges(1)	300		2017-2019	305		2017-2019

INTEREST RATE DERIVATIVES
(Dollars in millions)
June 30, 2016 December 31, 2015
Notional debt Maturities Notional debt Maturities
Sempra Energy Consolidated:
    Cash flow hedges(1) $ 377 2016-2028 $ 384 2016-2028
    Fair value hedges ― ― 300 2016
SDG&E:
    Cash flow hedge(1) 310 2016-2019 315 2016-2019
(1) Includes Otay Mesa VIE. All of SDG&E's interest rate derivatives relate to Otay Mesa VIE.


(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

FOREIGN CURRENCY DERIVATIVES

We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures. These cash flow hedges exchange our ~~Mexican-peso denominated~~Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. From time to time, Sempra Mexico and its joint ventures may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar.

We are also exposed to exchange rate movements at our Mexican subsidiaries and joint ventures, which have U.S. ~~dollar denominated~~dollar-denominated cash balances, receivables, payables and debt (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 denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these ~~impacts. In January 2016,~~impacts, however we ~~entered into foreign currency derivatives with a notional amount totaling $550 million.~~

~~At June 30, 2016~~generally do not hedge our deferred income tax assets and ~~December 31, 2015, the net notional amounts of our foreign currency derivatives, excluding joint ventures, were:~~liabilities or inflation.

FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
June 30, 2016 December 31, 2015
Notional debt Maturities Notional debt Maturities
Sempra Mexico:
Cross-currency swaps $ 408 2018-2023 $ 408 2018-2023
Other foreign currency derivatives 550 2016 ― ―

In addition, Sempra South American Utilities ~~uses~~and its joint ventures use foreign currency derivatives ~~at its subsidiaries and joint ventures as a means~~ to manage foreign currency rate risk. We discuss ~~such swaps~~these derivatives at Chilquinta Energí~~a's~~a’s Eletrans joint venture investment in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

At June 30, 2017 and December 31, 2016, the net notional amounts of our foreign currency derivatives, excluding joint ventures, were:



FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	June 30, 2017			December 31, 2016
	Notional amount		Maturities	Notional amount		Maturities
Sempra Energy Consolidated:
Cross-currency swaps	$	408	2017-2023	$	408	2017-2023
Other foreign currency derivatives(1)	903		2017-2018	86		2017-2018


(1)	In the first quarter of 2017, we entered into foreign currency derivatives with notional amounts totaling $850 million that expire in December 2017.

FINANCIAL STATEMENT PRESENTATION

The Condensed Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Condensed Consolidated Balance Sheets at June 30, ~~2016~~2017 and December 31, ~~2015,~~2016, 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 CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	June 30, 2017
	Current assets: Fixed-price contracts and other derivatives(1)			Other assets: Sundry			Current liabilities: Fixed-price contracts and other derivatives(2)			Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)	$	1		$	—		$	(56	)	$	(153	)
Derivatives not designated as hedging instruments:
Foreign exchange instruments	130			—			—			—
Commodity contracts not subject to rate recovery	43			8			(33		)	(5		)
Associated offsetting commodity contracts	(29		)	(3		)	29			3
Commodity contracts subject to rate recovery	15			71			(59		)	(147		)
Associated offsetting commodity contracts	(1		)	—			1			—
Associated offsetting cash collateral	—			—			15			10
Net amounts presented on the balance sheet	159			76			(103		)	(292		)
Additional cash collateral for commodity contracts not subject to rate recovery	10			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	17			—			—			—
Total(4)	$	186		$	76		$	(103	)	$	(292	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)	$	—		$	—		$	(13	)	$	(7	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	14			71			(58		)	(147		)
Associated offsetting commodity contracts	(1		)	—			1			—
Associated offsetting cash collateral	—			—			15			10
Net amounts presented on the balance sheet	13			71			(55		)	(144		)
Additional cash collateral for commodity contracts subject to rate recovery	16			—			—			—
Total(4)	$	29		$	71		$	(55	)	$	(144	)
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	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	1			—			—			—
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 CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
June 30, 2016
Deferred
credits
Current Current and other
assets: liabilities: liabilities:
Fixed-price Fixed-price Fixed-price
contracts 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) $ 1 $ ― $ (15) $ (184)
    Commodity contracts not subject to rate recovery ― ― (5) ―
Derivatives not designated as hedging instruments:
    Interest rate and foreign exchange instruments ― ― (12) ―
    Commodity contracts not subject to rate recovery 208 22 (227) (17)
        Associated offsetting commodity contracts (199) (13) 199 13
        Associated offsetting cash collateral ― ― 30 1
    Commodity contracts subject to rate recovery 18 52 (35) (48)
        Associated offsetting commodity contracts (4) (2) 4 2
        Associated offsetting cash collateral ― ― 13 15
    Net amounts presented on the balance sheet 24 59 (48) (218)
    Additional cash collateral for commodity contracts
        not subject to rate recovery 14 ― ― ―
    Additional cash collateral for commodity contracts
        subject to rate recovery 27 ― ― ―
    Total(4) $ 65 $ 59 $ (48) $ (218)
SDG&E:
Derivatives designated as hedging instruments:
    Interest rate instruments(3) $ ― $ ― $ (14) $ (23)
Derivatives not designated as hedging instruments:
    Commodity contracts subject to rate recovery 16 52 (32) (48)
        Associated offsetting commodity contracts (3) (2) 3 2
        Associated offsetting cash collateral ― ― 12 15
    Net amounts presented on the balance sheet 13 50 (31) (54)
    Additional cash collateral for commodity contracts
        subject to rate recovery 26 ― ― ―
    Total(4) $ 39 $ 50 $ (31) $ (54)
SoCalGas:
Derivatives not designated as hedging instruments:
    Commodity contracts not subject to rate recovery $ ― $ ― $ (1) $ ―
        Associated offsetting cash collateral ― ― 1 ―
    Commodity contracts subject to rate recovery 2 ― (3) ―
        Associated offsetting commodity contracts (1) ― 1 ―
        Associated offsetting cash collateral ― ― 1 ―
    Net amounts presented on the balance sheet 1 ― (1) ―
    Additional cash collateral for commodity contracts
        not subject to rate recovery 1 ― ― ―
    Additional cash collateral for commodity contracts
        subject to rate recovery 1 ― ― ―
    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 CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
December 31, 2015
Deferred
credits
Current Current and other
assets: liabilities: liabilities:
Fixed-price Fixed-price Fixed-price
contracts 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) $ 4 $ 1 $ (15) $ (156)
    Commodity contracts not subject to rate recovery 13 ― ― ―
Derivatives not designated as hedging instruments:
    Commodity contracts not subject to rate recovery 245 32 (239) (21)
        Associated offsetting commodity contracts (232) (20) 232 20
        Associated offsetting cash collateral (6) ― 4 ―
    Commodity contracts subject to rate recovery 28 49 (61) (64)
        Associated offsetting commodity contracts (2) (2) 2 2
        Associated offsetting cash collateral ― ― 28 26
    Net amounts presented on the balance sheet 50 60 (49) (193)
    Additional cash collateral for commodity contracts
        not subject to rate recovery 2 ― ― ―
    Additional cash collateral for commodity contracts
        subject to rate recovery 28 ― ― ―
    Total(4) $ 80 $ 60 $ (49) $ (193)
SDG&E:
Derivatives designated as hedging instruments:
    Interest rate instruments(3) $ ― $ ― $ (14) $ (23)
Derivatives not designated as hedging instruments:
    Commodity contracts not subject to rate recovery ― ― (1) ―
        Associated offsetting cash collateral ― ― 1 ―
    Commodity contracts subject to rate recovery 27 49 (60) (64)
        Associated offsetting commodity contracts (2) (2) 2 2
        Associated offsetting cash collateral ― ― 28 26
    Net amounts presented on the balance sheet 25 47 (44) (59)
    Additional cash collateral for commodity contracts
        not subject to rate recovery 1 ― ― ―
    Additional cash collateral for commodity contracts
        subject to rate recovery 27 ― ― ―
    Total(4) $ 53 $ 47 $ (44) $ (59)
SoCalGas:
Derivatives not designated as hedging instruments:
    Commodity contracts not subject to rate recovery $ ― $ ― $ (1) $ ―
        Associated offsetting cash collateral ― ― 1 ―
    Commodity contracts subject to rate recovery 1 ― (1) ―
    Net amounts presented on the balance sheet 1 ― (1) ―
    Additional cash collateral for commodity contracts
        subject to rate recovery 1 ― ― ―
    Total $ 2 $ ― $ (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 CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2016
	Current assets: Fixed-price contracts and other derivatives(1)			Other assets: Sundry			Current liabilities: Fixed-price contracts and other derivatives(2)			Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)	$	7		$	2		$	(24	)	$	(228	)
Commodity contracts not subject to rate recovery	—			—			(14		)	—
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery	248			36			(254		)	(28		)
Associated offsetting commodity contracts	(242		)	(27		)	242			27
Associated offsetting cash collateral	—			(1		)	16			1
Commodity contracts subject to rate recovery	37			73			(57		)	(150		)
Associated offsetting commodity contracts	(9		)	(1		)	9			1
Associated offsetting cash collateral	—			—			5			13
Net amounts presented on the balance sheet	41			82			(77		)	(364		)
Additional cash collateral for commodity contracts not subject to rate recovery	10			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	32			—			—			—
Total(4)	$	83		$	82		$	(77	)	$	(364	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)	$	—		$	—		$	(13	)	$	(12	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	33			73			(51		)	(150		)
Associated offsetting commodity contracts	(6		)	(1		)	6			1
Associated offsetting cash collateral	—			—			3			13
Net amounts presented on the balance sheet	27			72			(55		)	(148		)
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	30			—			—			—
Total(4)	$	58		$	72		$	(55	)	$	(148	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	4		$	—		$	(6	)	$	—
Associated offsetting commodity contracts	(3		)	—			3			—
Associated offsetting cash collateral	—			—			2			—
Net amounts presented on the balance sheet	1			—			(1		)	—
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	2			—			—			—
Total	$	4		$	—		$	(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 table below includes the effects of derivative instruments designated as fair value hedges on the Condensed Consolidated Statement of Operations for the three months and six months ended June 30, 2016. There were no fair value hedges outstanding during the three months or six months ended June 30, 2017.



FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
			Pretax gain (loss) on derivatives recognized in earnings
			Three months ended			Six months ended
		Location	June 30, 2016			June 30, 2016
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	1		$	3
Interest rate instruments		Other Income, Net	(2		)	(2		)
Total(1)			$	(1	)	$	1

(1)	There was no hedge ineffectiveness in either the three months or six months ended June 30, 2016. All other changes in the fair value 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.

The table below includes the effects of derivative instruments designated as cash flow hedges on the Condensed Consolidated Statements of Operations and in OCI and AOCI for the three months and six months ended June ~~30 were:~~30:

FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
Pretax gain (loss) on derivatives recognized in earnings
Three months ended June 30, Six months ended June 30,
Location 2016 2015 2016 2015
Sempra Energy Consolidated:
    Interest rate instruments Interest Expense $ 1 $ 2 $ 3 $ 4
    Interest rate instruments Other Income, Net (2) (3) (2) (2)
    Total(1) $ (1) $ (1) $ 1 $ 2
(1) There was no hedge ineffectiveness in either the three months or six months ended June 30, 2016 or 2015. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and are recorded in Other Income, Net.

CASH FLOW HEDGE IMPACTS
(Dollars in millions)
Pretax gain (loss) Pretax (loss) gain reclassified
recognized in OCI from AOCI into earnings
(effective portion) (effective portion)
Three months ended June 30, Three months ended June 30,
2016 2015 Location 2016 2015
Sempra Energy Consolidated:
    Interest rate and foreign
         exchange instruments(1) $ 1 $ 6 Interest Expense $ (3) $ (3)
Equity Earnings (Losses),
    Interest rate instruments (70) 89     Before Income Tax (2) (3)
    Interest rate and foreign Equity Earnings,
         exchange instruments (15) ―     Net of Income Tax (5) ―
    Commodity contracts not subject Revenues: Energy-Related
        to rate recovery (5) 1     Businesses ― ―
    Total(2) $ (89) $ 96 $ (10) $ (6)
SDG&E:
    Interest rate instruments(1)(2) $ (2) $ ― Interest Expense $ (3) $ (3)

Six months ended June 30, Six months ended June 30,
2016 2015 Location 2016 2015
Sempra Energy Consolidated:
    Interest rate and foreign
         exchange instruments(1) $ (10) $ (12) Interest Expense $ (7) $ (9)
Equity Earnings (Losses),
    Interest rate instruments (207) 11     Before Income Tax (5) (6)
    Interest rate and foreign Equity Earnings,
         exchange instruments (33) ―     Net of Income Tax (6) ―
    Commodity contracts not subject Revenues: Energy-Related
        to rate recovery (4) ―     Businesses 7 7
    Total(2) $ (254) $ (1) $ (11) $ (8)
SDG&E:
    Interest rate instruments(1)(2) $ (7) $ (5) Interest Expense $ (6) $ (6)
(1) Amounts include Otay Mesa VIE. All of SDG&E's interest rate derivative activity relates to Otay Mesa VIE.
(2) Amounts include negligible hedge ineffectiveness in the three months and six months ended June 30, 2016 and 2015.



CASH FLOW HEDGE IMPACTS
(Dollars in millions)
	Pretax (loss) gain recognized in OCI							Pretax gain (loss) reclassified from AOCI into earnings
	Three months ended June 30,							Three months ended June 30,
	2017			2016			Location	2017			2016
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments(1)	$	(8	)	$	1		Interest Expense	$	1		$	(3	)
Interest rate instruments	(32		)	(70		)	Equity Earnings (Losses), Before Income Tax	(2		)	(2		)
Interest rate and foreign exchange instruments	(9		)	(15		)	Equity Earnings (Losses), Net of Income Tax	(3		)	(5		)
Foreign exchange instruments	(1		)	—			Revenues: Energy- Related Businesses	1			—
Commodity contracts not subject to rate recovery	—			(5		)	Revenues: Energy- Related Businesses	—			—
Total(2)	$	(50	)	$	(89	)		$	(3	)	$	(10	)
SDG&E:
Interest rate instruments(1)(3)	$	(2	)	$	(2	)	Interest Expense	$	(3	)	$	(3	)

	Six months ended June 30,							Six months ended June 30,
	2017			2016			Location	2017			2016
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments(1)	$	8		$	(10	)	Interest Expense	$	4		$	(7	)
Interest rate instruments	(37		)	(207		)	Equity Earnings (Losses), Before Income Tax	(4		)	(5		)
Interest rate and foreign exchange instruments	(18		)	(33		)	Equity Earnings (Losses), Net of Income Tax	(5		)	(6		)
Foreign exchange instruments	(10		)	—			Revenues: Energy- Related Businesses	(1		)	—
Commodity contracts not subject to rate recovery	3			(4		)	Revenues: Energy- Related Businesses	(9		)	7
Total(2)	$	(54	)	$	(254	)		$	(15	)	$	(11	)
SDG&E:
Interest rate instruments(1)(3)	$	(2	)	$	(7	)	Interest Expense	$	(6	)	$	(6	)


(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.


(2)	There was $2 million of losses from hedge ineffectiveness related to these cash flow hedges in each of the three months and six months ended June 30, 2017 and negligible amounts for the same periods in 2016.


(3)	There was negligible hedge ineffectiveness related to these cash flow hedges in the three months and six months ended June 30, 2017 and 2016.

For Sempra Energy Consolidated, we expect that ~~losses~~net gains of ~~$23~~$11 million, which are net of income tax expense, that are currently recorded in AOCI (including $11 million of losses in noncontrolling interests 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. SoCalGas expects that negligible losses, net of income tax benefit, that are currently recorded in AOCI ~~(including $13 million in noncontrolling interests, substantially all of which 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 remaining term over which we are hedging exposure to the variability of cash flows at June 30, ~~2016~~2017 is approximately 1315 years and 32 years for Sempra Energy Consolidated and SDG&E, respectively. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is 1918 years.

The effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations for the three months and six months ended June 30 were:



UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Three months ended June 30,					Six months ended June 30,
	Location	2017		2016			2017			2016
Sempra Energy Consolidated:
Foreign exchange instruments	Other Income, Net	$	32	$	(15	)	$	97		$	(12	)
Foreign exchange instruments	Equity Earnings (Losses), Net of Income Tax	—		—			—			2
Commodity contracts not subject to rate recovery	Revenues: Energy-Related Businesses	16		(24		)	30			(29		)
Commodity contracts not subject to rate recovery	Operation and Maintenance	—		1			(1		)	1
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	6		40			(23		)	28
Commodity contracts subject to rate recovery	Cost of Natural Gas	—		(1		)	—			(2		)
Total		$	54	$	1		$	103		$	(12	)
SDG&E:
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	$	6	$	40		$	(23	)	$	28
SoCalGas:
Commodity contracts not subject to rate recovery	Operation and Maintenance	$	—	$	—		$	(1	)	$	—
Commodity contracts subject to rate recovery	Cost of Natural Gas	—		(1		)	—			(2		)
Total		$	—	$	(1	)	$	(1	)	$	(2	)

UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
Pretax (loss) gain on derivatives recognized in earnings

Three months ended
June 30,
Six months ended
June 30,
Location 2016 2015 2016 2015
Sempra Energy Consolidated:
    Foreign exchange instruments Other Income, Net $ (15) $ (3) $ (12) $ (3)
    Foreign exchange instruments Equity Earnings,
    Net of Income Tax ― ― 2 (1)
    Commodity contracts not subject Revenues: Energy-Related
        to rate recovery     Businesses (24) 9 (29) 12
    Commodity contracts not subject
        to rate recovery Operation and Maintenance 1 1 1 1
    Commodity contracts subject Cost of Electric Fuel
        to rate recovery     and Purchased Power 40 (53) 28 (73)
    Commodity contracts subject
        to rate recovery Cost of Natural Gas (1) ― (2) 1
    Total $ 1 $ (46) $ (12) $ (63)
SDG&E:
    Commodity contracts subject Cost of Electric Fuel
        to rate recovery     and Purchased Power $ 40 $ (53) $ 28 $ (73)
SoCalGas:
    Commodity contracts not subject ��
        to rate recovery Operation and Maintenance $ ― $ 1 $ ― $ 1
    Commodity contracts subject
        to rate recovery Cost of Natural Gas (1) ― (2) 1
    Total $ (1) $ 1 $ (2) $ 2

CONTINGENT FEATURES

For Sempra Energy Consolidated and SDG&E, certain of our derivative instruments contain credit limits which vary depending on 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 ~~is $6 million~~ at ~~both~~ June 30, ~~2016~~2017 and December 31, ~~2015.~~2016 is $4 million and $10 million, respectively. At June 30, ~~2016,~~2017, if the credit ratings of Sempra Energy were reduced below investment grade, $8$6 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 is $1 million at June 30, ~~2016~~2017 and negligible at December 31, ~~2015 is $2 million and $5 million, respectively.~~2016. At June 30, ~~2016,~~2017, if the credit ratings of SDG&E were reduced below investment grade, $4$3 million of additional assets could be required to be posted as collateral for these derivative contracts.

For Sempra Energy Consolidated, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.

NOTE 8. FAIR VALUE MEASUREMENTS

We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. ~~We have not changed the valuation techniques or types of inputs we use to measure fair value during the six months ended June 30, 2016.~~

RECURRING FAIR VALUE MEASURES

~~Recurring Fair Value Measures~~

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at June 30, ~~2016~~2017 and December 31, ~~2015.~~2016. 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.We have not changed the valuation techniques or types of inputs we use to measure recurring fair value during the six months ended June 30, 2017.

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 7 under ~~"Financial~~“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 June 30, ~~2016~~2017 and December 31, ~~2015~~2016 in the tables below include the following:

▪

Nuclear decommissioning trusts reflect the assets of SDG~~&E's nuclear decommissioning trusts,~~&E’s NDT, 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~~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).

▪

For commodity contracts, interest rate derivatives and foreign exchange instruments, 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). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below ~~under "Level~~in “Level 3 Information."”

§
▪	Rabbi Trust 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). These investments in marketable securities were negligible at both June 30, ~~2016~~2017 and December 31, ~~2015.~~2016.

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.

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
Fair value at June 30, 2016
Level 1 Level 2 Level 3 Netting(1) Total
Assets:
    Nuclear decommissioning trusts:
          Equity securities $ 632 $ ― $ ― $ ― $ 632
          Debt securities:
              Debt securities issued by the U.S. Treasury and other
                   U.S. government corporations and agencies 52 52 ― ― 104
              Municipal bonds ― 163 ― ― 163
              Other securities ― 192 ― ― 192
          Total debt securities 52 407 ― ― 459
    Total nuclear decommissioning trusts(2) 684 407 ― ― 1,091
    Interest rate and foreign exchange instruments ― 1 ― ― 1
    Commodity contracts not subject to rate recovery 1 17 ― 14 32
    Commodity contracts subject to rate recovery ― 1 63 27 91
Total $ 685 $ 426 $ 63 $ 41 $ 1,215

Liabilities:
    Interest rate and foreign exchange instruments $ ― $ 211 $ ― $ ― $ 211
    Commodity contracts not subject to rate recovery 32 5 ― (31) 6
    Commodity contracts subject to rate recovery 1 37 39 (28) 49
Total $ 33 $ 253 $ 39 $ (59) $ 266

Fair value at December 31, 2015
Level 1 Level 2 Level 3 Netting(1) Total
Assets:
    Nuclear decommissioning trusts:
          Equity securities $ 619 $ ― $ ― $ ― $ 619
          Debt securities:
              Debt securities issued by the U.S. Treasury and other
                   U.S. government corporations and agencies 47 44 ― ― 91
              Municipal bonds ― 156 ― ― 156
              Other securities ― 182 ― ― 182
          Total debt securities 47 382 ― ― 429
    Total nuclear decommissioning trusts(2) 666 382 ― ― 1,048
    Interest rate and foreign exchange instruments ― 5 ― ― 5
    Commodity contracts not subject to rate recovery 22 16 ― (4) 34
    Commodity contracts subject to rate recovery ― 1 72 28 101
Total $ 688 $ 404 $ 72 $ 24 $ 1,188

Liabilities:
    Interest rate and foreign exchange instruments $ ― $ 171 $ ― $ ― $ 171
    Commodity contracts not subject to rate recovery 5 3 ― (4) 4
    Commodity contracts subject to rate recovery ― 68 53 (54) 67
Total $ 5 $ 242 $ 53 $ (58) $ 242
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and 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 June 30, 2016
Level 1 Level 2 Level 3 Netting(1) Total
Assets:
    Nuclear decommissioning trusts:
          Equity securities $ 632 $ ― $ ― $ ― $ 632
          Debt securities:
              Debt securities issued by the U.S. Treasury and other
                   U.S. government corporations and agencies 52 52 ― ― 104
              Municipal bonds ― 163 ― ― 163
              Other securities ― 192 ― ― 192
          Total debt securities 52 407 ― ― 459
    Total nuclear decommissioning trusts(2) 684 407 ― ― 1,091
    Commodity contracts subject to rate recovery ― ― 63 26 89
Total $ 684 $ 407 $ 63 $ 26 $ 1,180

Liabilities:
    Interest rate instruments $ ― $ 37 $ ― $ ― $ 37
    Commodity contracts subject to rate recovery ― 36 39 (27) 48
Total $ ― $ 73 $ 39 $ (27) $ 85

Fair value at December 31, 2015
Level 1 Level 2 Level 3 Netting(1) Total
Assets:
    Nuclear decommissioning trusts:
          Equity securities $ 619 $ ― $ ― $ ― $ 619
          Debt securities:
              Debt securities issued by the U.S. Treasury and other
                   U.S. government corporations and agencies 47 44 ― ― 91
              Municipal bonds ― 156 ― ― 156
              Other securities ― 182 ― ― 182
          Total debt securities 47 382 ― ― 429
    Total nuclear decommissioning trusts(2) 666 382 ― ― 1,048
    Commodity contracts not subject to rate recovery ― ― ― 1 1
    Commodity contracts subject to rate recovery ― ― 72 27 99
Total $ 666 $ 382 $ 72 $ 28 $ 1,148

Liabilities:
    Interest rate instruments $ ― $ 37 $ ― $ ― $ 37
    Commodity contracts not subject to rate recovery 1 ― ― (1) ―
    Commodity contracts subject to rate recovery ― 67 53 (54) 66
Total $ 1 $ 104 $ 53 $ (55) $ 103
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2) Excludes cash balances and cash equivalents.



RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Fair value at June 30, 2017
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	494	$	5	$	—	$	—		$	499
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	49		8		—		—			57
Municipal bonds	—		263		—		—			263
Other securities	—		199		—		—			199
Total debt securities	49		470		—		—			519
Total nuclear decommissioning trusts(2)	543		475		—		—			1,018
Interest rate and foreign exchange instruments	—		131		—		—			131
Commodity contracts not subject to rate recovery	7		12		—		10			29
Commodity contracts subject to rate recovery	—		1		84		17			102
Total	$	550	$	619	$	84	$	27		$	1,280

Liabilities:
Interest rate and foreign exchange instruments	$	—	$	209	$	—	$	—		$	209
Commodity contracts not subject to rate recovery	3		3		—		—			6
Commodity contracts subject to rate recovery	25		6		174		(25		)	180
Total	$	28	$	218	$	174	$	(25	)	$	395

	Fair value at December 31, 2016
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	508	$	—	$	—	$	—		$	508
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	36		16		—		—			52
Municipal bonds	—		206		—		—			206
Other securities	—		141		—		—			141
Total debt securities	36		363		—		—			399
Total nuclear decommissioning trusts(2)	544		363		—		—			907
Interest rate and foreign exchange instruments	—		9		—		—			9
Commodity contracts not subject to rate recovery	—		15		—		9			24
Commodity contracts subject to rate recovery	1		3		96		32			132
Total	$	545	$	390	$	96	$	41		$	1,072

Liabilities:
Interest rate and foreign exchange instruments	$	—	$	252	$	—	$	—		$	252
Commodity contracts not subject to rate recovery	16		11		—		(17		)	10
Commodity contracts subject to rate recovery	19		8		170		(18		)	179
Total	$	35	$	271	$	170	$	(35	)	$	441


(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and 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 June 30, 2016
Level 1 Level 2 Level 3 Netting(1) Total
Assets:
    Commodity contracts not subject to rate recovery $ ― $ ― $ ― $ 1 $ 1
    Commodity contracts subject to rate recovery ― 1 ― 1 2
Total $ ― $ 1 $ ― $ 2 $ 3

Liabilities:
    Commodity contracts not subject to rate recovery $ 1 $ ― $ ― $ (1) $ ―
    Commodity contracts subject to rate recovery 1 1 ― (1) 1
Total $ 2 $ 1 $ ― $ (2) $ 1

Fair value at December 31, 2015
Level 1 Level 2 Level 3 Netting(1) Total
Assets:
    Commodity contracts subject to rate recovery $ ― $ 1 $ ― $ 1 $ 2
Total $ ― $ 1 $ ― $ 1 $ 2

Liabilities:
    Commodity contracts not subject to rate recovery $ 1 $ ― $ ― $ (1) $ ―
    Commodity contracts subject to rate recovery ― 1 ― ― 1
Total $ 1 $ 1 $ ― $ (1) $ 1
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.



RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
	Fair value at June 30, 2017
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	494	$	5	$	—	$	—		$	499
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	49		8		—		—			57
Municipal bonds	—		263		—		—			263
Other securities	—		199		—		—			199
Total debt securities	49		470		—		—			519
Total nuclear decommissioning trusts(2)	543		475		—		—			1,018
Commodity contracts subject to rate recovery	—		—		84		16			100
Total	$	543	$	475	$	84	$	16		$	1,118

Liabilities:
Interest rate instruments	$	—	$	20	$	—	$	—		$	20
Commodity contracts subject to rate recovery	25		5		174		(25		)	179
Total	$	25	$	25	$	174	$	(25	)	$	199

	Fair value at December 31, 2016
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	508	$	—	$	—	$	—		$	508
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	36		16		—		—			52
Municipal bonds	—		206		—		—			206
Other securities	—		141		—		—			141
Total debt securities	36		363		—		—			399
Total nuclear decommissioning trusts(2)	544		363		—		—			907
Commodity contracts not subject to rate recovery	—		—		—		1			1
Commodity contracts subject to rate recovery	1		2		96		30			129
Total	$	545	$	365	$	96	$	31		$	1,037

Liabilities:
Interest rate instruments	$	—	$	25	$	—	$	—		$	25
Commodity contracts subject to rate recovery	17		7		170		(16		)	178
Total	$	17	$	32	$	170	$	(16	)	$	203


(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and 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 June 30, 2017
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Commodity contracts not subject to rate recovery	$	—	$	—	$	—	$	1		$	1
Commodity contracts subject to rate recovery	—		1		—		1			2
Total	$	—	$	1	$	—	$	2		$	3

Liabilities:
Commodity contracts subject to rate recovery	$	—	$	1	$	—	$	—		$	1
Total	$	—	$	1	$	—	$	—		$	1

	Fair value at December 31, 2016
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Commodity contracts not subject to rate recovery	$	—	$	—	$	—	$	1		$	1
Commodity contracts subject to rate recovery	—		1		—		2			3
Total	$	—	$	1	$	—	$	3		$	4

Liabilities:
Commodity contracts subject to rate recovery	$	2	$	1	$	—	$	(2	)	$	1
Total	$	2	$	1	$	—	$	(2	)	$	1


(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Level 3 Information

The following table sets forth reconciliations of changes in the fair value of ~~congestion revenue rights (CRRs)~~CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:



LEVEL 3 RECONCILIATIONS
(Dollars in millions)
	Three months ended June 30,
	2017			2016
Balance at April 1	$	(96	)	$	11
Realized and unrealized (losses) gains	(3		)	8
Settlements	9			5
Balance at June 30	$	(90	)	$	24
Change in unrealized gains relating to
instruments still held at June 30	$	2		$	9



	Six months ended June 30,
	2017			2016
Balance at January 1	$	(74	)	$	19
Realized and unrealized (losses) gains	(16		)	7
Settlements	—			(2		)
Balance at June 30	$	(90	)	$	24
Change in unrealized (losses) gains relating to
instruments still held at June 30	$	(14	)	$	9

LEVEL 3 RECONCILIATIONS
(Dollars in millions)
Three months ended June 30,
2016 2015
Balance as of April 1 $ 11 $ 102
    Realized and unrealized gains (losses) 8 (60)
    Allocated transmission instruments ― 1
    Settlements 5 (1)
Balance as of June 30 $ 24 $ 42
Change in unrealized gains relating to
    instruments still held at June 30 $ 9 $ 45

Six months ended June 30,
2016 2015
Balance as of January 1 $ 19 $ 107
    Realized and unrealized gains (losses) 7 (54)
    Allocated transmission instruments ― 1
    Settlements (2) (12)
Balance as of June 30 $ 24 $ 42
Change in unrealized gains relating to
    instruments still held at June 30 $ 9 $ 46

SDG~~&E's~~&E’s Energy and Fuel Procurement department, in conjunction with SDG~~&E's~~&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the ~~California Independent System Operator (CAISO),~~CAISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and ~~remain in effect~~are the basis for valuation for the following year. The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. ~~From~~

For CRRs settling from January 1, 2017 to December 31, 2017, the auction price inputs ranged from $(12) per MWh to $7 per MWh at a given location, and for CRRs settling from January 1, 2016 to December 31, 2016, the auction ~~prices range~~price inputs ranged from $(24) per MWh to $10 ~~per MWh at a given location, and from January 1, 2015 to December 31, 2015, the auction prices ranged from $(16) per MWh to $8~~ per MWh at a given location. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 7.

Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. ~~At June 30, 2016, these electricity forward prices~~These inputs range from ~~$21.55~~$21.35 per MWh to ~~$62.71~~$46.35 per ~~MWh.~~MWh at June 30, 2017. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively. We summarize long-term, fixed-price electricity position volumes in Note 7.

Realized gains and losses associated with CRRs and long-term electricity positions, which are ~~recoverable~~included in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore ~~also~~ do not affect earnings.

FAIR VALUE OF FINANCIAL INSTRUMENTS

~~Fair Value of Financial Instruments~~

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, ~~current~~short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. 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 that are not recorded at fair value on the Condensed Consolidated Balance Sheets at June 30, ~~2016~~2017 and December 31, ~~2015:~~2016:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
June 30, 2016
Carrying Fair value
amount Level 1 Level 2 Level 3 Total
Sempra Energy Consolidated:
Noncurrent due from unconsolidated affiliates(1)
$ 179 $ ― $ 94 $ 77 $ 171
Total long-term debt(2)(3)
13,811 ― 14,933 572 15,505
Preferred stock of subsidiary 20 ― 25 ― 25
SDG&E:
Total long-term debt(3)(4)
$ 4,677 $ ― $ 5,055 $ 310 $ 5,365
SoCalGas:
Total long-term debt(5)
$ 3,009 $ ― $ 3,335 $ ― $ 3,335
Preferred stock 22 ― 27 ― 27

December 31, 2015
Carrying Fair value
amount Level 1 Level 2 Level 3 Total
Sempra Energy Consolidated:
Noncurrent due from unconsolidated affiliates(1)
$ 175 $ ― $ 97 $ 69 $ 166
Total long-term debt(2)(3)
13,761 ― 13,985 648 14,633
Preferred stock of subsidiary 20 ― 23 ― 23
SDG&E:
Total long-term debt(3)(4)
$ 4,304 $ ― $ 4,355 $ 315 $ 4,670
SoCalGas:
Total long-term debt(5)
$ 2,513 $ ― $ 2,621 $ ― $ 2,621
Preferred stock 22 ― 25 ― 25
(1) Excluding accumulated interest outstanding of $13 million and $11 million at June 30, 2016 and December 31, 2015, respectively.
(2) Before reductions for unamortized discount (net of premium) and debt issuance costs of $111 million and $107 million at June 30, 2016 and December 31, 2015, respectively, and excluding build-to-suit and capital lease obligations of $385 million and $387 million at June 30, 2016 and December 31, 2015, respectively. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
(3) Level 3 instruments include $310 million and $315 million at June 30, 2016 and December 31, 2015, respectively, related to Otay Mesa VIE.
(4) Before reductions for unamortized discount and debt issuance costs of $47 million and $43 million at June 30, 2016 and December 31, 2015, respectively, and excluding capital lease obligations of $242 million and $244 million at June 30, 2016 and December 31, 2015, respectively.
(5) Before reductions for unamortized discount and debt issuance costs of $28 million and $24 million at June 30, 2016 and December 31, 2015, respectively, and excluding capital lease obligations of $1 million both at June 30, 2016 and December 31, 2015.



FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	June 30, 2017
	Carrying amount		Fair value
	Carrying amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates(1)	$	345	$	—	$	228	$	92	$	320
Total long-term debt(2)(3)	15,519		—		15,900		494		16,394
SDG&E:
Total long-term debt(3)(4)	$	4,891	$	—	$	5,032	$	300	$	5,332
SoCalGas:
Total long-term debt(5)	$	3,009	$	—	$	3,169	$	—	$	3,169

	December 31, 2016
	Carrying amount		Fair value
	Carrying amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates(1)	$	184	$	—	$	91	$	84	$	175
Total long-term debt(2)(3)	15,068		—		15,455		492		15,947
SDG&E:
Total long-term debt(3)(4)	$	4,654	$	—	$	4,727	$	305	$	5,032
SoCalGas:
Total long-term debt(5)	$	3,009	$	—	$	3,131	$	—	$	3,131


(1)	Excluding accumulated interest outstanding of $22 million and $17 million at June 30, 2017 and December 31, 2016, respectively, and excluding foreign currency translation of $6 million on a Mexican peso-denominated loan at June 30, 2017.

(2)

Before reductions for unamortized discount (net of premium) and debt issuance costs of $114 million and $109 million at June 30, 2017 and December 31, 2016, respectively, and excluding build-to-suit and capital lease obligations of $882 million and $383 million at June 30, 2017 and December 31, 2016, respectively. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.


(3)	Level 3 instruments include $300 million and $305 million at June 30, 2017 and December 31, 2016, respectively, related to Otay Mesa VIE.


(4)	Before reductions for unamortized discount and debt issuance costs of $48 million and $45 million at June 30, 2017 and December 31, 2016, respectively, and excluding capital lease obligations of $737 million and $240 million at June 30, 2017 and December 31, 2016, respectively.


(5)	Before reductions for unamortized discount and debt issuance costs of $25 million and $27 million at June 30, 2017 and December 31, 2016, respectively, and excluding capital lease obligations of $1 million at June 30, 2017.

We determine the fair value of certain ~~noncurrent~~long-term amounts due from unconsolidated affiliates and long-term debt ~~and preferred stock~~ based on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value certain other ~~noncurrent~~long-term amounts due from unconsolidated affiliates ~~of Sempra South American Utilities~~ using a perpetuity approach based on the ~~obligation's~~obligation’s fixed interest rate, the absence of a stated maturity date and a discount rate reflecting local borrowing costs (Level 3). 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~~NDT related to ~~the San Onofre Nuclear Generating Station (SONGS)~~SONGS in Note ~~9 below.~~9.

NON-RECURRING FAIR VALUE MEASURES

~~Non-Recurring Fair Value Measures –~~TdM

In February 2016, management approved a plan to market and sell Sempra Mexico’s TdM, a natural gas-fired power plant, and classified it as held for sale on the Sempra Energy Consolidated

~~Sempra Natural Gas – Rockies Express~~

As Balance Sheet, as we discuss in Note 3 above and in ~~March 2016,~~Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. In connection with the sales process, Sempra ~~Natural Gas agreed to sell~~Mexico received a purchase price offer resulting from negotiations with an active market participant. This new market information indicates that the fair value of TdM was lower than its ~~25-percent interest in Rockies Express for cash consideration~~carrying value at June 30, 2017. As a result, Sempra Mexico further reduced the carrying value of ~~$440 million, subject to adjustment at closing. The transaction closed in May 2016. In March 2016, we recorded~~TdM by recognizing a noncash impairment charge of ~~our investment~~$71 million in ~~Rockies Express of $44 million ($27 million after-tax). The charge is included in Equity Earnings, Before Income Tax, on~~ the ~~Condensed Consolidated Statement of Operations for the~~three months and six months ended June 30, ~~2016. We~~2017, recorded in Impairment Losses on Sempra Energy’s Consolidated Statements of Operations. The purchase price offer is considered ~~the sale price for our equity interest in Rockies Express~~ to be a market participants' view of the total value of Rockies Express and measured the fair value of our investment based on the equity sale price. Use of this market participant input as the indicator of fair value is a Level 2 ~~measurement~~input in the fair value ~~hierarchy.~~hierarchy, as it represents an observable pricing input.

The following table summarizes significant inputs impacting this non-recurring fair value ~~measures related to our investment in Rockies Express:~~measure:

NON-RECURRING FAIR VALUE MEASURE – SEMPRA ENERGY CONSOLIDATED

(Dollars in millions)

Estimated

fair

value

Valuation technique

Fair

value

hierarchy

% of

fair value

measurement

Inputs used to

develop

measurement

Range of

inputs

TdM

(1)

Market approach

Level 2

100%

Purchase price offer

100%

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
Estimated Fair % of Inputs used to
fair value fair value develop Range of
value Valuation technique hierarchy measurement measurement inputs
Investment in
Rockies Express $ 440 (1) Market approach Level 2 100% Equity sale price 100%
(1) At measurement date of March 29, 2016.


(1)	At measurement date of June 30, 2017.

NOTE 9. SAN ONOFRE NUCLEAR GENERATING STATION ~~(SONGS)~~

~~SDG&E has a 20-percent ownership interest in~~We provide below updates to ongoing matters related to SONGS, a nuclear generating facility near San Clemente, California ~~which~~that ceased operations in June ~~2013. On June 6,~~ 2013, ~~after an extended outage beginning~~and in ~~2012, Southern California Edison Company (Edison), the majority owner and operator of SONGS, notified~~ which SDG&E ~~that it had reached~~has a ~~decision to permanently retire~~20-percent ownership interest. We discuss 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~~further in Note 13 of the ~~NRC and the CPUC.~~

~~SDG&E, and each of the other owners, holds its undivided interest as a tenant in common~~Notes to Consolidated Financial Statements in the property. Each owner is responsible for financing its share of expenses and capital expenditures. SDG&E's share of operating expenses is included in Sempra Energy's and SDG&E's Condensed Consolidated Statements of Operations.Annual Report.

REPLACEMENT STEAM GENERATORS

~~SONGS Steam Generator Replacement Project~~

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, the majority owner and operator of SONGS, 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~~2’s steam generator. These issues with the steam generators ultimately resulted in ~~Edison's~~Edison’s decision to permanently retire ~~SONGS.~~SONGS in June 2013.

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).~~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 ~~binding~~ arbitration proceedings against MHI seeking ~~damages as well.~~recovery of damages. The other SONGS co-owners, SDG&E ~~is participating in~~and the City of Riverside, participated as claimants and respondents.

On March 13, 2017, the Tribunal overseeing the arbitration asfound MHI liable for breach of contract, subject to a ~~claimant~~contractual limitation of liability, and ~~respondent. We discuss~~rejected claimants’ other claims. The Tribunal awarded $118 million in damages to the SONGS co-owners, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. The damage award is offset by these ~~proceedings~~costs, resulting in ~~Note 11.~~

a net award of approximately $60 million in favor of the SONGS co-owners. SDG&E’s specific allocation of the damage award is $24 million reduced by costs awarded to MHI of approximately $12 million, resulting in a net damage award of $12 million, which was paid by MHI to SDG&E in March 2017. These amounts include certain adjustments to calculations supporting the Tribunal’s findings. In accordance with the Amended Settlement Agreement ~~to Resolve~~discussed below, which may be modified or set aside, SDG&E recorded the ~~CPUC's Order Instituting Investigation (OII) into~~proceeds from the MHI arbitration by reducing Operation and Maintenance for previously incurred legal costs of $11 million, and shared the remaining $1 million equally between ratepayers and shareholders.

SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION INTO THE SONGS ~~Outage (SONGS OII)~~OUTAGE

In November 2012, in response to the outage, the CPUC issued the SONGS OII, which 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).~~outage.

In ~~April~~November 2014, ~~SDG&E filed with~~ the CPUC ~~in the SONGS OII proceeding~~issued a Settlement Agreement, along with Edison, The Utility Reform Network (TURN), the CPUC Office of Ratepayer Advocates (ORA) and two other intervenors who joined the Settlement Agreement (collectively, the Settling Parties).

~~In September 2014, the Settling Parties executed~~final decision approving an Amended and Restated Settlement Agreement (Amended Settlement Agreement)~~, which amended~~ in the ~~Settlement Agreement,~~SONGS OII proceeding executed by SDG&E along with Edison, TURN, ORA and ~~in November 2014, the CPUC issued a final decision approving the Amended Settlement Agreement.~~two other intervenors. The Amended Settlement Agreement does not affect ~~on-going~~ongoing 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)~~addressed in the final decision) or proceedings addressing decommissioning activities and costs. We ~~discuss~~describe the terms and provisions of the Amended Settlement Agreement ~~and related filings~~ in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

In April 2015, a petition for modification (PFM) was filed with the CPUC by Alliance for Nuclear Responsibility (A4NR), an intervenor in the SONGS OII proceeding, asking the CPUC to set aside its decision approving the Amended Settlement Agreement and reopen the SONGS OII proceeding. In June 2015, TURN, a party to the Amended Settlement Agreement, filed a response supporting the A4NR petition. TURN does not question the merits of the Amended Settlement Agreement, but is concerned that certain allegations regarding Edison raised by A4NR have undermined the public's confidence in the regulatory process. SDG&E has responded that TURN's concerns regarding public perception do not impact the reasonableness of the Amended Settlement Agreement and are insufficient to overturn it.

In August 2015, ORA, also a party to the Amended Settlement Agreement, filed a PFM with the CPUC, withdrawing its support for the Amended Settlement Agreement and asking the CPUC to reopen the SONGS OII proceeding. The ORA does not question the merits of the Amended Settlement Agreement, but is concerned with the CPUC's approach toward recent disclosures concerning Edison ex parte communications with the CPUC. SDG&E responded that the ORA's PFM is insufficient to overturn the Amended Settlement Agreement, because the ORA fails to make a case that the Amended Settlement Agreement is no longer in the public interest.

In May 2016, following the filing of petitions for modification by various parties, the CPUC issued a procedural ruling reopening the record of the OII to address the issue of whether the Amended Settlement Agreement is reasonable and in the public interest.

In ~~accordance with the ruling, Edison and SDG&E filed separate reports with~~December 2016, the CPUC ~~in June 2016 on~~issued another procedural ruling directing parties to the SONGS OII to determine whether an agreement could be reached to modify the Amended Settlement Agreement previously approved by the CPUC, to resolve allegations that unreported ex parte communications between Edison and the ~~status~~CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated. Pursuant to the December ruling and a subsequent procedural ruling, the parties have met to confer and, as a result of ~~its implementation,~~these discussions, the parties engaged a mediator and ~~filed separate legal briefs~~held confidential mediation discussions in June, July ~~2016 asserting~~and continuing into August of 2017. Given the mediation, the parties were granted an extension until August 15, 2017 to file their proposed settlement and/or positions for moving forward with the proceeding. If no agreement is reached, the CPUC will consider other options, including entertaining additional testimony, hearings and briefs.

There is no assurance that the Amended Settlement Agreement ~~is reasonable~~will not be renegotiated, modified or set aside as a result of the mediation or the larger OII proceedings, which could result in a substantial reduction in our expected recovery and ~~in the public interest.~~could have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations, financial condition and cash flows.

Accounting and Financial Impacts

Through ~~December 31, 2015 and~~ June 30, ~~2016,~~2017, the cumulative after-tax loss from plant closure recorded by Sempra Energy and SDG&E is $125 ~~million, including a reduction in the after-tax loss of $13 million recorded in the first quarter of 2015.~~million. The remaining regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is ~~$206~~$166 million ($4534 million current and ~~$161~~$132 million long-term) at June 30, 2016 and is recorded on the Condensed Consolidated Balance Sheets in Other Current Assets and Regulatory Assets Noncurrent, respectively, at Sempra Energy, and in Regulatory Assets Current and Other Regulatory Assets Noncurrent, respectively, at SDG&E. 2017. The amortization period prescribed for the regulatory asset is 10 years, ~~which commenced~~ending in January ~~2015 following the CPUC's final decision approving the Amended Settlement Agreement in November 2014.~~2022.

NUCLEAR DECOMMISSIONING AND FUNDING

~~Settlement with Nuclear Electric Insurance Limited (NEIL)~~

NEIL insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks. In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with NEIL to resolve all of SONGS' insurance claims arising out of the failures of the replacement steam generators for a total payment by NEIL of $400 million, SDG&E's share of which is $80 million. Pursuant to the terms of the SONGS OII Amended Settlement Agreement, after reimbursement of legal fees and a 5-percent allocation to shareholders, the net proceeds of $75 million were allocated to ratepayers through ERRA. We discuss NEIL further in Note 11.

~~Nuclear Decommissioning and Funding~~

As a result of ~~Edison's~~Edison’s decision to permanently retire SONGS Units 2 and 3, Edison ~~has begun~~began the decommissioning phase of the plant. ~~We discuss~~Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be done once Units 2 and 3 are dismantled. In December 2016, Edison announced that, following a 10-month competitive bid process, it had contracted with a joint venture of AECOM and EnergySolutions (known as SONGS Decommissioning Solutions) as the ~~process~~general contractor to complete the dismantlement of ~~decommissioning SONGS and oversight by the NRC in Note 13~~SONGS. The majority of the ~~Notes~~dismantlement work is expected to ~~Consolidated Financial Statements in~~take 10 years. SDG&E is responsible for approximately 20 percent of the ~~Annual Report.~~total contract price.

In accordance with state and federal requirements and regulations, SDG&E has assets held in ~~trusts, referred~~the NDT to ~~as the Nuclear Decommissioning Trusts (NDT), to~~ fund its share of decommissioning costs for SONGS Units 1, 2 and 3. ~~Decommissioning~~The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of ~~Unit 1, removed~~externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. The NDT assets are presented on the Sempra Energy and SDG&E Condensed Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from ~~service in 1992, is largely complete. The remaining work will be done when~~Removal Obligations.

In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 ~~are decommissioned. At June 30, 2016, the fair value~~ of $4.4 billion (in 2014 dollars), of which SDG~~&E's NDT assets was $1.1 billion.~~ &E’s share is $899 million. 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 April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 of $4.411 billion, of which SDG&E's share is $899 million. The decision also approves an annual advice letter request process for SDG&E to request trust fund disbursements for decommissioning costs based on a forecast for 2016 and thereafter. Disbursements from the trust will then be made up to this annual forecast amount as decommissioning expenses are incurred. All disbursements will be subject to future refund until a reasonableness review of the actual decommissioning costs is conducted, which would be no less frequently than every three years.

SDG&E has received authorization from the CPUC to access ~~trust~~NDT funds ~~for SONGS decommissioning costs~~ of up to ~~$218~~ $302 million for 2013 through ~~2016 (forecasted). The total of $218~~2017 (2017 forecasted) SONGS decommissioning costs. This includes up to $84 million ~~includes $75 million that is expected~~authorized by the CPUC in February 2017 to be withdrawn ~~pending satisfactory clarification by~~from the ~~Internal Revenue Service (IRS)~~NDT for forecasted 2017 SONGS Units 2 and 3 costs as decommissioning costs are incurred.

In December 2016, the IRS and the U.S. Department of the Treasury issued proposed regulations that ~~certain~~clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified fund. The proposed regulations state that costs related to the construction and maintenance of independent spent fuel ~~costs and other costs~~management installations are ~~eligible~~included in the definition of “nuclear decommissioning ~~costs, payable from qualified nuclear decommissioning trusts. We are uncertain as to when such clarification~~costs.” The proposed regulations will be ~~provided.~~

effective prospectively once they are finalized; however, the IRS has stated that it will not challenge taxpayer positions consistent with the proposed regulations for taxable years ending on or after the date the proposed regulations were issued. SDG&E is seeking further clarification of the proposed regulations to confirm that the proposed regulations will allow SDG&E to access the NDT funds for reimbursement or payment of the spent fuel management costs that were or will be incurred in 2016 and subsequent years. Further clarification of the proposed regulations could enable SDG&E to access the NDT to recover spent fuel management costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the NDT and matters related to its funding and the funding of decommissioning costs by the NDT further in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report. We discuss matters related toDOE’s responsibility for spent nuclear fuel in Note 11. It is unclear when clarification of the proposed regulations might be provided or when the proposed regulations will be finalized.

~~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 presented on the Sempra Energy and SDG&E Condensed Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from Removal Obligations.

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 8.



NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At June 30, 2017:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)	$	57	$	—	$	—		$	57
Municipal bonds(2)	256		8		(1		)	263
Other securities(3)	197		3		(1		)	199
Total debt securities	510		11		(2		)	519
Equity securities	196		305		(2		)	499
Cash and cash equivalents	11		—		—			11
Total	$	717	$	316	$	(4	)	$	1,029
At December 31, 2016:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	$	52	$	—	$	—		$	52
Municipal bonds	203		4		(1		)	206
Other securities	141		2		(2		)	141
Total debt securities	396		6		(3		)	399
Equity securities	143		366		(1		)	508
Cash and cash equivalents	119		—		—			119
Total	$	658	$	372	$	(4	)	$	1,026

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
Gross Gross Estimated
unrealized unrealized fair
Cost gains losses value
At June 30, 2016:
Debt securities:
    Debt securities issued by the U.S. Treasury and other
         U.S. government corporations and agencies(1) $ 99 $ 5 $ ― $ 104
    Municipal bonds(2) 150 13 ― 163
    Other securities(2) 189 9 (6) 192
Total debt securities 438 27 (6) 459
Equity securities 221 416 (5) 632
Cash and cash equivalents 12 ― ― 12
    Total $ 671 $ 443 $ (11) $ 1,103
At December 31, 2015:
Debt securities:
    Debt securities issued by the U.S. Treasury and other
         U.S. government corporations and agencies $ 89 $ 2 $ ― $ 91
    Municipal bonds 148 8 ― 156
    Other securities 194 1 (13) 182
Total debt securities 431 11 (13) 429
Equity securities 214 412 (7) 619
Cash and cash equivalents 15 ― ― 15
    Total $ 660 $ 423 $ (20) $ 1,063
(1) Maturity dates are 2017-2065.
(2) Maturity dates are 2016-2115.


(1)	Maturity dates are 2018-2047.


(2)	Maturity dates are 2017-2047.


(3)	Maturity dates are 2017-2066.

The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales:



SALES OF SECURITIES
(Dollars in millions)
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
Proceeds from sales(1)	$	466		$	111		$	823		$	204
Gross realized gains	79			5			124			8
Gross realized losses	(3		)	(3		)	(8		)	(11		)

SALES OF SECURITIES
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
Proceeds from sales(1) $ 111 $ 127 $ 204 $ 221
Gross realized gains 5 4 8 6
Gross realized losses (3) (3) (11) (7)
(1) Excludes securities that are held to maturity.


(1)	Excludes securities that are held to maturity.

Net unrealized gains ~~(losses)~~and losses, as well as realized gains and losses that are reinvested in the NDT, are included in Regulatory Liabilities Arising from Removal Obligations on Sempra ~~Energy's~~Energy’s and SDG~~&E's~~&E’s Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.In the three months and six months ended June 30, 2017, sale and purchase activities in our NDT increased significantly compared to the same periods in 2016 as a result of continuing changes to our asset allocations initiated in the fourth quarter of 2016 to reduce our equity volatility, lower our duration risk, and increase exposure to municipal bonds and intermediate credit. This shift in our asset mix is intended to reduce the overall risk profile of the NDT in anticipation of significant cash withdrawals over the next 10 years to fund the SONGS decommissioning.

~~We provide additional information about SONGS in Note 11.~~

NOTE 10. ~~CALIFORNIA UTILITIES'~~ REGULATORY MATTERS

We discuss regulatory matters ~~affecting our California Utilities~~ in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and ~~details of any~~information about new matters below.

~~JOINT~~CALIFORNIA UTILITIES MATTERS

CPUC General Rate Case ~~(GRC)~~

The CPUC uses a ~~general rate case~~GRC proceeding to set sufficient rates to allow the California Utilities to recover their reasonable cost of ~~operations and maintenance~~O&M 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. In September 2015, the California Utilities filed settlement agreements with the CPUC to resolve all material matters related to the proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through tax repair deductions, discussed below. The settlement agreements were with eight of eleven intervening parties.

In June 2016, the CPUC issued ~~a final decision~~the 2016 GRC FD, the details of which are discussed in Note 14 of the Notes to Consolidated Financial Statements in the 2016 GRC. The final decision (2016 GRC FD) adopts substantially all of the terms of the settlement agreements entered into between SDG&E and SoCalGas and eight of the eleven intervening parties in the 2016 GRC.Annual Report. The 2016 GRC FD adopts two revenue requirement changes, the first of which, relating to the extension of bonus depreciation, is the only significant change to the settlement agreements. The second revenue requirement adjustment relates to income tax benefits associated with flow-through repair deductions (the settling parties did not reach agreement on this second matter). With these adjustments, the final decision adopts a 2016 revenue requirement of $1.791 billion for SDG&E, which is $20 million less than the $1.811 billion proposed in the settlement agreements. For SoCalGas, the final decision's adjustments result in a 2016 revenue requirement of $2.204 billion, which is $15 million less than the $2.219 billion proposed in the settlement agreements. The 2016 GRC FD also requires certain refunds to be paid to customers and establishes a two-way income tax expense memorandum account, each discussed below.

Consistent with the settlement agreements, the 2016 GRC FD adopts subsequent annual escalation of the adopted revenue requirements by 3.5 percent for years 2017 and 2018 and continuation of the Z-Factor mechanism for qualifying cost recovery. The Z-Factor mechanism allows the California Utilities to seek cost recovery of significant cost increases, under certain unforeseen circumstances, incurred between GRC filings, subject to a $5 million deductible per event. Also, the 2016 GRC FD denies a separate agreement between the ORA and the California Utilities requesting a four-year GRC period and instead adopts a three-year GRC period (through 2018).

~~The California Utilities recorded revenues in the first quarter of 2016 based on levels authorized for 2015 under the 2012 GRC, because a final decision in the 2016 GRC~~ was ~~not issued by March 31, 2016. The 2016 GRC FD is~~ effective retroactive to January 1, ~~2016,~~2016. SDG&E and ~~the California Utilities~~SoCalGas recorded ~~the retroactive impacts in the second quarter of 2016. For SoCalGas and SDG&E, these amounts include an incremental after-tax earnings impact of $12~~$9 million and $9 million, respectively, related to the first quarter of 2016. The adopted revenue requirements associated with the seven-month period through July 2016 will be recovered in rates over a 17-month period, beginning August 2016. At June 30, 2016, SoCalGas is reporting on its Condensed Balance Sheet a regulatory asset of $60 million, with $21 million as noncurrent, representing the retroactive revenue from the 2016 GRC FD from January 1 through June 30, 2016 to be recovered in rates through December 2017. At June 30, 2016, SDG&E is reporting on its Condensed Consolidated Balance Sheet a regulatory asset of $23 million, with $8 million as noncurrent, representing the retroactive revenue from the 2016 GRC FD from January 1 through June 30, 2016 to be recovered in rates through December 2017.

The 2016 GRC FD results in certain accounting impacts associated with the income tax repairs deduction matter. In general, the 2016 GRC FD considers that the income tax benefits obtained from income tax repairs deductions exceeded amounts forecasted by the California Utilities from 2011 to 2015, and that they were attributed to shareholders during that time. The 2016 GRC FD reallocates the economic benefit of this tax deduction forecasting difference to ratepayers. Accordingly, revenues corresponding to income tax repair deductions that exceeded forecasted amounts relating to 2015, which have been tracked in memorandum accounts, are ordered to be refunded to customers. The 2015 amounts total $72 million for SoCalGas and $37 million for SDG&E. Pursuant to this refund requirement, SoCalGas and SDG&E recorded regulatory liabilities for these amounts, resulting in after-tax charges to earnings of $43 million and $22$12 million, respectively, in the second quarter of 2016 ~~(summarized below). In addition,~~for the 2016 GRC FD reduced rate base by $38 million at SoCalGas and $55 million at SDG&E. The corresponding reductions in the 2016 revenue requirement will be $5 million at SoCalGas and $7 million at SDG&E (which reductions are included in the adopted 2016 revenue requirement amounts described above). The rate base reductions reallocate to ratepayers the economic benefits associated with tax repair deductions that were previously providedretroactive after-tax earnings impact related to the ~~shareholders for the period~~first quarter of ~~2012-2014 for SoCalGas and 2011-2014 for SDG&E. The rate base reductions do not result in an impairment of any of our reported assets, but will impact our revenues and earnings prospectively.~~2016.

The 2016 GRC FD also requires us to notify the CPUC if the 2012-2015 repairs deductions estimated in this GRC are different from the actual repairs deductions for SDG&E and SoCalGas. SoCalGas and SDG&E recorded regulatory liabilities of $11 million and $15 million, respectively, related to 2012-2014, resulting in after-tax charges to earnings for these differences of $6 million and $9 million in the second quarter of 2016 for SoCalGas and SDG&E, respectively (summarized below). SDG&E and SoCalGas will record any adjustments necessary related to estimated 2015 amounts when the information to do so becomes available.

In July 2016, SDG&E, SoCalGas and the parties to the settlement agreements filed a joint motion indicating their agreement to accept the CPUC's adjustments to the original settlements with one additional change. The settlement parties agree that SDG&E and SoCalGas shall retain the right to seek further review and modification of the bonus depreciation adjustment made by the CPUC, so that SDG&E and/or SoCalGas can pursue relief in the form of full or partial restoration of the total revenue requirements reflected in the original settlement agreements. We expect CPUC action on the joint motion in the second half of 2016.

~~Following is a summary of immediate earnings impacts from the 2016 GRC FD recorded in the second quarter of 2016:~~

EARNINGS IMPACTS FROM THE 2016 GRC FD RECORDED IN THE SECOND QUARTER OF 2016
(Dollars in millions)
SoCalGas SDG&E
Pretax After-tax Pretax After-tax
earnings earnings earnings earnings
(charge) (charge) (charge) (charge)
Retroactive revenue requirement increase
    for the first quarter of 2016 $ 20 $ 12 $ 15 $ 9
Adjustments to revenue related to
    tax repairs deductions:
        Refund of 2015 memorandum account $ (72) $ (43) $ (37) $ (22)
        True-up of 2012-2014 estimates to actuals (11) (6) (15) (9)
        Total $ (83) $ (49) $ (52) $ (31)

~~Finally, the 2016 GRC FD requires~~required the establishment of a two-way income tax expense memorandum ~~account~~accounts to track any revenue ~~differences~~variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred by ~~the California Utilities~~SDG&E and SoCalGas from 2016 through 2018. The ~~differences~~variances to be tracked ~~are to specifically~~ include tax expense differences relating toto:

§
▪	net revenue changes;

§
▪	mandatory tax law, tax accounting, tax procedural, or tax policy changes; and

§
▪	elective tax law, tax accounting, tax procedural, or tax policy changes.

~~The account will remain open, and the balance~~Starting in the account will be reviewed in subsequent GRC proceedings, until the CPUC decides to close the account. In July 2016, to address the implementation of the 2016 GRC FD, the California Utilities filed an advice letter to establish a two-way memorandum account to track revenue requirement differences resulting from the differences in the income tax expense forecasted in the GRC proceedings of SDG&E and SoCalGas and the income tax expense incurred by them during the GRC period. In the second quarter of 2016, SoCalGas and SDG&E ~~each recorded a liability~~began recording liabilities associated with tracking the differences in the income tax expense forecasted in the GRC proceedings and the income tax expense ~~that~~incurred. At June 30, 2017, the recorded liability associated with these tracked amounts totaled $41 million and $20 million for SoCalGas and SDG&E, ~~incurred~~respectively. The tracking accounts will remain open, and the balance in the accounts will be reviewed in subsequent GRC proceedings, until the CPUC decides to close them. As of June 2017, there have been no mandatory or elective tax law, tax accounting, tax procedural, or tax policy changes that could give rise to a regulatory liability and as such, no amount has been tracked related to these items.

SDG&E and SoCalGas are scheduled to file their next GRC applications (the 2019 GRC) in the third quarter of 2017. The applications, among other matters, will seek test year revenue requirements for 2019 and attrition year adjustments for 2020 and 2021. SDG&E and SoCalGas also expect to request a third attrition year adjustment for 2022. In June 2017, SDG&E and SoCalGas filed their first interim accountability reports comparing authorized and actual spending in 2014 and 2015 for certain safety-related activities. Similar data for 2016 will be provided with the 2019 GRC filings. The stated purpose of the interim accountability reports is to provide data and metrics for key safety and risk mitigation areas that will be reviewed in the 2019 GRC.

Risk Assessment Mitigation Phase Report

In December 2014, the CPUC issued a decision incorporating a risk-based decision-making framework into all future GRC application filings for major natural gas and electric utilities in California. The framework is intended to assist in assessing safety risks and the utilities’ plans to help ensure that such risks are adequately addressed. In advance of filing the California Utilities’ 2019 GRC applications, two proceedings occurred: the Safety Model Assessment Proceeding and the RAMP. In the Safety Model Assessment Proceeding, the California Utilities demonstrated the models used to prioritize and mitigate risks in order for the ~~six-month period ended June 30, 2016, which resulted in after-tax charges~~CPUC to ~~earnings of $9 million ($15 million pretax)~~establish guidelines and standards for ~~SoCalGas and a negligible amount for SDG&E.~~

~~Natural Gas Pipeline Operations Safety Assessments~~these models.

In ~~June 2014,~~November 2016, as part of the new framework, SDG&E and SoCalGas filed their first RAMP report presenting a comprehensive assessment of their key safety risks and proposed activities for mitigating such risks. The report details these key safety risks, which include critical operational issues such as natural gas pipeline safety and wildfire safety, and addresses their classification, scoring, mitigation, alternatives, safety culture, quantitative analysis, data collection and lessons learned. As part of the new framework, funding for any incremental projects or activities is not addressed in the RAMP report and would be subsequently requested in the California Utilities’ upcoming GRC applications.

In March 2017, the CPUC’s Safety and Enforcement Division issued its evaluation report providing generally favorable feedback on the California Utilities’ RAMP report, but recommending more detailed analysis of the risks we presented in the report. The new GRC framework does not require the CPUC to adopt the RAMP report. Certain information from the RAMP report, including certain proposed projects and activities outlined therein, will be incorporated in the SDG&E and SoCalGas 2019 GRC applications to be filed in the third quarter of 2017.

CPUC Cost of Capital

On July 13, 2017, the CPUC issued a final decision ~~addressing~~adopting, with certain modifications, the joint petition filed in February 2017 by SDG~~&E's~~&E, SoCalGas, PG&E and ~~SoCalGas' Pipeline Safety Enhancement Plan (PSEP). Specifically, the~~Edison, along with ORA and TURN. The final decision ~~determined the following~~provides a two-year extension for ~~Phase 1~~each of the ~~program:~~

§	~~approved the utilities' model~~utilities to file its next respective cost of capital application, extending the filing date to April 2019 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 regulatory accounts authorized by the CPUC;

§	~~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 that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of June 30, 2016, SDG&E and SoCalGas have recorded PSEP costs of $15 million and $195 million, respectively, in the CPUC-authorized regulatory account.

In October 2014, SDG&E and SoCalGas filed a petition with the CPUC requesting authority to begin to recover PSEP costs from customers in the year in which the costs are incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of recovery of such costs in a subsequent2020 test year.

In July 2016, the CPUC issued a proposed decision addressing a number of outstanding requests and authorizing SoCalGas and SDG&E to recover, subject to refund pending reasonableness reviews, the revenue requirements associated with 50 percent of their incurred PSEP Phase 1 costs recorded to regulatory accounts; file two reasonableness review applications for Phase 1 projects completed through 2017; file a Phase 2 revenue requirement forecast application for costs to be incurred in 2017 and 2018; and include in their 2019 GRC applications, and any future GRCs, all other PSEP costs not the subject of prior applications. We expect the CPUC to issue a The final decision inalso reduces the ~~proceeding in the third quarter of 2016.~~

~~In December 2014,~~ROE for SDG&E from 10.30 percent to 10.20 percent and for 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. In June 2015, SDG&E and SoCalGas agreedfrom 10.10 percent to ~~remove certain projects~~10.05 percent, effective from the filing and defer their review to future proceedings when the projects are fully completed and, as a result, are now requesting recovery of $0.1 million and $26.8 million, respectively. The ORA, TURN and the Southern California Generation Coalition (SCGC) have recommended disallowances related to completed projects, as well as facilities build-out costs, de-scoped projects, and project management and consulting costs. We expect a decision on this application in the second half of 2016.

In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC's June 2014 final decision. In March 2015, the CPUC issued a decision denying the ORA's and TURN's second request for rehearing, but keeping the record open to admit additional evidence on the limited issue of pressure testing or replacing pipelines installed between January 1, ~~1956~~2018 through December 31, 2019. SDG&E’s and ~~July 1, 1961. The ORA and TURN allege that the CPUC made~~SoCalGas’ ratemaking capital structures will remain at current levels until modified, if at all, by 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 December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the averagefuture cost of pressure testing nor the undepreciated balance of abandoned pipelines. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. In May 2016, the CPUC issued a decision denying the request for rehearing. Through June 30, 2016, the after-tax disallowed costs for SoCalGas and SDG&E are $3.6 million and $0.5 million, respectively.

SoCalGas and SDG&E expect to file an application with the CPUC in the third quarter of 2016 for reasonableness review and rate recovery of certain pipeline safety projects recorded in their authorized regulatory accounts. SoCalGas and SDG&E expect a decision from the CPUC in 2017.

~~SDG&E MATTERS~~

~~SONGS~~

~~We discuss regulatory and other matters related to SONGS in Note 9.~~

~~Wildfire Claims Cost Recovery~~

In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of an estimated $379 million in costs related to the October 2007 wildfires that have been recorded to the Wildfire Expense Memorandum Account (WEMA). These costs represent a portion of the estimated total of $2.4 billion in costs and legal fees that SDG&E has incurred to resolve third-party damage claims arising from the October 2007 wildfires. The requested amount of $379 million is the net estimated cost incurred by SDG&E after deductions for insurance reimbursement ($1.1 billion), third party settlement recoveries ($824 million) and allocations to Federal Energy Regulatory Commission (FERC)-jurisdictional rates ($80 million), and reflects a voluntary 10 percent shareholder contribution applied to the net WEMA balance ($42 million). SDG&E requested a CPUCcapital decision by the ~~end~~CPUC. Also, the utilities will update their cost of ~~2016~~capital for actual cost of long-term debt through August 2017 and ~~is proposing to recover the~~forecasted cost through 2018, and update preferred stock costs ~~in rates over a six- to ten-year period. In April 2016, a ruling was issued establishing the scope and schedule~~ for ~~the proceeding, which~~anticipated issuances (if any) through 2018. The automatic CCM will be ~~managed~~ in two phases. Phase 1 will address SDG&E's operational and management prudence surrounding the 2007 wildfires. Phase 2 will address whether SDG&E's actions and decision-making in connection with settling legal claims in relationeffect to ~~the wildfires were reasonable. Evidentiary hearings in Phase 1 are scheduled to be held in January 2017, with a final decision scheduled to be issued in the second half~~adjust 2019 cost of ~~2017. The procedural schedule for Phase 2 will be determined after Phase 1 is concluded.~~

~~In September 2015, the presiding judge assigned~~capital, if necessary. Unless changed by the ~~FERC to SDG&E's annual Electric Transmission Formula Rate filing (TO4 Formula Cycle 2) issued an initial decision and an order on summary judgment that authorized SDG&E to recover all~~operation of the CCM, the updated costs ~~incurred~~of long-term debt and allocated to SDG&E's FERC-regulated operations, including $23.1 million of costs associated with the 2007 wildfires. In October 2015, the CPUC filed a request for rehearing of the FERC's September 2015 order, which requested abeyance of SDG&E's request to recover 2007 wildfire damage expenses. On April 21, 2016, the FERC affirmed its findings in the September 2015 order and denied the CPUC's request for rehearing. The FERC decision finalizes SDG&E's base transmission revenue requirementpreferred stock (if applicable) and the ~~recovery of $23.1 million of wildfire damage expenses allocated to SDG&E's FERC-regulated operations.~~new ROEs will remain in effect through December 31, 2019.

~~We provide additional information about wildfire litigation costs and their recovery in Note 11.~~

~~SOCALGAS MATTERS~~

~~Aliso Canyon Natural Gas Storage Facility~~

~~We discuss various regulatory matters regarding the Aliso Canyon natural gas storage facility and leak in Note 11.~~

~~Natural Gas Procurement~~

In June 2016, SoCalGas filed an application for a gas cost incentive mechanism award of $5 million for natural gas procured for its core customers during the 12-month period ended March 31, 2016. We expect a CPUC decision in the first half of 2017.

~~CALIFORNIA UTILITIES — MAJOR PROJECTS~~

We discuss the California Utilities' major projects in detail in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and details in the tables below.

~~MAJOR PROJECTS – UPDATES~~


~~Joint Utilities Projects~~
~~Southern Gas System Reliability Project (North-South Pipeline)~~
§	~~In July 2016, the CPUC issued a final decision which denies the California Utilities' request for a permit to construct.~~
§	In June 2016, SoCalGas recorded an after-tax impairment charge of $13 million for the development costs it had invested in the project. The pretax charge of $21 million is included in Operation and Maintenance on Sempra Energy's and SoCalGas' Condensed Consolidated Statements of Operations. We expect to make a filing to the CPUC seeking recovery of all or a portion of these costs.
~~Pipeline Safety & Reliability Project~~
§	SDG&E and SoCalGas filed an amended application with the CPUC in March 2016 providing detailed analysis and testimony supporting the proposed project. The revised request also presents additional information on the costs and benefits of project alternatives, safety evaluation and compliance analysis, and statutory and procedural requirements. SDG&E and SoCalGas seek approval to construct the proposed project, estimated at a cost of $633 million, and authority to recover the associated revenue requirement in rates.

~~SDG&E Projects~~
~~Cleveland National Forest (CNF) Transmission Projects~~
§	In March 2016, the U.S. Forest Service issued a final decision authorizing issuance of the CNF Master Special Use Permit renewing SDG&E's land rights and authorizing the construction, operation and maintenance of facilities located on national forest lands for the next 50 years, as well as approving the majority of the fire-hardening activities proposed by SDG&E.
§	In May 2016, the CPUC issued a final decision granting SDG&E a permit to construct. The project will be installed at an estimated cost of $680 million: $470 million for the various transmission-level facilities and $210 million for associated distribution-level facilities, including distribution circuits and additional undergrounding required by the final environmental impact statement. In July 2016, the Cleveland National Forest Foundation and the Protect Our Communities Foundation filed a joint application for rehearing of the final decision.
~~Sycamore-Peñasquitos Transmission Project~~
§	March 2016 final environmental impact report (EIR) recommended an alternative that undergrounds more of the project than originally proposed, and is viewed as environmentally superior. The CPUC may consider this alternative.
§	The recommended alternative in the EIR has an estimated cost of $250 million to $300 million, compared to the original project cost estimate of $120 million to $150 million, and would also delay the project schedule by approximately 10 months.
§	~~CPUC decision expected in the second half of 2016.~~
~~South Orange County Reliability Enhancement~~
§	CPUC issued its final EIR for the project in April 2016. The EIR concluded that an alternative project is considered environmentally superior to SDG&E's proposal. The final EIR states that the CPUC is not required to adopt the environmentally superior alternative if there are overriding considerations in favor of another alternative. The CPUC will consider the findings in determining whether to approve SDG&E's proposed project or an alternative to it.
§	~~Final CPUC decision expected in the second half of 2016.~~
~~Energy Storage Projects~~
§	SDG&E filed an advice letter with the CPUC in July 2016 seeking approval to own and operate two energy storage projects totaling 37.5 MW. The purpose of the two projects is to enhance electric reliability in the San Diego service territory.
§	~~We expect a CPUC resolution later in 2016.~~

NOTE 11. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

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 June 30, ~~2016, Sempra Energy's~~2017, accrued liabilities for legal proceedings, including associated legal fees and costs of litigation, ~~on a consolidated basis,~~ were ~~$44 million. At June 30, 2016, accrued liabilities~~$10 million for ~~legal proceedings were $21~~Sempra Energy Consolidated, including $3 million for SDG&E and ~~$21~~$5 million for SoCalGas. Amounts for Sempra Energy and SoCalGas include ~~$21~~$5 million for matters related to the Aliso Canyon natural gas storage facility gas leak, which we discuss below.

SDG&E

2007 Wildfire Litigation

In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E "power line caused" and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications' (Cox) fiber optic cable came into contact with an SDG&E power line "causing an arc and starting the fire." A September 2008 staff report issued by the CPUC's Consumer Protection and Safety Division, now known as the Safety and Enforcement Division, 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.

Numerous parties 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 asserted various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines. SDG&E has resolved ~~almost~~ all ~~of these lawsuits. One case~~litigation associated with three wildfires that occurred in October 2007, except one appeal that remains ~~subject to a damages-only trial, where the value of any compensatory damages resulting from the fires will be determined. Two appeals are~~ pending after judgment in the trial court. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but could receive additional settlement demands and damage estimates from the remaining plaintiff until the case is resolved. SDG&E ~~establishes~~maintains reserves for the wildfire litigation and makes adjustments to these reserves as information becomes available and amounts are estimable.

SDG&E ~~has concluded~~continues to conclude 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, at June 30, ~~2016,~~2017, Sempra Energy and SDG&E have recorded assets of ~~$355~~$350 million in Regulatory Assets (long-term) and Other Regulatory Assets (long-term), respectively, on their Condensed Consolidated Balance Sheets ~~including $353 million~~ related to CPUC-regulated operations, which represents the amount substantially equal to the aggregate amount it has paid and 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. Onoperations. In September ~~25,~~ 2015, SDG&E filed an application with the CPUC seeking authority to recover these CPUC-related costs ~~as we discuss~~ in ~~Note 10.~~ rates over a six- to ten-year period. The requested amount is the net estimated CPUC-related cost incurred by SDG&E after deductions for insurance reimbursement and third party settlement recoveries, and reflects a voluntary 10-percent shareholder contribution applied to the net Wildfire Expense Memorandum Account balance. In April 2016, the CPUC issued a ruling establishing the scope and schedule for the proceeding, which will be managed in two phases. Phase 1 addresses SDG&E’s operational and management prudence surrounding the 2007 wildfires. We expect a Phase 1 draft decision from the CPUC in the second half of 2017. Phase 2 will address whether SDG&E’s actions and decision-making in connection with settling legal claims in relation to the wildfires were reasonable, with a final CPUC decision expected by early 2019.

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 June 30, ~~2016,~~2017, the resulting after-tax charge against earnings would have been up to approximately ~~$210~~$207 million. A failure to obtain substantial or full recovery of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on SDG&E’s and Sempra ~~Energy's and SDG&E's~~Energy’s results of operations and cash flows.

We ~~provide additional information about excess wildfire claims cost recovery and related CPUC actions in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report and~~ discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

~~Smart Meters Patent Infringement Lawsuit~~Concluded Matter

~~In October 2011,~~ SDG&E ~~was sued by~~participated as a ~~Texas design~~claimant and ~~manufacturing company~~respondent in Federal District Court, Southern District of California, and later transferred to the Federal District Court, Western District of Oklahoma as part of Multi-District Litigation (MDL) proceedings, 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 sought injunctive relief and recovery of unspecified amounts of damages. The third party vendor has settled the lawsuit without cost to SDG&E, and a dismissal was entered in federal court on July 20, 2016.

~~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 initiated by Edison in October 2013 against MHI seeking damages stemming from the failure of the MHI replacement steam generators. In late December 2013, MHI answered and filed a counterclaim 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 participated in the arbitration as a claimant and respondent~~. The arbitration hearing concluded~~generators at the ~~end~~SONGS nuclear power plant. In March 2017, the Tribunal found MHI liable for breach of ~~April 2016, and a decision could come as early as this year.~~

~~Rim Rock Wind Farm~~

In 2011, the CPUC and FERC approved SDG&E's estimated $285 million tax equity investment in a wind farm project and its purchase of renewable energy credits from that project. SDG&E's contractual obligations to both invest in the Rim Rock wind farm and to purchase renewable energy credits from the wind farm under the power purchase agreement werecontract, subject to a contractual limitation of liability, but determined that MHI was the ~~satisfaction~~prevailing party and awarded it 95 percent of ~~certain conditions which, if not achieved, would allow SDG&E to terminate the power purchase agreement~~its arbitration costs. We discuss this arbitration and ~~not make the investment.~~

In December 2013, SDG&E and the project developer began litigating claims against each other regarding whether the project developer had timely satisfied all contractual conditions necessary to trigger SDG&E's obligations to investdecision further in the project and purchase renewable energy credits. On February 11, 2016, SDG&E, the project developer and several of the project developer's parent and affiliated entities entered into a conditional settlement agreement, which was approved by the CPUC in July 2016 and will become final and non-appealable 30 days after the CPUC approval, provided that no party requests rehearing. Under the settlement agreement, among other things, the parties agreed to terminate the tax equity investment arrangement, continue the power purchase agreement for the wind farm generation and release all claims against each other, while generally continuing the other elements of the 2011 approved decision. The settlement agreement will result in a $39 million credit to ratepayers.

Note 9.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

On October 23, 2015, SoCalGas discovered a leak at one of its ~~injection and withdrawal~~injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility, located in the northern part of the San Fernando Valley in Los Angeles County. The Aliso Canyon natural gas storage facility has been operated by SoCalGas since 1972. SS25 is ~~more than one mile away from and 1,200 feet above the closest homes. It is~~ one of more than 100 ~~injection and withdrawal~~injection-and-withdrawal wells at the storage facility.

Stopping the Leak, and Local Community Mitigation Efforts.SoCalGas worked closely with several of the ~~world's~~world’s leading experts to stop the leak, ~~including planning~~ and ~~obtaining all necessary approvals for drilling relief wells. On~~on February 18, 2016, ~~the California Department of Conservation's Division of Oil, Gas, and Geothermal Resources (DOGGR)~~DOGGR confirmed that the well was permanently sealed.

~~On December 24, 2015, by~~Pursuant to a stipulation and ~~court~~ order ~~SoCalGas agreed to implement a formal plan for assisting residents in~~by the ~~nearby community to temporarily relocate, as well as to pay for additional overtime and costs associated with extra~~ Los Angeles ~~Police Department security patrols, among other things.~~County Superior Court, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. ~~In addition, SoCalGas provided air filtration and purification systems to those residents~~Following the permanent sealing of the well, the DPH conducted indoor testing of certain homes in the ~~nearby~~Porter Ranch community, ~~requesting them.~~

As a result of receiving the confirmation from DOGGR that SS25 was permanently sealed, SoCalGas started winding down its temporary relocation support in accordance with the terms of the formal relocation plan. Subject to certain exceptions, the period for temporary relocation support to residents who temporarily relocated to short-term housing, such as hotels, was scheduled to end on February 25, 2016. This deadline was challenged by the Los Angeles County Department of Public Health (DPH), which contendedand concluded that indoor ~~testing was required to determine whether~~conditions did not present a long-term health risk and that it was safe for residents to return home.

In mid-March 2016, a third party engaged by SoCalGas conducted screening of indoor air for methane and mercaptans (odorants added to natural gas) in 71 houses in the Porter Ranch community near the Aliso Canyon storage facility. No mercaptans were detected in this screening, and concentrations of methane were well below levels of concern as established by the California Environmental Protection Agency's Department of Toxic Substances Control. On March 24,May 2016, the DPH released its indoor sampling work plan to test approximately 100 houses for a broad range of chemicals, including volatile organic compounds, semi-volatile organic compounds, metals, and sulfur compounds in the air and on surfaces. These substances are commonly found in households at varying levels.

~~On April 27, 2016, the California~~Los Angeles County Superior Court ~~issued an order extending~~ordered SoCalGas to offer to clean residents’ homes at SoCalGas’ expense as a condition to ending the relocation ~~support term pending~~program. SoCalGas completed the ~~completion of the DPH's indoor testing. The DPH took samples from more than 100 homes~~residential cleaning program and certain schools, as well as 11 "control" homes outside the Porter Ranch Community, and tested for over 250 chemical substances, and on May 13, 2016 issued its report of the results, which concluded that the testing did not detect chemicals at levels that presented an elevated health risk, and that the occurrence of air contaminants was consistent with background levels for indoor settings. The DPH's report stated that certain metals had been detected in surface dust in a small number of homes tested. Although the levels of any such metals were found to be significantly below levels established as safe by the U.S. Environmental Protection Agency (EPA) and even though such metals were also found in homes outside the Porter Ranch Community that were tested as a control group, the DPH nevertheless asserted that the detection of such substances required the homes of relocated residents to be cleaned before the relocation program ~~could end.~~

In response, the Superior Court issued an order on May 20, 2016, as supplemented by the Superior Court on May 25, 2016, ruling that: (1) currently relocated residents be given the choice to request residence cleaning, to be performed according to the DPH's proposed protocol and at SoCalGas' expense, and (2) the relocation program for currently relocated residents would terminate. In accordance with the May 20 and May 25 orders, SoCalGas finished cleaning all homes covered by this order onended in July ~~6, 2016, or approximately 1,500 homes. As of July 24, 2016, the relocation program has ended.~~2016.

Apart from the Los Angeles County Superior Court order, onin May ~~13,~~ 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 ~~have~~ participated in the relocation program, or who are located within a ~~five mile~~five-mile radius of the Aliso Canyon natural gas storage facility and have experienced symptoms from the natural gas leak (the Directive). SoCalGas ~~does not believe~~disputes the Directive, contending that ~~the DPH has the authority to issue the Directive~~it is invalid and unenforceable, and has filed a petition for writ of mandate to set ~~aside the Directive.~~it aside.

The total costs incurred to remediate and stop the leak and to mitigate local community impacts are significant and may increase, and we may be subject to potentially significant damages, restitution, and civil, administrative and criminal fines, costs or other penalties. To the extent any of these costs are 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'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of operations.

Cost Estimates and Accounting Impact. AtAs of June 30, ~~2016,~~2017, SoCalGas recorded estimated costs of ~~$717~~$832 million related to the leak. Of this amount, approximately ~~70 percent~~two-thirds is for the temporary relocation program (including cleaning costs and certain labor costs) ~~and approximately 15 percent is~~. Other estimated costs include amounts for ~~attempts~~efforts to control the well, stop the leak, stop or reduce the emissions, and the estimated cost of the root cause analysis being conducted by an independent third party to ~~determine~~investigate the cause of the leak. The remaining portion of the ~~$717~~$832 million includes ~~estimated~~ legal costs ~~necessary~~incurred to defend litigation, the value of lost gas, the costs to mitigate the actual natural gas released, and other costs. As the value of lost gas reflects the current replacement cost, the value may fluctuate until such time as replacement gas is purchased and injected into storage. SoCalGas ~~made a commitment in December 2015 to mitigate~~adjusts its estimated total liability associated with the ~~actual natural gas released and has been working on a plan to accomplish the mitigation.~~leak as additional information becomes available. The ~~$717~~$832 million represents ~~management's~~management’s best estimate of these costs related to the leak. Of these costs, a substantial portion has been paid and ~~$117~~$63 million is ~~recorded~~accrued as Reserve for Aliso Canyon Costs atas of June 30, ~~2016~~2017 on ~~SoCalGas'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after June 30, ~~2016.~~2017.

AtAs of June 30, ~~2016,~~2017, we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the leak of ~~$679~~$554 million as Insurance Receivable for Aliso Canyon Costs on ~~SoCalGas'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s Condensed Consolidated Balance Sheets. This amount is net of insurance retentions and ~~$34~~$273 million of insurance proceeds we received ~~in the second quarter of 2016~~through June 30, 2017 related to ~~control of well expenses.~~control-of-well expenses and temporary relocation costs. If we were to conclude that this receivable or a portion of it was no longer probable of recovery from insurers, some or all of this receivable would be charged against earnings, which could have a material adverse effect on SoCalGas’ and Sempra ~~Energy's and SoCalGas'~~Energy’s cash flows, financial condition and results of operations.

The above amounts do not include any unsettled damage ~~awards,~~claims, restitution, or ~~any~~ civil, administrative or criminal fines, costs or other penalties that may be imposed in connection with the incident or our responses thereto, as it is not possible to predict the outcome of any ~~criminal~~civil or ~~civil~~criminal proceeding or any administrative action in which such damage awards, restitution or civil, administrative or criminal fines, costs or other penalties could be imposed, and any such amounts, if awarded or imposed or otherwise paid, cannot be

reasonably estimated at this time. In addition, the recorded amounts above ~~amounts~~ do not include the ~~cost~~costs to clean additional homes ~~as directed by~~pursuant to the ~~DPH~~Directive, future legal costs necessary to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate.

OnIn March ~~17,~~ 2016, the CPUC ~~issued a decision directing~~ordered SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon natural gas storage ~~field.~~facility and, in September 2016, approved SoCalGas’ request to begin tracking these revenues as of March 17, 2016. The CPUC will determine at a later time whether, and to what extent, the authorized revenues tracked ~~revenues~~in the memorandum account may be refunded to ratepayers. ~~Pursuant to the CPUC's decision, on March 24, 2016, SoCalGas filed an advice letter requesting to establish a memorandum account to track all business-as-usual costs to own~~

Insurance. Excluding directors and operate the Aliso Canyon storage field, which has been protested by TURN and SCGC. On April 22, 2016, the CPUC's Energy Division issued a suspension notice for SoCalGas' advice letter citing the need for additional time for staff review.

~~Insurance.~~ Weofficers liability insurance, we have ~~at least~~ four kinds of insurance policies that together provide ~~in excess of $1~~between $1.2 billion to $1.4 billion in insurance ~~coverage.~~coverage, depending on the nature of the claims. We cannot predict all of the potential categories of costs or the total amount of costs that we may incur as a result of the leak. ~~In reviewing each of our policies, and subject~~Subject to various policy limits, exclusions and conditions, based ~~upon~~on what we know as of the filing date of this report, we believe that our insurance policies collectively should cover the following categories of costs: ~~the~~ costs incurred for temporary relocation (including cleaning costs and certain labor costs), costs to address the leak and stop or reduce emissions, the root cause analysis being conducted to ~~determine~~investigate the cause of the leak, the value of lost natural gas, ~~and estimated~~ costs incurred to mitigate the actual natural gas released, ~~the~~ costs associated with litigation and claims by nearby residents and businesses, ~~the cost~~any costs to clean additional homes ~~as directed by~~pursuant to the ~~DPH,~~Directive, and, in some circumstances depending on their nature and manner of assessment, fines and penalties. We have been communicating with our insurance carriers and, as discussed above, we ~~recently~~have received an insurance ~~payment~~payments for ~~control~~a portion of ~~well~~control-of-well expenses and a portion of temporary relocation costs. We intend to pursue the full extent of our insurance coverage for the costs we have incurred or may incur. There can be no assurance that we will be successful in obtaining insurance coverage for these costs under the applicable policies, and to the extent we are not successful itin obtaining coverage or these costs exceed the amount of our coverage, such costs could ~~result in~~have a material ~~charge against the earnings of SoCalGas~~adverse effect on SoCalGas’ and Sempra ~~Energy.~~Energy’s cash flows, financial condition and results of operations.

Our recorded estimate atas of June 30, ~~2016~~2017 of ~~$717~~$832 million of certain costs in connection with the Aliso Canyon natural gas storage facility leak may rise significantly as more information becomes available, and toany costs not included in our estimate could be material. 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 and SoCalGas' cash flows, financial condition and results of operations. In addition, any costs not included in the $717 million estimate could be material, and to the extent not covered by insurance (including any costs in excess of applicable policy limits), could have a material adverse effect on Sempra Energy's and SoCalGas'Energy’s cash flows, financial condition and results of operations.

Governmental Investigations and Civil and Criminal ~~Litigation~~. Litigation. Various governmental agencies, including ~~the~~ DOGGR, DPH, ~~South Coast Air Quality Management District (SCAQMD), California Air Resources Board (CARB),~~SCAQMD, CARB, Los Angeles Regional Water Quality Control Board, ~~(RWQCB),~~ California Division of Occupational Safety and Health, ~~(DOSH),~~ CPUC, ~~Pipeline and Hazardous Materials Safety Administration (PHMSA),~~PHMSA, EPA, Los Angeles County District ~~Attorney's~~Attorney’s Office and California Attorney ~~General's~~General’s Office, have investigated or are investigating this incident. OnOther federal agencies (e.g., the DOE and the U.S. Department of the Interior) investigated the incident as part of the joint interagency task force discussed below. In January ~~25,~~ 2016, ~~the~~ DOGGR and the CPUC selected Blade ~~Energy Partners~~ to conduct an independent analysis under their supervision and to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon natural gas storage facility gas leak. ~~We expect~~The timing of the root cause analysis ~~to be completed in late 2016 or early 2017, but~~is under the ~~timing is dependent on the~~control of Blade, DOGGR and the CPUC.

As of ~~July 28, 2016, 181~~August 3, 2017, 281 lawsuits, ~~have been filed (177~~including over 25,500 plaintiffs, are pending in the Los Angeles County Superior Court ~~2 in San Diego County Superior Court, and 2 in the United States District Court for the Southern District of California)~~ against SoCalGas, some of which have also named Sempra ~~Energy, and, in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, against certain officers and directors of Sempra Energy and/or SoCalGas.~~Energy. These various lawsuits assert causes of action for negligence, negligence per se, strict liability, property damage, fraud, public and private nuisance (continuing and permanent), trespass, ~~breach of fiduciary duties,~~ inverse condemnation, fraudulent concealment, unfair business practices and loss of consortium, ~~and violation of federal securities laws,~~ among other things, and additional litigation may be filed against us in the future related to this incident. ~~Many~~A complaint alleging violations of ~~these~~Proposition 65 was also filed. These complaints seek ~~class action status,~~ compensatory and punitive damages, civil penalties, injunctive relief, costs of future medical monitoring and ~~attorneys' fees.~~ attorneys’ fees, and several seek class action status. All of these cases, other than a matter brought by the Los Angeles County District Attorney, the federal securities class action and one of the shareholder derivative actions discussed below, are coordinated before a single court in the Los Angeles County Superior Court for pretrial management.

In addition to the lawsuits 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 certain of its directors in the SDCA, and six shareholder derivative actions alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas are pending, one in the SDCA and five in the coordination proceeding in the Los Angeles County Superior Court. In March 2017, the SDCA dismissed the shareholder derivative action pending in that court, ruling that the plaintiff did not have standing to pursue the alleged claims; the plaintiff did not seek to amend his complaint to cure its deficiencies. In June 2017, the SDCA dismissed the federal securities class action on the grounds the plaintiff failed to plead sufficient facts to establish a claim for securities fraud. In July 2017, the plaintiff filed an amended complaint, again alleging violation of the federal securities laws.

Pursuant to the ~~parties' agreement,~~coordination proceeding in the ~~court ordered that~~Los Angeles County Superior Court, in March 2017, the ~~individual~~individuals and business ~~entity plaintiffs would proceed by filing~~entities asserting tort and Proposition 65 claims filed a Second Amended Consolidated Master Case Complaint for Individual Actions, through which their separate lawsuits will be managed for pretrial purposes. The consolidated complaint asserts causes of action for

negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment, loss of consortium and violations of Proposition 65 against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, injunctive relief, costs of future medical monitoring, civil penalties (including penalties associated with Proposition 65 claims alleging violation of requirements for warning about certain chemical exposures), and attorneys’ fees.

In January 2017, pursuant to the coordination proceeding, two consolidated ~~master~~class action complaints were filed against SoCalGas and Sempra Energy, one ~~for~~on behalf of a putative class of persons and businesses who own or lease real property within a five-mile radius of the ~~individual tort cases,~~well (the Property Class Action), and a second on behalf of a putative class of all persons and entities conducting business within five miles of the facility (the Business Class Action). Both complaints assert claims for strict liability for ultra-hazardous activities, negligence and violation of California Unfair Competition Law. The Property Class Action also asserts claims for negligence per se, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action also asserts a claim for negligent interference with prospective economic advantage. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees.

Three actions filed by public entities are pending, as follows. These lawsuits are also included in the ~~class action cases. The Los Angeles City Attorney and~~coordination proceeding in the Los Angeles County ~~Counsel have also filed a complaint~~Superior Court. First, in July 2016, the County of Los Angeles, on behalf of itself and the people of the State of California, filed a complaint against SoCalGas in the Los Angeles County Superior Court for public nuisance, unfair competition, breach of franchise agreement, breach of lease, and ~~violation~~damages. This suit alleges that the four natural gas storage fields operated by SoCalGas in Los Angeles County require safety upgrades, including the installation of a sub-surface safety shut-off valve on every well. It additionally alleges that SoCalGas failed to comply with the ~~California Unfair Competition Law. The~~DPH Directive. It seeks preliminary and permanent injunctive relief, civil penalties, and damages for the County’s costs to respond to the leak, as well as punitive damages and attorneys’ fees.

Second, in August 2016, the California Attorney General, acting in ~~her~~an independent capacity and on behalf of the people of the State of California and the CARB, ~~joined this lawsuit. The~~together with the Los Angeles City Attorney, filed a third amended complaint ~~as amended includes allegations~~on behalf of the people of the State of California against SoCalGas alleging public nuisance, violation of the California Unfair Competition Law, violations of California Health and Safety Code sections 41700, prohibiting discharge of air contaminants that cause annoyance to the public, and 25510, requiring reporting of the release of hazardous material, as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties. ~~The SCAQMD also~~

Third, in March 2017, the County of Los Angeles filed a petition for writ of mandate against DOGGR and its State Oil and Gas Supervisor, as to which SoCalGas is the real party in interest. In July 2017, the County amended the petition to add the CPUC and its Executive Director. The petition alleges that in issuing its July 19, 2017 determination that the requirements for the resumption of injection operations have been met, discussed under “ Natural Gas Storage Operations and Reliability” below, DOGGR failed to comply with the provisions of SB 380, which requires a comprehensive safety review of the Aliso Canyon natural gas storage facility before injection of natural gas may resume. The County alleges, among other things, that DOGGR failed to comply with the provisions of SB 380 in declaring the safety review complete and authorizing the resumption of injection of natural gas into the facility before the root cause analysis was complete, failing to make its safety-review documents available to the public and failing to address seismic risks to the field as part of its safety review. The County further alleges that CEQA requires DOGGR to perform an Environmental Impact Review before the resumption of injection of natural gas at the facility may be approved. The petition seeks a writ of mandate requiring DOGGR and the State Oil and Gas Supervisor to comply with SB 380 and CEQA, and to produce records in response to the County’s Public Records Act request; as well as, declaratory and injunctive relief against any authorization to inject natural gas and attorneys’ fees. On July 24, 2017, the County filed an application for an immediate stay of DOGGR’s order, a temporary restraining order and order to show cause why a preliminary injunction should not be issued to stop the reopening of the facility. On July 28, 2017, the Superior Court denied the application on the ground that, pursuant to Public Utilities Code sections 714 and 1759(a), the CPUC has jurisdiction over regulating injections at the Aliso Canyon natural gas storage facility, and the Court therefore lacks jurisdiction to rule on the County’s application. On July 31, 2017, the County filed a petition for writ of mandate, prohibition, stay or other appropriate relief and a request for immediate stay in the Court of Appeal, seeking review of the Superior Court’s order denying the County’s application for a temporary restraining order. Later the same day, the Court of Appeal denied the County’s request for an immediate stay on injections.

A complaint filed by the SCAQMD against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the ~~leak. That suit seeks up~~leak was settled in February 2017, pursuant to ~~$250,000 in civil penalties for each day the violations occurred. On July 13, 2016, the SCAQMD amended its complaint~~which SoCalGas paid $8.5 million, of which $1 million is to ~~seek a declaration that SoCalGas is required~~be used to pay ~~the costs of~~for a ~~longitudinal study of the~~ health ~~of persons exposed to the gas leak.~~study. The SCAQMD’s complaint was dismissed in February 2017.

~~All of these cases, other than the derivative and securities law claims, are coordinated before a single court~~Separately, in February 2016, the Los Angeles County Superior Court for pretrial management. As ordered by the court in the coordination proceeding, on July 25, 2016, the individuals and business entities asserting tort claims filed a Consolidated Case Complaint for Individual Actions through which their separate lawsuits will be managed for pretrial purposes. The consolidated complaint asserts causes of action for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment and loss of consortium against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, property damage and diminution in property value, a temporary injunction, costs of future medical monitoring, and attorneys' fees.

~~On February 2, 2016, the Los Angeles~~ District ~~Attorney's~~Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section

2703(a), and for allegedly violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. ~~On February 16,~~In September 2016, SoCalGas ~~pled not guilty~~entered into a settlement agreement with the Los Angeles County District Attorney’s Office in which it agreed to plead no contest to the ~~complaint. No trial date has been set.~~

~~On July 25,~~notice charge under Health and Safety Code section 25510(a) and agreed to pay the maximum fine of $75,000, penalty assessments of approximately $233,500, and operational commitments estimated to cost approximately $5 million, reimbursement and assessments in exchange for the Los Angeles County District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint (collectively referred to as the District Attorney Settlement). In November 2016, SoCalGas completed the commitments and obligations under the District Attorney Settlement, and on November 29, 2016, the ~~County~~Court approved the settlement and entered judgment on the notice charge. Certain individuals residing near the Aliso Canyon natural gas storage facility who objected to the settlement have filed a notice of ~~Los Angeles, on behalf of itself and the people~~appeal of the ~~State of California, filed~~judgment, as well as a ~~complaint against SoCalGas in~~petition asking the Los Angeles County Superior Court ~~for public nuisance, unfair competition, breach of franchise agreement, breach of lease,~~to set aside the November 29, 2016 order and ~~damages. This suit alleges that the four natural gas storage fields operated or formerly operated by SoCalGas in~~grant them restitution. The Los Angeles County ~~require safety upgrades, including~~Superior Court dismissed the ~~installation of sub-surface safety shut-off valves on every well. It additionally alleges~~petition in January 2017, ruling that ~~SoCalGas failed to comply with~~ the ~~Directive. It seeks preliminary and permanent injunctive relief, civil penalties, and damages for the County's costs to respond to the leak, as well as punitive damages and attorneys' fees.~~petitioners have a remedy at law via their direct appeal.

The costs of defending against these civil and criminal lawsuits, ~~and~~ cooperating with these investigations, and any damages, restitution, and civil, administrative and criminal fines, costs and other penalties, if awarded or imposed, as well as the costs of mitigating the actual natural gas released, 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 receiving insurance recoveries, such costs could have a material adverse effect on ~~SoCalGas'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of operations.

Regulatory Proceedings. In February 2017, the CPUC opened a proceeding pursuant to SB 380 to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region. The proceeding will be conducted in two phases, with Phase 1 undertaking a comprehensive effort to develop the appropriate analyses and scenarios to evaluate the impact of reducing or eliminating the use of the Aliso Canyon natural gas storage facility and Phase 2 evaluating the impacts of reducing or eliminating the use of the Aliso Canyon natural gas storage facility using the scenarios and models adopted in Phase 1. In accordance with the Phase 1 schedule, public participation hearings began in April 2017, and workshops and additional public participation hearings are expected to occur later in 2017.

The order establishing the scope of the proceeding expressly excludes issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Aliso Canyon natural gas storage facility gas leak.

Section 455.5 of the California Public Utilities Code, among other things, directs regulated utilities to notify the CPUC if all or any portion of a major facility has been out of service for nine consecutive months. Although SoCalGas does not believe the Aliso Canyon natural gas storage facility or any portion of that facility has been out of service for nine consecutive months, SoCalGas provided notification in an abundance of caution to demonstrate commitment to regulatory compliance and transparency, and because the process for obtaining authorization to resume injection operations at the facility required longer to complete than initially contemplated. In response, and as required by section 455.5, the CPUC issued an OII to address whether the Aliso Canyon natural gas storage facility or any portion of that facility has been out of service for nine consecutive months pursuant to section 455.5, and if it is determined to have been out of service, whether the CPUC should adjust SoCalGas’ rates to reflect the period the facility is deemed to have been out of service. As required under section 455.5, if hearings on the investigation are necessary, they will be consolidated with SoCalGas’ next GRC proceeding. In the event that the CPUC determines that all or any portion of the facility has been out of service for nine consecutive months, the amount of any refund to ratepayers and the inability to earn a return on those assets could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Orders and Additional ~~Regulation and Reliability.~~ OnRegulation. In January 6, 2016, the Governor of the State of California issued ~~the Governor's~~an Order (the Governor’s Order) proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon natural gas storage facility. The ~~Governor's~~Governor’s Order ~~directs~~imposes various orders with respect to: stopping the ~~following:~~leak; protecting public health and safety; ensuring accountability; and strengthening oversight. Most of the directives in the Governor’s Order have been fulfilled, with the following remaining open items: (1) applicable agencies must convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; (2) the CPUC must ensure that SoCalGas covers costs related to the natural gas leak and its response, while protecting ratepayers, and CARB was ordered to develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas; and (3) DOGGR, CPUC, CARB and the CEC must submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California.

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~~Protecting Public Health and Safety~~: State agencies will: continue the prohibition against SoCalGas injecting any gas into the Aliso Canyon storage facility until a comprehensive review, utilizing independent experts, of the safety of the storage wells and the air quality of the surrounding community is completed; expand real-time monitoring of emissions in the surrounding community; convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; and take all actions necessary to ensure the continued reliability of natural gas and electricity supplies in the coming months during the moratorium on gas injections into the Aliso Canyon storage facility.

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~~Ensuring Accountability~~: The CPUC will ensure that SoCalGas covers costs related to the natural gas leak and its response, while protecting ratepayers; and CARB will develop a program to fully mitigate the leak's emissions of methane by March 31, 2016, with such program to be funded by SoCalGas.

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~~Strengthening Oversight~~: The DOGGR will promulgate emergency regulations for gas storage facility operators throughout the state, requiring: at least daily inspection of gas storage well heads using gas leak detection technology such as infrared imaging; ongoing verification of the mechanical integrity of all gas storage wells; ongoing measurement of annular gas pressure or annular gas flow within wells; regular testing of all safety valves used in wells; minimum and maximum pressure limits for each gas storage facility in the state; and a comprehensive risk management plan for each facility that evaluates and prepares for risks, including corrosion potential of pipes and equipment. Additionally, the DOGGR, CPUC, CARB and California Energy Commission (CEC) will submit to the Governor's Office a report that assesses the long-term viability of natural gas storage facilities in California.

In December 2015, SoCalGas made a commitment ~~in December 2015~~ to mitigate the actual natural gas released from the leak and has been working on a plan to accomplish the mitigation. OnIn March ~~31,~~ 2016, pursuant to the ~~Governor's~~Governor’s Order, the CARB issued its Aliso Canyon Methane Leak Climate Impacts Mitigation Program, which sets forth its recommended approach to achieve full mitigation of the emissions from the Aliso Canyon natural gas storage facility gas leak. The CARB program ~~preliminarily assumes that the leak released approximately 100,000 metric tons of methane. It states that full mitigation~~ requires that ~~the program generate~~ reductions in short-lived climate pollutants and other greenhouse gases be at least equivalent to ~~that~~the amount of the emissions from the leak, and that the ~~appropriate~~ global warming potential to be

used in deriving the amount of reductions required is based on a 20-year term ~~rather~~(rather than the 100-year term the CARB and other state and federal agencies use in regulating ~~emissions,~~emissions), resulting in a target of approximately ~~8,000,000~~9,000,000 metric tons of carbon dioxide equivalent. ~~CARB's~~CARB’s program also ~~requires~~provides that all of the mitigation is to occur in California over the next five to ten years without the use of allowances or offsets. In October 2016, CARB issued its final report concluding that the incident resulted in total emissions from 90,350 to 108,950 metric tons of methane, and asserting that SoCalGas should mitigate 109,000 metric tons of methane to fully mitigate the greenhouse gas impacts of the leak. We have not agreed ~~to this proposed formulation~~with CARB’s estimate of methane released and continue to work with CARB on ~~the~~developing a mitigation plan.

OnIn January ~~23,~~ 2016, the Hearing Board of the SCAQMD ordered SoCalGas to ~~among other things: stop all injections of~~take various actions in connection with injecting and withdrawing natural gas except as directed by the CPUC, withdraw the maximum amount of natural gas feasible in a contained and safe manner, subject to orders of the CPUC, and permanently seal the well once the leak has ceased; continuously monitor the well site with infrared cameras until 30 days after the leak has ceased; provide the public with daily air monitoring data collected by SoCalGas; provide the SCAQMD with certain natural gas injection, withdrawal and emissions data from the Aliso Canyon facility; prepare and submit to the SCAQMD for its approval an enhanced leak detection and reporting well inspection program for the Aliso Canyon facility; provide the SCAQMD with funding to develop a continuous air monitoring plan for the Aliso Canyon facility and the nearby schools and community; prepare and submit to the SCAQMD for its approval an air quality notification plan to provide notice to SCAQMD, other public agencies and the nearby community in the event of a future reportable release; and provide the SCAQMD with funding to conduct an independent health study on the potential impacts of exposure on the constituents of the natural gas released from the facility, as well as any odor suppressants used to mitigate odors from the leaking well.

~~On April 1, 2016, the Secretary of the U.S. Department of Energy (DOE) and PHMSA jointly announced the formation of an Interagency Task Force on Natural Gas Storage Safety in response to the leak~~ at Aliso Canyon to assess and make recommendations on best practices, response plans and safe operation of gas storage facilities. On June 22, 2016, President Obama signed the "Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016" or the "PIPES Act of 2016." Among other things, the PIPES Act: (1) requires PHMSA to issue, within two years of passage, "minimum safety standards for underground natural gas storage facilities;" (2) imposes a "user fee" on underground storage facilities as needed to implement the safety standards; (3) grants PHMSA authority to issue emergency orders and impose emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for hearing, if the Secretary of Energy determines that an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes or is causing an imminent hazard; (4) directs the Secretary of Energy to establish an Aliso Canyon Task Force comprised of representatives from the Department of Transportation (DOT), Department of Health and Human Services, EPA, Department of the Interior, Department of Commerce, FERC and representatives of state and local governments, as deemed appropriate by the Secretary and the Administrator. The Act expressly allows states to adopt more stringent standards for intrastate underground natural gas storage facilities if such standards are compatible with the minimum standards prescribed under the PIPES Act.

~~Within 180 days of enactment of the PIPES Act, the Task force is required to issue a report that includes: (1) an analysis and conclusion of the cause and contributing factors of~~ the Aliso Canyon natural gas ~~leak; (2) an analysis of measures taken~~storage facility, sealing the well, monitoring, reporting, safety and funding a health impact study, among other things (the Abatement Order). SoCalGas fulfilled its obligations under the Abatement Order to ~~stop~~ the ~~natural gas leak, with an immediate focus on other, more effective measures that could be taken; (3) an assessment~~satisfaction of the ~~impact~~SCAQMD and its Hearing Board, except for the condition that SoCalGas agree to fund the reasonable costs of a study of the ~~natural gas leak on~~ health ~~safety, and the environment, wholesale and retail electricity prices and the reliability~~impacts of the ~~bulk-power system; (4) an analysis of how Federal, State, and local agencies responded~~leak. Pursuant to the ~~natural gas leak; (5) recommendations on how to improve~~settlement agreement between the ~~response to a future leak~~SCAQMD and ~~coordination between appropriate Federal, State,~~SoCalGas described above, the SCAQMD agreed that the health study condition was satisfied and, ~~local agencies~~ in ~~response to future natural gas leaks; (6) an analysis of~~March 2017, the ~~potential for a similar natural gas leak to occur at other underground natural gas storage facilities in~~Hearing Board terminated the United States; (7) recommendations on how to prevent any future natural gas leaks; (8) recommendations regarding Aliso Canyon and other underground natural gas storage facilities located in close proximity to residential populations; (9) any recommendations on information that is not currently collected but that would be in the public interest to collect and distribute to agencies and institutions for the continued study and monitoring of natural gas storage infrastructure in the United States; and (10) any other recommendations, as appropriate.Abatement Order.

PHMSA, DOGGR, SCAQMD, EPA and CARB have each commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. ~~Regulations~~DOGGR issued ~~by DOGGR~~new regulations following the ~~Governor's~~Governor’s Order as ~~well as~~described above, and in 2016, the California ~~Senate Bill 380, which was~~Legislature enacted ~~on May 10, 2016, are discussed below.~~four separate bills providing for additional regulation of natural gas storage facilities. Additional hearings in the ~~State~~California Legislature, as well as with various other federal and state regulatory agencies, have been or ~~are expected to~~may be scheduled, additional legislation has been proposed in the ~~state legislature,~~California Legislature, and additional laws, orders, rules and regulations may be adopted. The Los Angeles County Board of Supervisors has formed a task force to review and potentially implement new, more stringent land use (zoning) requirements and associated regulations and enforcement protocols for oil and gas activities, including natural gas storage field ~~operations. Such new requirements~~operations, which could materially affect new or modified uses of the Aliso Canyon natural gas storage facility and other natural gas storage fields located in ~~the County, including review under the California Environmental Quality Act and mitigation of environmental impacts associated with new and modified uses of the fields.~~Los Angeles County.

Higher operating costs and additional capital expenditures incurred by SoCalGas as a result of new laws, orders, rules and regulations arising out of this incident or our responses thereto could be significant and may not be recoverable in customer rates, and ~~SoCalGas'~~such new laws, orders, rules and regulations could have a material adverse effect on SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of ~~operations may be materially adversely affected by any such new regulations.~~operation.

On June 10, 2016, DOSH issued four citations to SoCalGas alleging violations of various regulations, including that SoCalGas failed to ensure that testing and inspection of well casing and tubing at the Aliso Canyon storage facility complied with testing and inspection requirements, with total penalties of $60,800. On June 27, 2016, SoCalGas filed an appeal of all four citations on the grounds that no violations of the cited regulations occurred, the citations are all preempted by federal law, the citations were not issued in a timely manner, and two of the citations are duplicative.

~~Adoption of SB 380.~~ The California legislature has enacted and the Governor has signed Senate Bill (SB) 380, which among other things: (1) continues the prohibition against SoCalGas injecting any natural gas into the Aliso Canyon natural gas storage facility until a comprehensive review of the safety of the gas storage wells at the facility is completed in accordance with regulations adopted by the DOGGR, the State Oil and Gas Supervisor has made a safety determination and other required findings, at least one public hearing has been held in the affected community, and the Executive Director of the CPUC has issued a concurring letter regarding the Supervisor's determination of safety; (2) requires that all gas storage wells returning to service shall only inject or produce gas through the interior metal tubing and not through the annulus between the tubing and the well casing, which will result in diminished field production capability; (3) requires the CPUC, in consultation with various governmental agencies and other entities, to determine the range of working gas necessary in Aliso Canyon to ensure safety and reliability for the region and just and reasonable rates in California and publish a report that includes such range and the number of wells and associated injection and production capacity required; (4) requires seeking public comments on the report either through written comments or a workshop; and (5) requires the CPUC, no later than July 1, 2017, to open a proceeding to determine the feasibility of minimizing or eliminating use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region, and to consult with various governmental agencies and other entities in making its determination.

~~As required by SB 380, on June 28, 2016, the CPUC published the Report,~~ ~~Aliso Canyon Working Gas Inventory, Production Capacity, Injection Capacity, and Well Availability for Summer 2016 Reliability~~ ~~(SB 380 Report), which incorporates, and is based on the findings of, the~~ ~~Aliso Canyon Risk Assessment Technical Report~~ which was prepared by the staff of the CAISO, CEC, Los Angeles Department of Water and Power (LADWP), SoCalGas and the CPUC. In that report, among other things, the CPUC determined that SoCalGas would need a withdrawal capacity of 1.119 billion cubic feet (Bcf) per day to meet the reliability needs of customers. In addition, the CPUC directed SoCalGas to keep 17 specified wells that have completed the Phase I testing required by DOGGR available for reliability-related withdrawals.

Natural Gas Storage ~~Operations.~~ SoCalGas estimates that approximately 57 Bcf of natural gas has been delivered to customers from an initial starting point of approximately 77 Bcf of gas in storage on October 23, 2015 at the Aliso Canyon facility. SoCalGas completed its measurement of the natural gas lost from the leakOperations and calculated that approximately 4.62 Bcf of natural gas was released from the Aliso Canyon natural gas storage facility as a result of the leak. In January of 2016, the CPUC directed SoCalGas to retain a minimum of 15 Bcf of working natural gas to help ensure reliability of the system, with withdrawals permitted only to meet reliability needs under a limited set of circumstances. Effective February 5, 2016, the DOGGR issued Emergency Regulations that amended the California Code of Regulations to require all underground natural gas storage facility operators, including SoCalGas, to take further steps to help ensure the safety of their gas storage operations. On July 8, 2016, DOGGR issued a Discussion Draft of new permanent regulations for all storage fields in California.

Reliability.Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, 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'~~SoCalGas’ delivery system. SoCalGas calculated that approximately 4.62 Bcf of natural gas was released from the Aliso Canyon ~~represents 63 percent of SoCalGas' owned~~ natural gas storage ~~inventory capacity.~~facility as a result of the leak. SoCalGas ~~has~~did not ~~injected~~inject natural gas into the Aliso Canyon ~~since~~natural gas storage facility after October 25, 2015, pursuant to orders by DOGGR and the Governor, and in accordance with SB 380. Limited withdrawals of natural gas from the ~~Governor's Order, but~~Aliso Canyon natural gas storage facility have been made in ~~conflict~~2017 to augment natural gas supplies during critical demand periods.

The process to begin limited injection operations at the Aliso Canyon natural gas storage facility was initiated in November 2016, when SoCalGas submitted a request to DOGGR seeking authorization to resume injection operations at the Aliso Canyon natural gas storage facility. In accordance with SB 380, DOGGR held public meetings in the ~~CPUC's reliability-based direction, which requires injections~~affected community to ~~reach higher inventory levels prior~~provide the public an opportunity to comment on the ~~winter season.~~ safety review findings (the comment period has expired). Also, in April and June of 2017, SoCalGas advised the CAISO, CEC, CPUC and PHMSA of its concerns that the inability to inject natural gas into the Aliso Canyon natural gas storage facility poses a risk to energy reliability in Southern California.

On ~~March 4, 2016, the~~July 19, 2017, DOGGR issued its determination that the requirements of SB 380 for the resumption of injection operations, including all safety requirements, have been met. On the same date, the CPUC’s Executive Director issued his concurrence with that determination, and DOGGR issued its Order ~~1109,~~ ~~Order to~~to: Test and Take ~~Specific~~Temporary Actions ~~Regarding~~Upon Resuming Injection: Aliso Canyon Gas Storage ~~Facility (Safety Review Testing Regime). On April 7, 2016,~~Facility. The order lifted the prohibition on injection at the Aliso Canyon natural gas storage facility, subject to its requirements that SoCalGas ~~announced its safety framework~~conduct and report results of a leak survey and measurement of total site methane emissions before resuming injection operations, as well as other requirements after injection resumes. The CPUC additionally issued a directive to ~~comply with the DOGGR Order 1109, which consists~~SoCalGas to maintain a range of ~~phased testing for each of the active injection wells~~working gas in the Aliso Canyon natural gas storage facility at a target of 23.6 Bcf (approximately 28 percent of its maximum capacity), and at all times above 14.8 Bcf. DOGGR’s findings require SoCalGas to continue to operate the facility under restrictions that limit the rate at which it is able to withdraw natural gas from the field. The County of Los Angeles has filed a petition for writ of mandate seeking declaratory and injunctive relief and stay of DOGGR’s order lifting the prohibition against injecting natural gas at the facility. ~~SoCalGas will continue this moratorium~~On July 28, 2017, the Superior Court denied the County’s application for a temporary restraining order to block DOGGR’s order on ~~further injections until all required approvals have been obtained.~~

~~On April 5, 2016, four energy agencies—~~the ground that, pursuant to Public Utilities Code sections 714 and 1759(a), the CPUC ~~CEC, CAISO, and LADWP—issued an~~ has jurisdiction over regulating injections at the Aliso Canyon ~~Action Plan~~natural gas storage facility, and the Court therefore lacks jurisdiction to ~~Preserve Gas~~rule on the County’s application. On July 31, 2017, the County filed a petition for a writ of mandate, prohibition, stay or other appropriate relief and ~~Electric Reliability~~a request for immediate stay in the ~~Los Angeles Basin. In their Action Plan, the agencies recognized that: Aliso Canyon is critical to meeting peak demand in both winter and summer; the Greater Los Angeles region could face an estimated 16 days~~Court of ~~gas curtailments this upcoming summer—assuming no withdrawals of any~~Appeal, seeking review of the ~~15 Bcf held at Aliso Canyon;~~Superior Court’s order denying the County’s applica

tion for a temporary restraining order. Later the same day, the Court of Appeal denied the County’s request for an immediate stay on injections. We provide further detail regarding the County of Los Angeles’ suit above in “Governmental Investigations and ~~unless gas~~Civil and Criminal Litigation.” Also on July 19, 2017, the CEC released a letter to the CPUC indicating that its staff is ~~withdrawn from Aliso Canyon, 14 of these days are likely~~prepared to be large enough to interrupt natural gas service to electric generators located in the Los Angeles Basin. To help mitigate concerns about natural gas service reliability to customers, including related impacts on natural gas-fueled power generation, SoCalGas, SDG&E and 24 customer organizations filed a settlement agreementwork with the CPUC and other agencies on ~~April 29, 2016 regarding procedures~~a plan to ~~help deal with service reliability issues this upcoming summer.~~phase out the use of the Aliso Canyon natural gas storage facility within ten years. The ~~procedures, which address supply shortages~~CEC and ~~surpluses using temporarily modified Operational Flow Order (OFO) tariff provisions, were approved by~~other stakeholders will be providing input into the SB 380 proceeding underway at the CPUC ~~on June 9, 2016, and will be in place through no later than November 30, 2016. There can be no assurance~~ that ~~these measures will prevent gas curtailments or power outages during~~addresses the ~~period~~future of the Aliso Canyon ~~remains offline.~~natural gas storage facility. Having completed the steps outlined by state agencies in order to safely begin injections at the Aliso Canyon natural gas storage facility, as of July 31, 2017, SoCalGas resumed limited injections.

If the Aliso Canyon natural gas storage facility were determined to be ~~taken~~ out of service for any meaningful period of time or permanently closed, or if future cash flows were otherwise insufficient to recover its carrying value, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At June 30, ~~2016,~~2017, the Aliso Canyon natural gas storage facility has a net book value of ~~$441~~$582 million, including ~~$199~~$237 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'~~SoCalGas’ and Sempra ~~Energy's~~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, and ~~SoCalGas'~~could have a material adverse effect on SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of ~~operations, cash flows and financial condition may be materially adversely affected.~~

~~Other~~

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 six of the seven lawsuits for an amount that is not significant.

operations.

Sempra Mexico

Property Disputes and 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. In the second quarter of 2015, the Administrative Court of Baja California confirmed the municipality of Ensenada's ruling and dismissed the proceeding. 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)~~SEDATU in 2006 to issue a title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico challenged the ruling, due to lack of notification of the underlying process. ~~In November 2015, the Agrarian~~Both challenges are pending to be resolved by a Federal Court ~~denied Sempra Mexico's challenge, but the ruling does not affect any property rights. Another appeal filed by SEDATU is pending.~~in Mexico. Sempra Mexico expects additional proceedings regarding the ~~claims, although such proceedings are not related to the permit challenges referenced above.~~claims.

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. In September 2015, the Court granted Sempra ~~Energy's~~Energy’s motion for summary judgment and closed the case. ~~In October 2015, the~~The claimant ~~filed a notice of appeal of~~appealed the summary judgment and an earlier order dismissing certain of his causes of action. In July 2017, the Ninth Circuit Court of Appeal issued a ruling affirming the summary judgment and dismissal of his other causes of action, except one alleging theft of personal property in connection with the alleged eviction.

Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency ~~(SEMARNAT)~~ and 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~~environmental impact authorization 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 was filed with and rejected by the Mexican Communications and Transportation Ministry. In April 2015, the Federal court confirmed the Mexican Communications and Transportation Ministry's ruling denying the request to revoke the port concession and decided in favor of Energía Costa Azul.

Two real property cases have been filed against Energía Costa ~~Azul in which~~Azul. In one, the plaintiffs seek to annul the recorded property ~~titles~~title for ~~parcels~~a parcel on which the Energía Costa Azul LNG terminal is situated and to obtain possession of a different ~~parcels~~parcel that allegedly ~~sit~~sits in the same ~~place; one of these cases was dismissed in September 2013 at the direction of the state appellate court.~~place. A ~~third~~second 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. In January 2016, the second complaint was dismissed by the Federal Agrarian Court. Sempra Mexico expects further proceedings on ~~the remaining~~these two matters.

In 2015, the Yaqui tribe, with the exception of some members living in the Bácum community, granted its consent and a right-of-way easement agreement for the construction of the Guaymas-El Oro segment of IEnova’s Sonora natural gas pipeline that crosses its territory. Representatives of the Bácum community filed an amparo in Mexican Federal Court demanding the right to withhold consent for the project, the stoppage of work in the Yaqui territory and damages. The judge granted a suspension order that prohibited the construction through the Bácum community territory. Because the pipeline does not pass through the Bácum community, IEnova does not believe the order prohibited construction in the remainder of the Yaqui territory. As a result of the dispute, however, IEnova was delayed in the construction of the approximately 14 kilometers of pipeline that pass through territory of the Yaqui tribe. The CFE agreed to extend the deadline for commercial operations until the second quarter of 2017. Construction of the pipeline is complete, and commercial operations began in May 2017. The amparo remains pending.

In December 2012, Backcountry Against Dumps, Donna Tisdale and the Protect Our Communities Foundation filed a complaint in the SDCA seeking to invalidate the presidential permit issued by the DOE for Energía Sierra Juárez’s cross-border generation tie line

~~Sempra Natural Gas~~

~~Since April 2012,~~ connecting the Energía ~~total of 14 lawsuits have been filed against Mobile Gas~~Sierra Juárez wind project in ~~Mobile County Circuit Court alleging that~~Mexico to the electric grid in the ~~first half of 2008 Mobile Gas spilled tert-butyl mercaptan, an odorant added to natural gas for safety reasons, in Eight Mile, Alabama. Eleven~~United States. The suit alleged violations of the ~~lawsuits have been settled. A small percentage~~NEPA, the Endangered Species Act, the Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act. Plaintiffs filed a motion for summary judgment, which the court largely denied in September 2015. One NEPA claim, however, was not resolved – whether the Environmental Impact Statement’s assessment of alleged extraterritorial impacts of the ~~plaintiffs~~generation tie line in ~~these lawsuits did~~the United States on the environment in Mexico was inadequate (the “extraterritorial impact issue”) – and was the subject of additional briefing in 2016. On January 30, 2017, the Court issued a ruling on the extraterritorial impact issue and, contrary to its prior ruling, ruled that the Environmental Impact Statement was deficient for not ~~sign individual releases~~considering the effects in Mexico of both the U.S. and are expected to continue to pursue claims against Mobile Gas. The remaining three lawsuits, which include approximately 250 individual plaintiffs, allege nuisance, fraud and negligence causes of action, and seek unspecified compensatory and punitive damages. Under the termsMexican portion of the ~~agreement to sell 100 percent of~~generation tie line and the ~~outstanding equity of EnergySouth,~~wind farm itself. The Court has not yet made a decision on the ~~parent company of Mobile Gas, as discussed in Note 3, this litigation will be retained by Mobile Gas at the close of the transaction.~~

ultimate remedy, and a final judgment has not been entered.

Other Litigation

Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities, ~~LLP (RBS Sempra Commodities),~~ a limited liability partnership in the process of being liquidated. ~~The Royal Bank of Scotland plc (RBS),~~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)~~paid an £86 million assessment in October 2014 to HMRC for denied VAT refund claims ~~made by various businesses~~filed 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~~allowances by RBS ~~related to transactions by RBS Sempra Energy Europe (RBS SEE),~~SEE, a ~~former indirect~~ subsidiary of RBS Sempra ~~Commodities that was~~Commodities. RBS SEE has since been sold to JP ~~Morgan.~~Morgan and later to Mercuria Energy Group, Ltd. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid on certain carbon credit purchases 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~~After paying the 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~~First-Tier Tribunal. AsThe First-Tier Tribunal held a ~~condition of the appeal, RBS was required~~preliminary hearing in September 2016 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. RBS has asserted that HMRC's~~determine whether HMRC’s assessment was time-barred. ~~A preliminary~~In January 2017, the First-Tier Tribunal issued a decision in favor of HMRC concluding that the assessment was not time-barred. RBS has decided not to appeal the First-Tier Tribunal’s decision to the Upper Tribunal. There will be a hearing ~~is scheduled for September 19~~on the substantive matter regarding whether RBS knew or should have known that certain vendors in the trading chain did not remit their VAT to ~~21, 2016. In June~~HMRC.

During 2015, liquidators, ~~for three~~acting on behalf of ten companies (the Companies) that engaged in carbon credit trading via chains that included a company that RBS SEE traded with directly, filed a claim in the High Court of Justice asserting damages of £160 million against RBS and ~~RBS Sempra Commodities alleging~~Mercuria Energy Europe Trading Limited (the Defendants). The claim alleges that ~~RBS Sempra Commodities' and RBS SEE's~~the Defendants’ participation in ~~transactions involving~~ the ~~sale~~purchase and ~~purchase~~sale of carbon credits resulted in the ~~companies' incurring~~Companies’ carbon credit trading transactions creating a VAT liability they were unable to pay. ~~In October 2015,~~Trial of the ~~liquidators' counsel filed an amended claim adding seven additional trading companies to~~matter has been set for the ~~claim and asserting damages~~summer of £146 million for all 10 companies. Additionally, the claimants dropped RBS Sempra Commodities LLP as a defendant, adding the successor to RBS SEE and JP Morgan, Mercuria Energy Europe Trading Limited (Mercuria), in its stead.2018. JP Morgan has notified us that Mercuria Energy Group, Ltd. has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from ~~us.~~ us and RBS.

Our remaining ~~balance~~investment in RBS Sempra Commodities of $67 million at June 30, 2017 is accounted for under the equity ~~method. The investment balance of $67 million at June 30, 2016~~method and reflects remaining distributions expected to be received from the partnership as it is liquidated. The timing and amount of distributions may be impacted by these matters. ~~We discuss RBS Sempra Commodities further in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.~~

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 for any liability from the final resolution of these matters. 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.

CONTRACTUAL ~~AND OTHER~~ COMMITMENTS

We discuss below significant changes in the first six months of ~~2016~~2017 to contractual commitments discussed in Notes 1 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Contracts

Sempra ~~Natural Gas'~~LNG & Midstream’s natural gas purchase and transportation commitments have decreased by ~~$111~~$130 million since December 31, ~~2015,~~2016, primarily due to payments on existing contracts and changes in forward natural gas prices in the first six months of ~~2016.~~2017. Net future payments are expected to decrease by ~~$97 million in 2016, increase by $14~~$133 million in 2017 and ~~decrease~~increase by $8$2 million in 2018 ~~$16~~and $1 million ~~in 2019 and $4 million in 2020~~thereafter compared to December 31, ~~2015.~~2016.

In ~~the second quarter of~~May 2016, Sempra ~~Natural Gas~~LNG & Midstream permanently released certain pipeline capacity that it held with Rockies Express and ~~others. The effect~~others, which we discuss in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report. In May 2017, Sempra LNG & Midstream received settlement proceeds of $57 million from a breach of contract claim against a counterparty in bankruptcy court. Of the total proceeds, $47 million related to the charge we recorded in 2016 resulting from the permanent ~~capacity releases resulted in~~release of certain pipeline capacity. Sempra LNG & Midstream recorded the settlement proceeds as a ~~pretax charge of $206 million ($123 million after-tax), which is included in~~reduction to Other Cost of Sales on ~~the~~ Sempra ~~Energy~~Energy’s Condensed Consolidated Statement of Operations in the ~~three months and six months ended June 30, 2016. The charge represents an acceleration~~second quarter of costs that would otherwise have been recognized over the duration of the contracts. In connection with the capacity releases, Sempra Natural Gas has recorded $41 million in Other Current Liabilities and $118 million in Deferred Credits and Other on the Sempra Energy Condensed Consolidated Balance Sheet at June 30, 2016, representing the amounts by which Sempra Natural Gas' obligation to make future capacity payments is expected to exceed proceeds generated from the permanent capacity releases.

2017.

LNG Purchase Agreement

Sempra ~~Natural Gas~~LNG & Midstream has a purchase agreement for the supply of LNG to the Energía Costa Azul terminal. The ~~agreement~~commitment amount is ~~priced~~calculated using a predetermined formula based on ~~natural gas market indices.~~estimated forward prices of the index applicable from 2017 to 2029. At

June 30, 2017, the commitment amount is expected to decrease by $321 million in 2017, $42 million in 2018, $20 million in 2019, $21 million in 2020, $24 million in 2021 and $432 million thereafter (through contract termination in 2029) compared to December 31, 2016, reflecting changes in estimated forward prices since December 31, 2016 and actual transactions for the first six months of 2017. These LNG commitment amounts are based on the assumption that all cargoes, less those already confirmed to be diverted, under the agreement are delivered. Although this ~~contract~~agreement 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~~agreement by Sempra ~~Natural Gas.~~

~~Sempra Natural Gas' commitment under the~~ LNG purchase agreement, reflecting changes in forward prices since December 31, 2015 and actual transactions for the first six months of 2016, is expected to decrease by $196 million in 2016, increase by $61 million in 2017 and $13 million in 2018, decrease by $9 million in 2019 and $33 million in 2020 and increase by $108 million thereafter (through contract termination in 2029) compared to December 31, 2015. These amounts are based on forward prices of the index applicable to the contract from 2016 to 2028 and an estimated one percent escalation per year beyond 2028 through contract termination in 2029. The LNG commitment amounts above are based on the requirement for Sempra Natural Gas to accept the maximum possible delivery of cargoes under the agreement.& Midstream. Actual LNG purchases in the current and prior years have been significantly lower than the maximum ~~amounts possible~~amount provided under the agreement due to the customer electing to divert cargoes as allowed by the agreement.

Capital Leases – Power Purchase Agreements

In 2015, SDG&E entered into a CPUC-approved 25-year PPA with a peaker power plant facility. Construction of the peaker power plant facility was completed and delivery of contracted power commenced in June 2017, at which time we recorded a $500 million capital lease obligation on SDG&E’s and Sempra Energy’s Condensed Consolidated Balance Sheets. We discuss commitments related to this capital lease obligation in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

In the first quarter of 2017, SDG&E satisfied all of the conditions precedent for a CPUC-approved 20-year PPA with a 500-MW power plant facility that is under construction. Beginning with the initial delivery of the contracted power, scheduled in 2018, the PPA will be accounted for as a capital lease. Future minimum lease payments under the new PPA are as follows:



FUTURE MINIMUM PAYMENTS – POWER PURCHASE AGREEMENT
(Dollars in millions)
2017	$	—
2018	88
2019	105
2020	105
2021	105
Thereafter	1,706
Total minimum lease payments(1)	2,109
Less: interest(2)	(1,559		)
Present value of net minimum lease payments	$	550


(1)	This amount will be recorded over the life of the lease as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs, which are recovered in rates.


(2)	Amount necessary to reduce net minimum lease payments to estimated present value at the inception of the lease.

~~Asset Retirement Obligations~~The entities that own the peaker plant facilities are VIEs of which SDG&E is not the primary beneficiary. SDG&E does not have any additional implicit or explicit financial responsibility related to these VIEs.

Construction and Development Projects

SDG&E

~~Contractual~~In the first six months of 2017, significant net increases to contractual commitments ~~for asset retirement obligations~~ at SDG&E ~~SoCalGas~~were $41 million, primarily for construction and ~~Sempra Energy Consolidated increased~~infrastructure improvements for transmission systems. Net future payments under these contractual commitments are expected to increase by $21 million in 2017 and $26 million ~~$316~~in 2018, decrease by $8 million in 2019, increase by $7 million in 2020 and ~~$342~~$2 million ~~respectively, since~~in 2021, and decrease by $7 million thereafter compared to December 31, ~~2015, primarily for natural gas assets, as a result of updated cost studies completed for the 2016 General Rate Case filing. We discuss the 2016 General Rate Case in Note 10.~~

2016.

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. This insurance provides ~~$375~~$450 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~~$13 billion of ~~secondary financial protection (SFP).~~SFP. If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the ~~$375~~$450 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. In such case, SDG~~&E's~~&E’s contribution would be up to ~~$50.93~~$50.9 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~~maintain nuclear property ~~decontamination, and debris removal~~damage insurance ~~subject to a $2.5 million deductible for "each and every loss."~~that exceeds the minimum federal requirements of $1.06 billion. This insurance coverage is provided through ~~Nuclear Electric Insurance Limited (NEIL).~~NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to ~~$9.7~~$10.4 million of retrospective premiums based on overall member claims. ~~See~~All of SONGS’ insurance claims arising out of the failures of the MHI

replacement steam generators have been settled with NEIL, as we discuss in Note ~~9 under "Settlement with NEIL" for discussion~~13 of ~~an agreement between~~ the ~~SONGS co-owners and NEIL~~Notes to ~~settle all claims under~~Consolidated Financial Statements in the ~~NEIL policies associated with the SONGS outage.~~Annual Report.

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 NUCLEAR FUEL DISPOSAL

The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing 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 continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel. OnIn April ~~18,~~ 2016, Edison executed a spent fuel settlement agreement with the DOE for $162 million covering damages incurred from January 1, 2006 through December 31, 2013. In May 2016, Edison refunded SDG&E $32 million for its respective share of the damage award paid. In applying this refund, SDG&E recorded a $23 million reduction to the SONGS regulatory asset, an $8 million reduction of its nuclear decommissioning balancing account and a $1 million reduction in its SONGS ~~operation and maintenance~~O&M cost balancing account.

In September 2016, Edison filed claims with the DOE for $56 million in spent fuel management costs incurred in 2014 and 2015 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. In February 2017, the DOE reduced the request to approximately $43 million primarily due to reductions to the claimed fuel canister costs. SDG&E received its $9 million respective share of the claim from Edison in May 2017 and recorded the proceeds in balancing accounts or as reductions to regulatory assets for the benefit of ratepayers.

In October 2015, the California Coastal Commission approved ~~Edison's~~Edison’s application for the proposed expansion of an ~~Independent Spent Fuel Storage Installation (ISFSI)~~ISFSI at SONGS. The ISFSI expansion began construction in 2016 ~~will~~and is expected to be fully loaded with spent fuel by 2019 and ~~will~~to operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state.

We provide additional information about SONGS in Note 9 above and in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

CONCENTRATION OF CREDIT RISK

We maintain credit policies and systems designed to manage our overall credit risk. These policies include an evaluation of potential ~~counterparties'~~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.~~Peru.

As they become operational, projects owned or partially owned by Sempra ~~Natural Gas,~~LNG & Midstream, Sempra Renewables, Sempra South American Utilities and Sempra Mexico place significant reliance on the ability of their suppliers, customers and partners 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 12. 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 develops, owns and operates, or holds interests in, electric transmission, distribution and generation infrastructure in Chile and Peru.

▪

Sempra Mexico develops, owns and operates, or holds interests in, natural gas, ~~transmission pipelines~~electric, LNG, LPG, ethane and ~~propane~~liquid fuels infrastructure, and ~~ethane systems, a natural gas distribution utility, electric generation facilities (including wind), a terminal for the import of LNG, and~~has marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico. In February 2016, management approved a plan to market and sell the TdM natural gas-fired power plant located in Mexicali, Baja California, as we discuss in Note 3.

5.
▪	Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy ~~projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Nebraska, Nevada and Pennsylvania to serve~~generation facilities serving wholesale electricity markets in the United States.

▪

Sempra ~~Natural Gas~~LNG & Midstream 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, and natural gas pipelines and storage facilities, all within the United States. In ~~May~~September 2016, Sempra ~~Natural Gas completed the sale of its 25-percent interest in Rockies Express, as we discuss in Note 3. In April 2016, we entered into an agreement to sell~~LNG & Midstream sold EnergySouth, the parent company of Mobile Gas and Willmut Gas, ~~the two natural gas distribution utilities owned by Sempra Natural Gas, as we~~and in May 2016, sold its 25-percent interest in Rockies Express. We discuss these divestitures in Note ~~3. Sempra Natural Gas also owned and operated~~3 of the ~~Mesquite Power plant, a natural gas-fired electric generation asset,~~Notes to Consolidated Financial Statements in the ~~remaining 625-MW block of which was sold in April 2015.~~Annual Report.

~~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~~segment’s performance based on its contribution to Sempra ~~Energy's~~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'~~Utilities’ operations are based on rates set by the CPUC and the FERC. We describe the accounting policies of all of our segments in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.

The following tables show selected information by segment from our Condensed Consolidated Statements of Operations and Condensed Consolidated Balance Sheets. Amounts labeled as ~~"All other"~~“All other” in the following tables consist primarily of parent organizations.

SEGMENT INFORMATION
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
REVENUES
  SDG&E $ 992 46 % $ 972 41 % $ 1,983 41 % $ 1,938 38 %
  SoCalGas 617 29 780 33 1,650 35 1,828 36
  Sempra South American Utilities 385 18 389 16 785 16 778 15
  Sempra Mexico 147 7 152 6 285 6 315 6
  Sempra Renewables 6 ― 10 1 13 ― 18 1
  Sempra Natural Gas 90 4 155 7 220 5 352 7
  Adjustments and eliminations ― ― (1) ― ― ― (1) ―
  Intersegment revenues(1) (81) (4) (90) (4) (158) (3) (179) (3)
      Total $ 2,156 100 % $ 2,367 100 % $ 4,778 100 % $ 5,049 100 %
INTEREST EXPENSE
  SDG&E $ 48 $ 52 $ 96 $ 104
  SoCalGas 24 19 46 38
  Sempra South American Utilities 11 8 20 13
  Sempra Mexico 4 6 8 11
  Sempra Renewables ― 1 ― 2
  Sempra Natural Gas 10 23 22 44
  All other 74 65 146 128
  Intercompany eliminations (29) (35) (53) (67)
      Total $ 142 $ 139 $ 285 $ 273
INTEREST INCOME
  SoCalGas $ ― $ 3 $ ― $ 3
  Sempra South American Utilities 5 5 10 9
  Sempra Mexico 1 2 3 4
  Sempra Renewables ― 1 1 1
  Sempra Natural Gas 17 25 33 44
  Intercompany eliminations (17) (26) (35) (44)
      Total $ 6 $ 10 $ 12 $ 17
DEPRECIATION AND AMORTIZATION
  SDG&E $ 158 50 % $ 149 48 % $ 317 49 % $ 294 48 %
  SoCalGas 112 36 113 37 234 36 226 37
  Sempra South American Utilities 14 4 12 4 27 4 25 4
  Sempra Mexico 15 5 17 6 32 5 34 6
  Sempra Renewables 2 1 1 ― 3 1 3 ―
  Sempra Natural Gas 12 4 12 4 25 4 24 4
  All other 1 ― 3 1 4 1 4 1
      Total $ 314 100 % $ 307 100 % $ 642 100 % $ 610 100 %
INCOME TAX EXPENSE (BENEFIT)
  SDG&E $ 48 $ 54 $ 120 $ 142
  SoCalGas (29) 16 58 111
  Sempra South American Utilities 15 18 29 34
  Sempra Mexico (12) 5 29 13
  Sempra Renewables (9) (11) (21) (28)
  Sempra Natural Gas (99) 27 (124) 29
  All other (20) (11) (55) (40)
      Total $ (106) $ 98 $ 36 $ 261



SEGMENT INFORMATION
(Dollars in millions)
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
REVENUES
SDG&E	$	1,058		$	992		$	2,115		$	1,983
SoCalGas	770			617			2,011			1,650
Sempra South American Utilities	381			385			793			785
Sempra Mexico	273			147			537			285
Sempra Renewables	26			6			48			13
Sempra LNG & Midstream	122			90			254			220
Intersegment revenues(1)	(97		)	(81		)	(194		)	(158		)
Total	$	2,533		$	2,156		$	5,564		$	4,778
INTEREST EXPENSE
SDG&E	$	49		$	48		$	98		$	96
SoCalGas	26			24			51			46
Sempra South American Utilities	11			11			20			20
Sempra Mexico	20			4			52			8
Sempra Renewables	4			—			8			—
Sempra LNG & Midstream	9			10			20			22
All other	67			74			135			146
Intercompany eliminations	(27		)	(29		)	(56		)	(53		)
Total	$	159		$	142		$	328		$	285
INTEREST INCOME
Sempra South American Utilities	$	6		$	5		$	11		$	10
Sempra Mexico	3			1			5			3
Sempra Renewables	2			—			3			1
Sempra LNG & Midstream	12			17			29			33
Intercompany eliminations	(15		)	(17		)	(34		)	(35		)
Total	$	8		$	6		$	14		$	12
DEPRECIATION AND AMORTIZATION
SDG&E	$	166		$	158		$	329		$	317
SoCalGas	126			112			252			234
Sempra South American Utilities	13			14			26			27
Sempra Mexico	37			15			73			32
Sempra Renewables	10			2			19			3
Sempra LNG & Midstream	11			12			21			25
All other	5			1			8			4
Total	$	368		$	314		$	728		$	642
INCOME TAX EXPENSE (BENEFIT)(2)
SDG&E	$	54		$	48		$	144		$	113
SoCalGas	19			(29		)	117			54
Sempra South American Utilities	20			15			39			29
Sempra Mexico	102			(12		)	244			28
Sempra Renewables	(5		)	(9		)	(16		)	(22		)
Sempra LNG & Midstream	18			(99		)	19			(128		)
All other	(41		)	(20		)	(85		)	(72		)
Total	$	167		$	(106	)	$	462		$	2

SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
EQUITY EARNINGS (LOSSES)
Earnings (losses) recorded before tax:
   Sempra Renewables $ 11 $ 10 $ 18 $ 12
   Sempra Natural Gas 3 17 (26) 34
       Total $ 14 $ 27 $ (8) $ 46
Earnings (losses) recorded net of tax:
   Sempra South American Utilities $ ― $ ― $ 2 $ (1)
   Sempra Mexico 33 22 48 38
       Total $ 33 $ 22 $ 50 $ 37
EARNINGS (LOSSES)
   SDG&E $ 100 $ 126 $ 229 $ 273
   SoCalGas(2) (1) 70 194 284
   Sempra South American Utilities 43 45 81 86
   Sempra Mexico 57 50 74 97
   Sempra Renewables 12 19 25 32
   Sempra Natural Gas (149) 40 (185) 42
   All other (46) (55) (83) (82)
       Total $ 16 $ 295 $ 335 $ 732
Six months ended June 30,
2016 2015
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
   SDG&E $ 602 30 % $ 600 41 %
   SoCalGas 650 32 603 41
   Sempra South American Utilities 82 4 66 5
   Sempra Mexico 140 7 120 8
   Sempra Renewables 457 23 22 1
   Sempra Natural Gas 68 3 28 2
   All other 7 1 27 2
       Total $ 2,006 100 % $ 1,466 100 %
June 30, 2016 December 31, 2015
ASSETS
   SDG&E $ 17,039 40 % $ 16,515 40 %
   SoCalGas 13,086 30 12,104 29
   Sempra South American Utilities 3,486 8 3,235 8
   Sempra Mexico 3,925 9 3,783 9
   Sempra Renewables 1,838 4 1,441 4
   Sempra Natural Gas 5,396 13 5,566 13
   All other 803 2 734 2
   Intersegment receivables (2,698) (6) (2,228) (5)
       Total $ 42,875 100 % $ 41,150 100 %
EQUITY METHOD AND OTHER INVESTMENTS
   Sempra South American Utilities $ (1) $ (4)
   Sempra Mexico 548 519
   Sempra Renewables 827 855
   Sempra Natural Gas 818 1,460
   All other 75 75
       Total $ 2,267 $ 2,905
(1) Revenues for reportable segments include intersegment revenues of a negligible amount, $18 million, $27 million and $36 million for the three months ended June 30, 2016; $3 million, $35 million, $54 million and $66 million for the six months ended June 30, 2016; $3 million, $17 million, $24 million and $46 million for the three months ended June 30, 2015; and $5 million, $36 million, $49 million and $89 million for the six months ended June 30, 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2) After preferred dividends.



SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
EQUITY EARNINGS (LOSSES)
Earnings (losses) recorded before tax:
Sempra Renewables	$	16		$	11		$	18		$	18
Sempra LNG & Midstream	2			3			3			(26		)
Total	$	18		$	14		$	21		$	(8	)
Earnings (losses) recorded net of tax:
Sempra South American Utilities	$	—		$	—		$	1		$	2
Sempra Mexico	—			33			(9		)	48
Total	$	—		$	33		$	(8	)	$	50
EARNINGS (LOSSES)(2)
SDG&E	$	149		$	100		$	304		$	236
SoCalGas(3)	58			(1		)	261			198
Sempra South American Utilities	45			43			92			81
Sempra Mexico	(9		)	57			39			75
Sempra Renewables	23			12			34			26
Sempra LNG & Midstream	27			(149		)	28			(181		)
All other	(34		)	(46		)	(58		)	(66		)
Total	$	259		$	16		$	700		$	369
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E							$	763		$	602
SoCalGas							682			650
Sempra South American Utilities							77			82
Sempra Mexico							155			140
Sempra Renewables							100			457
Sempra LNG & Midstream							12			68
All other							13			7
Total							$	1,802		$	2,006
							June 30, 2017			December 31, 2016
ASSETS
SDG&E							$	18,708		$	17,719
SoCalGas							13,743			13,424
Sempra South American Utilities							3,750			3,591
Sempra Mexico							7,835			7,542
Sempra Renewables							2,349			3,644
Sempra LNG & Midstream							4,861			5,564
All other							660			475
Intersegment receivables							(2,530		)	(4,173		)
Total							$	49,376		$	47,786
EQUITY METHOD AND OTHER INVESTMENTS
Sempra South American Utilities							$	20		$	—
Sempra Mexico							234			180
Sempra Renewables							825			844
Sempra LNG & Midstream							977			997
All other							78			76
Total							$	2,134		$	2,097

(1)

Revenues for reportable segments include intersegment revenues of $3 million, $17 million, $26 million and $51 million for the three months ended June 30, 2017; $4 million, $35 million, $51 million and $104 million for the six months ended June 30, 2017; a negligible amount, $18 million, $27 million and $36 million for the three months ended June 30, 2016; and $3 million, $35 million, $54 million and $66 million for the six months ended June 30, 2016 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively.


(2)	Amounts for the six months ended June 30, 2016 reflect the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.


(3)	After preferred dividends.

ITEM 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto contained in this Form 10-Q, and the Consolidated Financial Statements and the Notes thereto, ~~"Management's~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” and ~~"Risk Factors"~~“Risk Factors” contained in our ~~2015~~ Annual ~~Report on Form 10-K (Annual Report).~~Report.

OVERVIEW

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~~Additional information about our operating units, ~~are our California Utilities, which are San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas),~~ 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~~Infrastructure, and their respective reportable segments ~~– Sempra Renewables~~is provided below and ~~Sempra Natural Gas.~~in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

This report includes information for the following separate registrants:

§
▪	Sempra Energy and its consolidated entities

§
▪	SDG&E and its consolidated VIE

§
▪	SoCalGas

References to ~~"we," "our"~~“we,” “our” and ~~"Sempra~~“Sempra Energy ~~Consolidated"~~Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by its context. We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include our South American utilities or the utilities in our Sempra Infrastructure operating unit. All references to ~~"Sempra International"~~“Sempra Utilities” and ~~"Sempra U.S. Gas & Power,"~~“Sempra Infrastructure,” and to their respective ~~principal~~reportable segments, are not intended to refer to any legal entity with the same or similar name.

Throughout this report, we refer to the following as Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements when discussed together or collectively:

§
▪	the Condensed Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and ~~variable interest entities (VIEs),~~VIEs;

§
▪	the Condensed Consolidated Financial Statements and related Notes of SDG&E and its ~~VIE,~~VIE; and

§
▪	the Condensed Financial Statements and related Notes of SoCalGas.

Below are summary descriptions of our operating units and their reportable segments.

SEMPRA ENERGY OPERATING UNITS AND REPORTABLE SEGMENTS

~~CALIFORNIA~~

SEMPRA UTILITIES
	~~MARKET~~	~~SERVICE TERRITORY~~
Business summary	Market	Service territory
~~SAN DIEGO GAS & ELECTRIC COMPANY (SDG&E)~~SDG&E A regulated public utility; infrastructure supports electric generation, transmission and distribution, and natural gas distribution	§ ▪ Provides electricity to a population of 3.6 million (1.4 million meters) § ▪ Provides natural gas to a population of 3.3 million (0.9 million meters)	Serves the county of San Diego, California (electric and natural gas) and an adjacent portion of southern Orange County (electric only) covering 4,100 square miles
~~SOUTHERN CALIFORNIA GAS COMPANY (SOCALGAS)~~SOCALGAS A regulated public utility; infrastructure supports natural gas distribution, transmission and storage	§~~Residential, commercial, industrial, utility electric generation and wholesale customers~~ §~~Covers~~ ▪ Provides natural gas to a population of ~~21.6~~21.7 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.~~

~~SEMPRA INTERNATIONAL~~
	~~MARKET~~	~~GEOGRAPHIC REGION~~
SEMPRA SOUTH AMERICAN UTILITIES Develops, owns and operates, or holds interests in electric transmission, distribution and generation infrastructure	§ ▪ Provides electricity to a population of approximately 2 million (approximately ~~672,000~~0.7 million meters) in Chile and approximately 4.9 million ~~consumers~~ (approximately ~~1,053,000~~1.1 million meters) in Peru	§~~Chile~~ §~~Peru~~ ▪ Region of Valparaiso in central Chile ▪ Southern zone of metropolitan Lima, Peru



SEMPRA INFRASTRUCTURE

Business summary	Market	Geographic area
SEMPRA MEXICO Develops, owns and operates, or holds interests in: § ▪ natural gas transmission pipelines ~~and propane~~ ▪ LPG and ethane systems § ▪ a natural gas distribution utility § ▪ electric generation facilities, including wind, solar and a natural gas-fired power plant (presently held for sale) § ▪ a terminal for the import of ~~liquefied natural gas (LNG)~~LNG § ▪ a terminal for the storage of LPG ▪ a marine terminal for the receipt, storage and delivery of liquid fuels ▪ marketing operations for the purchase of LNG and the purchase and sale of natural gas	§ ▪ Natural gas § ▪ Wholesale electricity §~~Liquefied natural gas~~ ▪ LNG ▪ LPG ▪ Liquid fuels	§~~Mexico~~ ▪ Mexico

~~SEMPRA U.S. GAS & POWER~~
	~~MARKET~~	~~GEOGRAPHIC REGION~~
SEMPRA RENEWABLES Develops, owns and operates, or holds interests in renewable energy generation projects	§ ▪ Wholesale electricity	§~~U.S.A.~~ ▪ Arizona ▪ California ▪ Colorado ▪ Hawaii ▪ Indiana ▪ Kansas	▪ Michigan ▪ Minnesota ▪ Nebraska ▪ Nevada ▪ Pennsylvania
SEMPRA ~~NATURAL GAS~~LNG & MIDSTREAM Develops, owns and operates, or holds interests ~~in:~~ §in LNG and natural gas midstream ~~and LNG~~assets: ▫~~natural gas pipelines and storage facilities~~ ▪ ▫a terminal in the U.S. for the import and export of LNG and sale of natural gas ▫~~marketing operations~~ ▪ §natural gas ~~distribution utilities (held for sale at June 30, 2016)~~pipelines and storage facilities ▪ marketing operations	§ ▪ LNG ▪ Natural gas §~~Liquefied natural gas~~	§~~U.S.A.~~ ▪ Alabama ▪ Louisiana ▪ Mississippi ▪ Texas

RESULTS OF OPERATIONS

We discuss the following in Results of Operations:

§
▪	Overall results of our operations ~~and factors affecting those~~


▪	Segment results

§	~~Our segment results~~
▪	Adjusted earnings and adjusted earnings per share

§
▪	Significant changes in revenues, costs and earnings between periods


▪	Impact of foreign currency and inflation rates on our results of operations

OVERALL RESULTS OF OPERATIONS OF SEMPRA ENERGY ~~CONSOLIDATED OVERALL RESULTS~~

Our earnings ~~decreased~~increased by ~~$279~~$243 million to ~~$16~~$259 million in the three months ended June 30, ~~2016,~~2017, while diluted ~~earnings per share decreased~~EPS increased by ~~$1.11~~$0.97 per share to ~~$0.06~~$1.03 per share. For the six months ended June 30, ~~2016,~~2017, our earnings ~~decreased~~increased by ~~$397~~$331 million ~~(54%)~~ to ~~$335~~$700 million, while diluted ~~earnings~~EPS increased by $1.30 per share ~~decreased by $1.58~~to $2.77 per ~~share (54%) to $1.33 per~~ share.

~~The net decreases in our~~ Our earnings and diluted ~~earnings per share for~~EPS were impacted by variances discussed in “Segment Results” below and by the ~~three-month period were primarily due to the following (decreases) increases, by segment:~~

~~SDG&E~~

$(31) million of charges associated with prior years' income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the California Public Utilities Commission's (CPUC) final decision in the 2016 General Rate Case (2016 GRC FD), which we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements herein

§	~~$9 million favorable impact from the retroactive application of the 2016 GRC FD for the first quarter of 2016~~

~~SoCalGas~~

§	~~$(49) million of charges associated with prior years' income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD~~

§	$(13) million impairment of assets related to the Southern Gas System Reliability Project (also referred to as the North-South Pipeline), as we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements herein

§	~~$(13) million of earnings in 2015 from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 and the first quarter of 2015 due to increased rate base~~

§	$(9) million charge associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD, as we discuss in Notes 5 and 10 of the Notes to Condensed Consolidated Financial Statements herein

§	~~$12 million favorable impact from the retroactive application of the 2016 GRC FD for the first quarter of 2016~~

~~Sempra Natural Gas~~

§	~~$(123) million loss on permanent release of pipeline capacity, as we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein~~

§	~~$(36) million gain in 2015 on the sale of the remaining 625-megawatt (MW) block of the Mesquite Power plant~~

§	~~$(24) million lower results primarily from midstream activities, including $3 million lower results from LNG marketing operations, mainly driven by changes in natural gas prices~~

§	~~$(8) million lower equity earnings resulting from the sale of Sempra Natural Gas' interest in Rockies Express Pipeline, LLC (Rockies Express)~~

~~The net decreases in our earnings and diluted earnings per share for the six-month period ended June 30, 2016 were primarily due to the following (decreases) increases, by segment:~~

~~SDG&E~~

§	~~$(31) million of charges associated with prior years' income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD~~

$(13) million decrease due to the plant closure adjustment recorded in the first quarter of 2015 based on the CPUC approval of a compliance filing related to SDG&E's authorized recovery of its investment in the San Onofre Nuclear Generating Station (SONGS), as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein

~~SoCalGas~~

§	~~$(49) million of charges associated with prior years' income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD~~

§	~~$(13) million impairment of assets related to the Southern Gas System Reliability Project~~

§	~~$(11) million of earnings in 2015 from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base~~

§	~~$(9) million charge associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD~~

§	~~$(8) million after-tax gas cost incentive mechanism (GCIM) award approved by the CPUC in the first quarter of 2015 for the 12-month period ending March 31, 2014~~

§	$(6) million primarily due to the utilization of the forecasted annual effective tax rate method for recording flow-through and permanent income tax items proportionately over the year, and lower pretax income in 2016 compared to 2015

§	~~$10 million higher earnings associated with the Pipeline Safety Enhancement Plan (PSEP) and advanced metering assets~~

~~Sempra South American Utilities~~

§	~~$(8) million lower earnings from foreign currency translation and inflation effects~~

~~Sempra Mexico~~

§	$(26) million deferred tax expense on our investment in the Termoeléctrica de Mexicali (TdM) natural gas-fired power plant as a result of management's decision to hold the asset for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein

~~Sempra Natural Gas~~

§	~~$(123) million loss on permanent release of pipeline capacity~~

§	~~$(39) million lower results primarily from midstream activities, including $6 million lower results for LNG marketing operations, mainly driven by changes in natural gas prices~~

§	~~$(36) million gain in 2015 on the sale of the remaining 625-MW block of the Mesquite Power plant~~

§	~~$(27) million impairment charge in the first quarter of 2016 related to Sempra Natural Gas' investment in Rockies Express~~

~~Parent and Other~~

§	~~$(15) million higher net interest expense in 2016, primarily due to debt offerings in 2015~~

~~ADJUSTED EARNINGS AND ADJUSTED EARNINGS PER SHARE~~

~~We prepare the Condensed Consolidated Financial Statements in conformity with accounting principles generally accepted~~items included in the ~~United States of America (U.S. GAAP). However, for Sempra~~table “Sempra Energy Consolidated, management may use earnings and earnings per share excluding certain items (adjusted earnings and adjusted earnings per share) internally for financial planning, for analysis of performance and for reporting of results to the Board of Directors. Adjusted earnings and adjusted earnings per share are non-GAAP financial measures. We may also use adjusted earnings and adjusted earnings per share when communicating our financial results and earnings outlook to analysts and investors. Because of the significance and/or nature of the excluded items, management believes that these non-GAAP financial measures provide a more meaningful comparison of the performance of Sempra Energy's business operations to prior and future periods.

Non-GAAP financial measures are supplementary information that should be considered in addition to, but not as a substitute for, the information prepared in accordance with GAAP. The table below reconciles for historical periods adjusted earnings and adjusted earnings per share to Sempra Energy Earnings and ~~Diluted~~Adjusted Earnings Per ~~Common~~ Share, ~~which we consider to be the most directly comparable financial measures calculated in accordance with GAAP.~~” also below.

SEMPRA ENERGY ADJUSTED EARNINGS AND ADJUSTED EARNINGS PER SHARE
(Dollars in millions, except per share amounts)
Pretax amount Income tax (benefit) expense(1) After-tax amount
Diluted
EPS
Three months ended June 30, 2016
Sempra Energy GAAP Earnings $ 16 $ 0.06
Excluded items:
   Permanent release of pipeline capacity $ 206 $ (83) 123 0.49
   SDG&E tax repairs adjustments related to 2016 GRC FD 52 (21) 31 0.12
   SoCalGas tax repairs adjustments related to 2016 GRC FD 83 (34) 49 0.20
   SDG&E retroactive impact of 2016 GRC FD for first-quarter 2016 (15) 6 (9) (0.04)
   SoCalGas retroactive impact of 2016 GRC FD for first-quarter 2016 (20) 8 (12) (0.05)
   Deferred income tax expense associated with TdM ― 2 2 0.01
Sempra Energy Adjusted Earnings $ 200 $ 0.79
Weighted-average number of shares outstanding, diluted (thousands) 251,938

Three months ended June 30, 2015
Sempra Energy GAAP Earnings $ 295 $ 1.17
Excluded items:
   Gain on sale of Mesquite Power block 2 $ (61) $ 25 (36) (0.14)
Sempra Energy Adjusted Earnings $ 259 $ 1.03
Weighted-average number of shares outstanding, diluted (thousands) 251,491

Six months ended June 30, 2016
Sempra Energy GAAP Earnings $ 335 $ 1.33
Excluded items:
   Permanent release of pipeline capacity $ 206 $ (83) 123 0.49
   SDG&E tax repairs adjustments related to 2016 GRC FD 52 (21) 31 0.12
   SoCalGas tax repairs adjustments related to 2016 GRC FD 83 (34) 49 0.20
   Impairment of investment in Rockies Express 44 (17) 27 0.11
   Deferred income tax expense associated with TdM ― 26 26 0.10
Sempra Energy Adjusted Earnings $ 591 $ 2.35
Weighted-average number of shares outstanding, diluted (thousands) 251,686

Six months ended June 30, 2015
Sempra Energy GAAP Earnings $ 732 $ 2.91
Excluded items:
   Gain on sale of Mesquite Power block 2 $ (61) $ 25 (36) (0.14)
   SONGS plant closure adjustment (21) 8 (13) (0.05)
Sempra Energy Adjusted Earnings $ 683 $ 2.72
Weighted-average number of shares outstanding, diluted (thousands) 251,264
(1)

Income taxes were calculated based on applicable statutory tax rates, except for adjustments that are solely income tax.

SEGMENT RESULTS

The following section presents earnings (losses) by Sempra Energy segment, as well as Parent and other, and the related discussion of the changes in segment earnings (losses). Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise ~~noted.~~noted, and before noncontrolling interests, where applicable.

SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
California Utilities:
    SDG&E $ 100 $ 126 $ 229 $ 273
    SoCalGas(1) (1) 70 194 284
Sempra International:
    Sempra South American Utilities 43 45 81 86
    Sempra Mexico 57 50 74 97
Sempra U.S. Gas & Power:
    Sempra Renewables 12 19 25 32
    Sempra Natural Gas (149) 40 (185) 42
Parent and other(2) (46) (55) (83) (82)
Earnings $ 16 $ 295 $ 335 $ 732
(1) After preferred dividends.
(2) Includes after-tax interest expense ($44 million and $39 million for the three months ended June 30, 2016 and 2015, respectively, and $87 million and $77 million for the six months ended June 30, 2016 and 2015, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.



SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016(1)
Sempra Utilities:
SDG&E	$	149		$	100		$	304		$	236
SoCalGas(2)	58			(1		)	261			198
Sempra South American Utilities	45			43			92			81
Sempra Infrastructure:
Sempra Mexico	(9		)	57			39			75
Sempra Renewables	23			12			34			26
Sempra LNG & Midstream	27			(149		)	28			(181		)
Parent and other(3)	(34		)	(46		)	(58		)	(66		)
Earnings	$	259		$	16		$	700		$	369

~~EARNINGS (LOSSES) BY SEGMENT – CALIFORNIA UTILITIES~~
~~(Dollars~~(1)	Reflects the adoption of ASU 2016-09, as we discuss in ~~millions)~~Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

The California Utilities recorded revenues in the first quarter of 2016 based on levels authorized for 2015 under the 2012 GRC, because a final decision in the 2016 GRC was not issued by March 31, 2016. The 2016 GRC FD, which was issued in June 2016, is effective retroactive to January 1, 2016, and the California Utilities have recorded the retroactive impacts in the second quarter of 2016.

~~SDG&E~~

~~Our SDG&E segment recorded earnings of:~~

§	~~$100~~
(2)	After preferred dividends.


(3)	Includes after-tax interest expense ($40 million inand $44 million for the three months ended June 30, 2017 and 2016,

§	~~$126~~ respectively, and $81 million inand $87 million for the ~~three~~six months ended June 30, ~~2015~~2017 and 2016, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

§	~~$229 million for the first six months of 2016~~

§	~~$273 million for the first six months of 2015~~

SDG&E

The ~~decrease~~increase in earnings of ~~$26~~$49 million ~~(21%~~(49%) in the three months ended June 30, ~~2016~~2017 was primarily due to:

§
▪	$31 million ~~of charges~~charge in 2016 associated with prior ~~years'~~years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC ~~FD ($22~~FD;


▪	$16 million ~~related to 2015 benefits~~higher CPUC base operating margin authorized for 2017 and ~~$9 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals); and~~lower non-refundable operating costs;

§
▪	$108 million favorable impact in ~~2015 related to~~2017 from the resolution of prior ~~years'~~years’ income tax items;


▪	$5 million higher earnings from electric transmission operations primarily due to higher rate base; and


▪	$3 million increase in AFUDC related to equity; offset by

§
▪	$9 million favorable impact in 2016 from the retroactive application of the 2016 GRC FD for the first quarter of ~~2016;~~2016.

§	~~$3 million lower net interest expense; and~~

§	~~$3 million increase in allowance for funds used during construction (AFUDC) related to equity.~~

The ~~decrease~~increase in earnings of ~~$44~~$68 million ~~(16%~~(29%) in the first six months of ~~2016~~2017 was primarily due to:

§
▪	$31 million ~~of charges~~charge in 2016 associated with prior ~~years'~~years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC ~~FD ($~~FD;


▪	$22 million ~~related to 2015 benefits~~higher CPUC base operating margin authorized for 2017 and ~~$9 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals);~~lower non-refundable operating costs;

§
▪	$13 million decrease due to the plant closure adjustment recorded in the first quarter of 2015 based on the CPUC approval of a compliance filing related to SDG&E's authorized recovery of its investment in SONGS;

§	~~$10~~8 million favorable impact in ~~2015 related to~~2017 from the resolution of prior ~~years'~~years’ income tax items; ~~and~~

§
▪	$57 million higher ~~non-refundable operating costs, including depreciation, partially offset by~~earnings from electric transmission operations primarily due to higher ~~CPUC base operating margin;~~ ~~offset by~~rate base;

§
▪	$~~6 million lower net interest expense;~~

§	$67 million increase in AFUDC related to equity; and

§
▪	$6 million reimbursement of litigation costs associated with the arbitration ruling over the SONGS replacement steam generators, as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein; offset by


▪	$47 million ~~lower generation major maintenance costs.~~income tax benefit in 2016 associated with excess tax benefits related to share-based compensation.

SoCalGas

~~Our SoCalGas segment recorded (losses)~~The increase in earnings ~~of:~~

§	~~$(1) million in the three months ended June 30, 2016 ($0 before preferred dividends)~~

§	~~$70 million in the three months ended June 30, 2015 ($71 million before preferred dividends)~~

§	~~$194 million for the first six months of 2016 ($195 million before preferred dividends)~~

§	~~$284 million for the first six months of 2015 ($285 million before preferred dividends)~~

~~The change~~ of ~~$71~~$59 million in the three months ended June 30, ~~2016~~2017 was primarily due to:

§
▪	$49 million of charges in 2016 associated with prior ~~years'~~years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC ~~FD ($43 million related to 2015 benefits and $6 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals);~~FD;

§
▪	$13 million impairment of assets in 2016 related to the Southern Gas System Reliability ~~project;~~Project (also referred to as the North-South Pipeline); and

§
▪	$135 million ofhigher earnings in 2015 from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 and the first quarter of 2015 due to increased rate base, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report;

§	~~$9 million charge~~ associated with ~~tracking~~ the ~~income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD;~~

§	~~$6 million from the favorable resolution of a legal settlement in 2015, including $2 million of related interest income;~~

~~$3 million primarily due to the utilization of the forecasted annual effective tax rate method for recording flow-through~~PSEP and permanent income tax items proportionately over the year, and lower pretax income in 2016 compared to 2015, as we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein; andadvanced metering assets; offset by

§	~~$3 million favorable impact in 2015 related to the resolution of prior years' income tax items;~~ ~~offset by~~

§▪	$12 million favorable impact in 2016 from the retroactive application of the 2016 GRC FD for the first quarter of ~~2016;~~2016.

§	$5 million higher earnings associated with the PSEP and advanced metering assets. We discuss the PSEP in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and below in "Factors Influencing Future Performance – California Utilities."; and

§	~~$5 million higher CPUC base operating margin authorized for 2016, and lower non-refundable operating costs.~~

The ~~decrease~~increase in earnings of ~~$90~~$63 million (32%) in the first six months of ~~2016~~2017 was primarily due to:

§
▪	$49 million of charges in 2016 associated with prior ~~years'~~years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC ~~FD ($43 million related to 2015 benefits and $6 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals);~~FD;

§
▪	$13 million impairment of assets in 2016 related to the Southern Gas System Reliability ~~project;~~

§	~~$11 million of earnings in 2015 from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base;~~

§	~~$9 million charge associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD;~~

$8 million after-tax GCIM award approved by the CPUC in February 2015 for the 12-month period ending March 31, 2014. We include incentive awards in earnings when we receive any required CPUC approval of the award, which may cause timing differences in earnings. In December 2015, SoCalGas received approval of a $4 million after-tax GCIM award for the 12-month period ending March 31, 2015;

$6 million primarily due to the utilization of the forecasted annual effective tax rate method for recording flow-through and permanent income tax items proportionately over the year, and lower pretax income in 2016 compared to 2015, as we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein;

§	~~$6 million from the favorable resolution of a legal settlement in 2015, including $2 million of related interest income;~~Project; and

§
•	~~$3 million favorable impact in 2015 related to the resolution of prior years' income tax items;~~ ~~offset by~~

§	$10 million higher earnings associated with the PSEP and advanced metering assets; ~~and~~

§	~~$6 million higher CPUC base operating margin authorized for 2016, partially~~ offset by ~~higher non-refundable operating costs.~~

~~EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL~~

~~(Dollars in millions)~~

$4 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation.

Sempra South American Utilities

Because our operations in South America use their local currency as their functional currency, revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra Energy ~~Consolidated's~~Consolidated’s results of operations. The year-to-year variances discussed below are as adjusted for the difference in foreign currency translation rates between ~~periods.~~ years. We discuss these and other foreign currency effects below in ~~"Impact~~“Impact of Foreign Currency and Inflation Rates on Results of Operations."”

Earnings ~~variances below~~ for ~~both Sempra South American Utilities and Sempra Mexico exclude amounts attributable to noncontrolling interests.~~

~~Sempra South American Utilities~~

~~Our Sempra South American Utilities segment recorded~~the three months ended June 30, 2017 were consistent with earnings ~~of:~~

§	~~$43 million in the three months ended June 30, 2016~~

§	~~$45 million in the three months ended June 30, 2015~~

§	~~$81 million for the first six months of 2016~~

§	~~$86 million for the first six months of 2015~~

for the same period in 2016.

The ~~decrease~~increase in earnings of $2$11 million ~~(4%~~(14%) in the first six months of 2017 was primarily due to higher earnings from operations at Luz del Sur, mainly driven by an increase in rates, and lower operating expenses, offset by lower volumes.

Sempra Mexico

Losses of $9 million in the three months ended June 30, 2017 compared to earnings of $57 million for the same period in 2016 was primarily due to:

§
▪	$471 million ~~lower earnings from foreign currency translation and inflation effects; and~~

§	$2impairment in 2017, net of a $12 million ~~lower capitalized interest due to completion~~income tax benefit that has been fully reserved, of ~~construction of the Santa Teresa hydroelectric power plant in 2015;~~ ~~offset by~~

§	~~$4 million higher earnings from operations mainly due to the start of operations of the Santa Teresa hydroelectric power plant in September 2015.~~

~~The decrease in earnings of $5 million (6%) in the first six months of 2016 was primarily due to:~~

§	~~$8 million lower earnings from foreign currency translation and inflation effects; and~~

§	~~$4 million lower capitalized interest due to completion of construction of the Santa Teresa hydroelectric power plant in 2015;~~ ~~offset by~~

§	~~$7 million higher earnings from operations mainly due to the start of operations of the Santa Teresa hydroelectric power plant in September 2015.~~

~~Sempra Mexico~~

~~Our Sempra Mexico segment recorded earnings of:~~

§	~~$57 million in the three months ended June 30, 2016~~

§	~~$50 million in the three months ended June 30, 2015~~

§	~~$74 million for the first six months of 2016~~

§	~~$97 million for the first six months of 2015~~

~~The increase in earnings of $7 million (14%) in the three months ended June 30, 2016 was primarily due to:~~

§	$10 million higher benefit due primarily to positive effects from foreign currency and inflation, including amounts in equity earnings from our joint ventures. We discuss these effects below in "Impact of Foreign Currency and Inflation Rates on Results of Operations;" ~~offset by~~

§	~~$4 million lower AFUDC related to equity primarily due to completion of the first segment of the Sonora pipeline in 2015.~~

~~The decrease in earnings of $23 million (24%) in the first six months of 2016 was primarily due to:~~

§	~~$26 million deferred tax expense on our investment in~~ the TdM natural gas-fired power plant ~~as a result of management's decision to hold the asset~~assets held for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein; ~~and~~

§	~~$7 million lower AFUDC related to equity primarily due to completion of the first segment of the Sonora pipeline in 2015;~~ ~~offset by~~

§▪	$629 million ~~higher benefit due primarily to positive effects~~unfavorable impact in 2017 from foreign currency and inflation ~~including amounts~~effects, net of related hedging activities, as follows:


◦	$52 million from income tax expense ($34 million after noncontrolling interests), and


◦	$9 million in equity losses from our joint ventures, offset by


◦	$8 million favorable transactional effects.

The net effects of the items above were partially mitigated, as we discuss below in “Other Income, Net,” by a $24 million gain ($40 million pretax) from foreign currency derivatives, which are hedging Sempra Mexico’s foreign currency exposure from its controlling interest in IEnova. We discuss these effects below in “Impact of Foreign Currency and Inflation Rate on Results of Operations;”


▪	$22 million favorable impact in 2016 from foreign currency and inflation effects, net of related hedging activities, as follows:


◦	$22 million from income tax benefit ($18 million after noncontrolling interests), and


◦	$15 million in equity earnings from our joint ~~ventures.~~ventures, offset by

~~EARNINGS (LOSSES) BY SEGMENT – SEMPRA U.S. GAS & POWER~~
~~(Dollars in millions)~~◦	$6 million unfavorable transactional effects.

The net effects of the items above were partially offset by a $9 million loss ($15 million pretax) from foreign currency derivatives, which were used to hedge Sempra ~~Renewables~~Mexico’s foreign currency exposure from its controlling interest in IEnova;

~~Our Sempra Renewables segment recorded earnings of:~~

§
▪	$1213 million valuation allowance against TdM’s deferred tax assets;


▪	$7 million higher interest expense, including $4 million at Ventika and $2 million at IEnova Pipelines (formerly known as GdC) related to debt assumed in their acquisitions; and


▪	$7 million lower operating results at TdM, mainly due to higher operating expenses related to major maintenance; offset by


▪	$35 million higher pipeline operational earnings, primarily attributable to the increase in our ownership interest in IEnova Pipelines from 50 percent to 100 percent in September 2016 and from other pipeline assets placed in service;


▪	$15 million losses attributable to noncontrolling interests in 2017 compared to $16 million earnings attributable to noncontrolling interests in 2016 at IEnova, as we discuss below in “Changes in Revenues, Costs and Earnings – Losses (Earnings) Attributable to Noncontrolling Interests;”


▪	$8 million operational earnings in 2017 from the Ventika wind power generation facilities, which we acquired in December 2016;


▪	$3 million tax benefit in 2017 from a reduction to the outside basis deferred tax liability compared to $3 million tax expense in 2016 on our investment in TdM that is held for sale; and


▪	$4 million higher earnings from the recognition of AFUDC related to equity primarily associated with the Ojinaga pipeline project.

The decrease in earnings of $36 million (48%) in the first six months of 2017 was primarily due to:


▪	$86 million unfavorable impact in 2017 from foreign currency and inflation effects, net of related hedging activities, as follows:


◦	$149 million from income tax expense ($99 million after noncontrolling interests), and


◦	$22 million in ~~the three months ended June 30, 2016~~equity losses from our joint ventures, offset by

§
◦	$1917 million ~~in the three months ended June 30, 2015~~favorable transactional effects.

The net effects of the items above were partially mitigated, as we discuss below in “Other Income, Net,” by a $68 million gain ($113 million pretax) from foreign currency derivatives, which are hedging Sempra Mexico’s foreign currency exposure from its controlling interest in IEnova. We discuss these effects below in “Impact of Foreign Currency and Inflation Rate on Results of Operations;”

§
▪	$25 million ~~for the first six months~~favorable impact in 2016 from foreign currency and inflation effects, net of ~~2016~~related hedging activities, as follows:

§
◦	$22 million from income tax benefit ($18 million after noncontrolling interests), and


◦	$15 million in equity earnings from our joint ventures, offset by


◦	$5 million net unfavorable transactional and translation effects.

The net effects of the items above were partially offset by a $7 million loss ($12 million pretax) from foreign currency derivatives, which were used to hedge Sempra Mexico’s foreign currency exposure from its controlling interest in IEnova;


▪	$71 million impairment in 2017, net of a $12 million income tax benefit that has been fully reserved, of the TdM assets held for sale;


▪	$15 million higher interest expense, including $8 million at Ventika and $4 million at IEnova Pipelines; and


▪	$13 million valuation allowance against TdM’s deferred tax assets; offset by


▪	$57 million higher pipeline operational earnings, primarily attributable to the increase in ownership in IEnova Pipelines and from other pipeline assets placed in service;


▪	$8 million tax benefit in 2017 from a reduction to the outside basis deferred tax liability compared to $32 million tax expense in 2016 on our investment in TdM that is held for sale;


▪	$32 million ~~for~~higher earnings from the ~~first six months~~recognition of ~~2015~~AFUDC related to equity primarily associated with the Ojinaga and San Isidro pipeline projects;


▪	$10 million losses attributable to noncontrolling interests in 2017 compared to $21 million earnings attributable to noncontrolling interests in 2016 at IEnova; and


▪	$18 million operational earnings in 2017 from Ventika.

Sempra Renewables

The ~~decreases~~increase in earnings of $11 million (92%) and $8 million (31%) in ~~both~~ the three months and six months ended June 30, ~~2016 were~~2017, respectively, was due to the attribution of losses of $7 million and $10 million, respectively, to tax equity investors reflected in noncontrolling interests, primarily due to ~~lower~~ solar ~~investment tax credits from projects~~assets placed in service ~~in 2015.~~

~~Sempra Natural Gas~~

~~Our Sempra Natural Gas segment recorded (losses) earnings of:~~

§	~~$(149) million in the three months ended June 30, 2016~~

§	~~$40 million in the three months ended June 30, 2015~~

§	~~$(185) million for the first six months of 2016~~

§	~~$42 million for the first six months of 2015~~

~~The change in~~during 2016. For the three months ended June 30, 2017, the higher earnings were also due to increased production at our wind and solar assets.

Sempra LNG & Midstream

Earnings of $27 million for the three months ended June 30, 2017 compared to losses of $149 million for the same period in 2016, was primarily due to:

§
▪	$123 million loss in 2016 on permanent release of certain pipeline ~~capacity;~~

§	~~$36 million gain~~capacity, as we discuss in ~~2015 on the sale~~Note 15 of the ~~remaining 625-MW block~~Notes to Consolidated Financial Statements in the Annual Report;


▪	$34 million settlement proceeds from a breach of contract claim against a counterparty in bankruptcy court, of which $28 million is related to the charge in 2016 from the permanent release of certain pipeline capacity, as we discuss in Note 11 of the ~~Mesquite Power plant, net of related expenses;~~Notes to Condensed Consolidated Financial Statements herein;

§
▪	$2418 million ~~lower results~~ primarily due to mark-to-market losses in 2016 from ~~midstream activities, including $3~~natural gas marketing activities; and


▪	$5 million ~~lower~~higher results from LNG marketing ~~operations, mainly~~activities primarily driven by changes in natural gas ~~prices; and~~prices.

§	$8Earnings of $28 million ~~lower equity earnings resulting from the sale of its investment in Rockies Express.~~

~~The change~~ in the first six months of 2017 compared to losses of $181 million for the same period in 2016, was primarily due to:

§
▪	$123 million loss in 2016 on permanent release of certain pipeline capacity;

§
▪	$39 million ~~lower~~improved results primarily due to mark-to-market losses in 2016 from ~~midstream activities, including $6 million lower results from LNG marketing operations, mainly driven by changes in~~ natural gas ~~prices;~~marketing activities;

§
▪	$3634 million ~~gain~~settlement proceeds from a breach of contract claim against a counterparty in ~~2015 on~~bankruptcy court, of which $28 million is related to the ~~sale~~charge in 2016 from the permanent release of ~~the remaining 625-MW block of the Mesquite Power plant, net of related expenses;~~certain pipeline capacity;

§
▪	$27 million impairment charge in the first quarter of 2016 related to ~~the~~our investment in Rockies Express, which we discuss further in ~~Notes~~Note 3 ~~and 8~~ of the Notes to Condensed Consolidated Financial Statements herein; and

§
▪	$9 million higher results from LNG marketing activities primarily driven by changes in natural gas prices; offset by


▪	$611 million lower equity earnings resulting from the sale of ~~its~~our investment in Rockies ~~Express.~~Express in May 2016; and


▪	$7 million lower earnings due to the sale of EnergySouth in September 2016, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.

Parent and Other

~~Losses for Parent and Other were~~

§	~~$46 million in the three months ended June 30, 2016~~

§	~~$55 million in the three months ended June 30, 2015~~

§	~~$83 million for the first six months of 2016~~

§	~~$82 million for the first six months of 2015~~

The decrease in losses of $9$12 million ~~(16%~~(26%) in the three months ended June 30, ~~2016~~2017 was primarily due to:

§
▪	$814 million ~~lower~~higher income tax benefits in 2017, including:


◦	$2 million income tax benefit in 2017 compared to $8 million income tax expense in 2016 due to the interim period application of an annual forecasted consolidated effective tax rate, and


◦	$4 million U.S. income tax expense in 2016 ~~as a result of lower~~on planned repatriation of ~~current year~~ earnings from certain non-U.S. subsidiaries; ~~and~~

§
▪	$65 million ~~increase in~~higher investment gains ~~in 2016~~ on dedicated assets in support of our executive retirement and deferred compensation plans, ~~net of the increase~~and a decrease in deferred compensation ~~liability~~expense associated with the investments; ~~offset by~~ and

§
▪	$5 million ~~higher~~lower net interest expense in ~~2016, primarily due to debt offerings~~2017; offset by


▪	$6 million higher proportion of operating costs retained at Parent; and


▪	$5 million ($8 million pretax) of costs in ~~the fourth quarter of 2015.~~2017 associated with foreign currency derivatives.

The ~~increase~~decrease in losses of $1$8 million ~~(1%~~(12%) in the first six months of ~~2016~~2017 was primarily due to:

§
▪	$1510 million higher investment gains on dedicated assets in support of our executive retirement and deferred compensation plans;


▪	$9 million lower net interest expense in 2017; and


▪	$6 million higher income tax benefits in 2017, including:


◦	$3 million income tax benefit in 2017 compared to $6 million income tax expense in 2016 ~~primarily~~ due to ~~debt offerings in 2015;~~ ~~offset by~~the interim period application of an annual forecasted consolidated effective tax rate,

§
◦	$159 million ~~lower~~ U.S. income tax expense in 2016 ~~as a result of lower~~on planned repatriation of ~~current year~~ earnings from certain non-U.S. ~~subsidiaries.~~subsidiaries, and


◦	$7 million income tax benefit in 2017 related to a deferred income tax liability on an outside basis difference in a subsidiary investment, offset by


◦	$1 million income tax expense in 2017 compared to $17 million income tax benefit in 2016 associated with excess tax deficiencies/benefits related to share-based compensation; offset by


▪	$10 million ($16 million pretax) of costs in 2017 associated with foreign currency derivatives; and


▪	$4 million higher proportion of operating costs retained at Parent.

ADJUSTED EARNINGS AND ADJUSTED EARNINGS PER SHARE

We prepare the Condensed Consolidated Financial Statements in conformity with U.S. GAAP. However, management may use earnings and EPS adjusted to exclude certain items (referred to as adjusted earnings and adjusted EPS) internally for financial planning, for analysis of performance and for reporting of results to the Board of Directors. We may also use adjusted earnings and adjusted EPS when communicating our financial results and earnings outlook to analysts and investors. Adjusted earnings and adjusted EPS are non-GAAP financial measures. Because of the significance and/or nature of the excluded items, management believes that these non-GAAP financial measures provide a meaningful comparison of the performance of business operations to prior and future periods. Non-GAAP financial measures are supplementary information that should be considered in addition to, but not as a substitute for, the information prepared in accordance with U.S. GAAP.

The table below reconciles adjusted earnings and adjusted EPS to Sempra Energy Earnings and Diluted Earnings Per Common Share, which we consider to be the most directly comparable financial measures calculated in accordance with U.S. GAAP, for the three months and six months ended June 30, 2017 and 2016.



SEMPRA ENERGY ADJUSTED EARNINGS AND ADJUSTED EPS
(Dollars in millions, except per share amounts)
	Pretax amount			Income tax (benefit) expense(1)			Non-controlling interests			Earnings			Diluted EPS
	Three months ended June 30, 2017
Sempra Energy GAAP Earnings										$	259		$	1.03
Excluded items:
Impairment of TdM assets held for sale	$	71		$	—		$	(24	)	47			0.19
Deferred income tax benefit associated with TdM	—			(3		)	1			(2		)	(0.01		)
Recoveries related to 2016 permanent release of pipeline capacity	(47		)	19			—			(28		)	(0.11		)
Sempra Energy Adjusted Earnings										$	276		$	1.10
Weighted-average number of shares outstanding, diluted (thousands)													252,822
	Three months ended June 30, 2016(2)
Sempra Energy GAAP Earnings										$	16		$	0.06
Excluded items:
Permanent release of pipeline capacity	$	206		$	(83	)	$	—		123			0.49
SDG&E tax repairs adjustments related to 2016 GRC FD	52			(21		)	—			31			0.12
SoCalGas tax repairs adjustments related to 2016 GRC FD	83			(34		)	—			49			0.19
SDG&E retroactive impact of 2016 GRC FD for first-quarter 2016	(15		)	6			—			(9		)	(0.03		)
SoCalGas retroactive impact of 2016 GRC FD for first-quarter 2016	(20		)	8			—			(12		)	(0.05		)
Deferred income tax expense associated with TdM	—			3			(1		)	2			0.01
Sempra Energy Adjusted Earnings										$	200		$	0.79
Weighted-average number of shares outstanding, diluted (thousands)													252,036
	Six months ended June 30, 2017
Sempra Energy GAAP Earnings										$	700		$	2.77
Excluded items:
Impairment of TdM assets held for sale	$	71		$	—		$	(24	)	47			0.19
Deferred income tax benefit associated with TdM	—			(8		)	3			(5		)	(0.02		)
Recoveries related to 2016 permanent release of pipeline capacity	(47		)	19			—			(28		)	(0.11		)
Sempra Energy Adjusted Earnings										$	714		$	2.83
Weighted-average number of shares outstanding, diluted (thousands)													252,609
	Six months ended June 30, 2016(2)
Sempra Energy GAAP Earnings										$	369		$	1.47
Excluded items:
Permanent release of pipeline capacity	$	206		$	(83	)	$	—		123			0.49
SDG&E tax repairs adjustments related to 2016 GRC FD	52			(21		)	—			31			0.12
SoCalGas tax repairs adjustments related to 2016 GRC FD	83			(34		)	—			49			0.19
Impairment of investment in Rockies Express	44			(17		)	—			27			0.11
Deferred income tax expense associated with TdM	—			32			(6		)	26			0.10
Sempra Energy Adjusted Earnings										$	625		$	2.48
Weighted-average number of shares outstanding, diluted (thousands)													251,775


(1)	Income taxes were calculated based on applicable statutory tax rates, except for adjustments that are solely income tax. Income taxes associated with TdM were calculated based on the applicable statutory tax rate, including translation from historic to current exchange rates. An income tax benefit of $12 million associated with the 2017 TdM impairment has been fully reserved.


(2)	Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

The tables below reconcile adjusted earnings to SDG&E’s and SoCalGas’ Earnings (Losses), which we consider to be the most directly comparable financial measure calculated in accordance with U.S. GAAP, for the three months and six months ended June 30, 2016. SDG&E and SoCalGas had no reconciling adjustments for the three months and six months ended June 30, 2017.



SDG&E ADJUSTED EARNINGS
(Dollars in millions)
	Pretax amount			Income tax (benefit) expense(1)			Earnings
	Three months ended June 30, 2016
SDG&E GAAP Earnings							$	100
Excluded items:
Tax repairs adjustments related to 2016 GRC FD	$	52		$	(21	)	31
Retroactive impact of 2016 GRC FD for first-quarter 2016	(15		)	6			(9		)
SDG&E Adjusted Earnings							$	122
	Six months ended June 30, 2016(2)
SDG&E GAAP Earnings							$	236
Excluded item:
Tax repairs adjustments related to 2016 GRC FD	$	52		$	(21	)	31
SDG&E Adjusted Earnings							$	267


(1)	Income taxes were calculated based on applicable statutory tax rates.


(2)	Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.



SOCALGAS ADJUSTED EARNINGS
(Dollars in millions)
	Pretax amount			Income tax (benefit) expense(1)			Earnings
	Three months ended June 30, 2016
SoCalGas GAAP Losses							$	(1	)
Excluded items:
Tax repairs adjustments related to 2016 GRC FD	$	83		$	(34	)	49
Retroactive impact of 2016 GRC FD for first-quarter 2016	(20		)	8			(12		)
SoCalGas Adjusted Earnings							$	36
	Six months ended June 30, 2016(2)
SoCalGas GAAP Earnings							$	198
Excluded item:
Tax repairs adjustments related to 2016 GRC FD	$	83		$	(34	)	49
SoCalGas Adjusted Earnings							$	247


(1)	Income taxes were calculated based on applicable statutory tax rates.


(2)	Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

CHANGES IN REVENUES, COSTS AND EARNINGS

This section contains a discussion of the differences between periods in ~~the specific~~certain line items of the Condensed Consolidated Statements of Operations for Sempra Energy, SDG&E and SoCalGas.

Utilities Revenues

Our utilities revenues include

Electric revenues at:


▪	SDG&E


▪	Sempra South American Utilities’ Chilquinta Energía and Luz del Sur

Natural gas revenues at:

§
▪	SDG&E

§
▪	SoCalGas

§
▪	Sempra ~~Mexico's~~Mexico’s Ecogas ~~México, S. de R.L. de C.V. (Ecogas)~~

§
▪	Sempra ~~Natural Gas'~~LNG & Midstream’s Mobile Gas ~~Service Corporation (Mobile Gas)~~ and Willmut Gas ~~Company (Willmut Gas)~~(prior to the sale of EnergySouth on September 12, 2016)

~~Electric revenues at:~~

~~SDG&E~~

§	~~Sempra South American Utilities' Chilquinta Energía S.A. (Chilquinta Energía) and Luz del Sur S.A.A. (Luz del Sur)~~

Intercompany revenues included in the separate revenues of each utility are eliminated in the Sempra Energy Condensed Consolidated Statements of Operations.

~~The California Utilities~~

~~The current regulatory framework for~~ SoCalGas and SDG&E permits the cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas' GCIM 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 withincurrently operate under a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Notes 1 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.

~~The~~ regulatory framework ~~also~~ that:

▪

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 subsequent periods through rates.~~

~~The table below summarizes revenues and cost of sales for our utilities, net of intercompany activity:~~

UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
Electric revenues:
  SDG&E $ 897 $ 874 $ 1,740 $ 1,679
  Sempra South American Utilities 365 363 743 726
  Eliminations and adjustments (1) (2) (3) (4)
Total 1,261 1,235 2,480 2,401
Natural gas revenues:
  SoCalGas 617 780 1,650 1,828
  SDG&E 95 98 243 259
  Sempra Mexico 20 19 42 44
  Sempra Natural Gas 18 18 56 60
  Eliminations and adjustments (17) (17) (35) (37)
Total 733 898 1,956 2,154
    Total utilities revenues $ 1,994 $ 2,133 $ 4,436 $ 4,555
Cost of electric fuel and purchased power:
  SDG&E $ 314 $ 251 $ 562 $ 479
  Sempra South American Utilities 247 247 514 500
Total $ 561 $ 498 $ 1,076 $ 979
Cost of natural gas:
  SoCalGas $ 147 $ 196 $ 400 $ 463
  SDG&E 25 31 64 85
  Sempra Mexico 11 11 23 26
  Sempra Natural Gas 4 5 15 20
  Eliminations and adjustments (4) (4) (8) (9)
Total $ 183 $ 239 $ 494 $ 585

~~Sempra Energy Consolidated~~

~~Electric Revenues~~

~~During the three months ended June 30, 2016, our electric revenues increased by $26 million (2%) to $1.3 billion primarily due to:~~

§	~~$23 million increase at SDG&E, which included~~

□	~~$63 million higher~~ cost of ~~electric fuel~~electricity supplied to customers. The differences in cost between estimates and ~~purchased power, which we discuss below,~~actual are recovered in subsequent periods through rates.

□	~~$14 million favorable impact from~~
▪	permits the ~~retroactive application of the 2016 GRC FD for the first quarter of 2016,~~

□	~~$13 million higher authorized revenue in the 2016 GRC FD, and~~

□	~~$7 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses,~~ ~~offset by~~

□

$52 million of charges associated with prior years' income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD ($37 million related to 2015 benefits and $15 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals), and

□	~~$6 million lower authorized revenues from electric transmission; and~~

§	~~$2 million increase at Sempra South American Utilities, which included~~

□	~~$32 million due to higher rates at Luz del Sur and Chilquinta Energía,~~ ~~offset by~~

□	~~$24 million due to foreign currency exchange rate effects, and~~

□	~~$4 million lower volumes at Luz del Sur, net of the effects of higher revenues from the Santa Teresa hydroelectric power plant, which began commercial operations in September 2015.~~

~~Our utilities' cost of electric fuel and purchased power increased by $63 million (13%) to $561 million in the three months ended June 30, 2016 due to the increase at SDG&E, which we discuss below.~~

~~During the six months ended June 30, 2016, our electric revenues increased by $79 million (3%) to $2.5 billion primarily due to:~~

§	~~$61 million increase at SDG&E, which included~~

□	~~$83 million higher cost of electric fuel and purchased power, which we discuss below,~~

□	~~$27 million higher authorized revenue in the 2016 GRC FD, and~~

□	~~$25 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses,~~ ~~offset by~~

□

§	~~$17 million increase at Sempra South American Utilities, which included~~

□	~~$85 million due to higher rates at Luz del Sur and Chilquinta Energía,~~ ~~offset by~~

□	~~$64 million due to foreign currency exchange rate effects, and~~

□	~~$4 million lower volumes at Luz del Sur, net of the effects of higher revenues from the Santa Teresa hydroelectric power plant, which began commercial operations in September 2015.~~

~~Our utilities' cost of electric fuel and purchased power increased by $97 million (10%) to $1.1 billion in the six months ended June 30, 2016 due to:~~

§	~~$83 million increase at SDG&E, which we discuss below; and~~

§	$14 million increase at Sempra South American Utilities driven primarily by higher prices at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects, and lower volumes at Luz del Sur.

~~We discuss the changes in electric revenues and the cost of electric fuel and purchased power for SDG&E in more detail below.~~

~~Natural Gas Revenues~~

During the three months ended June 30, 2016, Sempra Energy's natural gas revenues decreased by $165 million (18%) to $733 million, and the cost of natural gas decreased by $56 million (23%) to $183 million. The decrease in natural gas revenues included

§	~~decreases in~~ cost of natural gas ~~sold at~~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’ GCIM provides SoCalGas ~~and SDG&E, as we discuss below;~~

~~$83 million of charges at SoCalGas associated with prior years' income tax benefits generated from income tax repairs deductions that were reallocated~~the opportunity to ~~ratepayers pursuant to the 2016 GRC FD ($72 million related to 2015 benefits and $11 million related to the true-up of 2012-2014 estimated benefits used~~share in the ~~2016 GRC FD to actuals);~~

~~$24 million lower~~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 ~~at SoCalGas associated with CPUC-authorized refundable programs, which revenues~~incurred when average purchase costs are ~~fully offset~~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 ~~operation~~Note 1 of the Notes to Consolidated Financial Statements and ~~maintenance expenses;~~

§	~~$21 million increase in 2015 at SoCalGas from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014~~“Management’s Discussion and ~~the first quarter~~Analysis of ~~2015 due to increased rate base;~~Financial Condition and

§	~~$15 million charge at SoCalGas associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts~~ Results of Operations – Our Business” in the ~~2016 GRC FD;~~ ~~offset by~~ Annual Report.

§	~~$14 million favorable impact at SoCalGas from~~
▪	also permits the ~~retroactive application of the 2016 GRC FD~~California Utilities to recover certain expenses for ~~the first quarter of 2016;~~

§	~~$11 million higher~~programs authorized ~~revenue at SoCalGas in the 2016 GRC FD; and~~

§	~~$14 million higher revenues at SoCalGas primarily associated with the PSEP and advanced metering assets.~~

In the first six months of 2016, Sempra Energy's natural gas revenues decreased by $198 million (9%) to $2.0 billion, and the cost of natural gas decreased by $91 million (16%) to $494 million. The decrease in natural gas revenues included

§	~~decreases in cost of natural gas sold at SoCalGas and SDG&E, as we discuss below;~~

$83 million of charges at SoCalGas associated with prior years' income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD ($72 million related to 2015 benefits and $11 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals);

§	~~$29 million lower recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;~~

§	~~$19 million increase in 2015 at SoCalGas from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base;~~

§	~~$15 million charge at SoCalGas associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD; and~~

~~$14 million GCIM award approved~~ by the CPUC, in February 2015 at SoCalGas. We include incentive awards in earnings when we receive any required CPUC approval of the award, which may cause timing differences in earnings. In December 2015, SoCalGas received approval of a $7 million pretax GCIM award for the 12-month period ending March 31, 2015; ~~offset by~~

or “refundable programs.”

§	~~$26 million higher revenues at SoCalGas primarily associated with the PSEP and advanced metering assets; and~~

§	~~$25 million higher authorized revenue at SoCalGas in the 2016 GRC FD.~~

~~We discuss the~~Because changes in ~~natural gas revenues~~SDG&E’s and ~~the~~SoCalGas’ cost of electricity and/or 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 for the six months ended June 30, 2016 and 2015. Because the cost of electricity~~ is substantially recovered in rates, changes in ~~the cost~~these costs are reflected in the changes in ~~revenues.~~revenues, and therefore do not impact earnings. In addition to the change in cost or market prices, electric or natural gas revenues recorded during a period are impacted by customer ~~billing cycles~~usage 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 114 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E
ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)

Six months ended
June 30, 2016
Six months ended
June 30, 2015
Customer class Volumes Revenue Volumes Revenue
Residential 3,111 $ 603 3,227 $ 610
Commercial 3,130 586 3,223 656
Industrial 1,007 156 985 162
Direct access 1,606 99 1,696 106
Street and highway lighting 37 7 41 8
8,891 1,451 9,172 1,542
CAISO shared transmission revenue - net(1) 119 126
Other revenues 96 101
Balancing accounts 74 (90)
Total(2) $ 1,740 $ 1,679
(1) California Independent System Operator (CAISO).
(2) Includes sales to affiliates of $3 million in 2016 and $4 million in 2015.

The table below summarizes revenues and cost of sales for our utilities, net of intercompany activity:

~~For~~



UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
Electric revenues:
SDG&E	$	946		$	897		$	1,821		$	1,740
Sempra South American Utilities	362			365			752			743
Eliminations and adjustments	(1		)	(1		)	(3		)	(3		)
Total	1,307			1,261			2,570			2,480
Natural gas revenues:
SoCalGas	770			617			2,011			1,650
SDG&E	112			95			294			243
Sempra Mexico	25			20			55			42
Sempra LNG & Midstream	—			18			—			56
Eliminations and adjustments	(17		)	(17		)	(35		)	(35		)
Total	890			733			2,325			1,956
Total utilities revenues	$	2,197		$	1,994		$	4,895		$	4,436
Cost of electric fuel and purchased power:
SDG&E	$	316		$	314		$	577		$	562
Sempra South American Utilities	237			247			503			514
Total	$	553		$	561		$	1,080		$	1,076
Cost of natural gas:
SoCalGas	$	179		$	147		$	587		$	400
SDG&E	38			25			103			64
Sempra Mexico	15			11			34			23
Sempra LNG & Midstream	—			4			—			15
Eliminations and adjustments	(4		)	(4		)	(11		)	(8		)
Total	$	228		$	183		$	713		$	494

The table below summarizes electric and natural gas volumes billed by our utilities:



UTILITIES VOLUMES
(Electric volumes in millions of kilowatt-hours, natural gas volumes in billion cubic feet)
	Three months ended June 30,		Six months ended June 30,
	2017	2016	2017	2016
Electric volumes:
SDG&E:
Residential	1,388	1,422	3,059	3,111
Commercial	1,632	1,551	3,201	3,130
Industrial	526	519	1,026	1,007
Direct access	786	772	1,573	1,606
Street and highway lighting	19	20	43	37
Total(1)	4,351	4,284	8,902	8,891
Sempra South American Utilities:
Luz del Sur	1,780	1,887	3,674	3,836
Chilquinta Energía	691	682	1,502	1,481
Total	2,471	2,569	5,176	5,317
Natural gas volumes(2):
SoCalGas:
Natural gas sales	61	63	172	162
Transportation	141	138	289	278
Total(1)	202	201	461	440
SDG&E:
Natural gas sales	10	10	25	24
Transportation	7	6	15	14
Total(1)	17	16	40	38
Sempra Mexico – Ecogas	7	7	15	15


(1)	Includes intercompany sales.


(2)	In September 2016, Sempra LNG & Midstream completed the sale of EnergySouth, the parent company of Mobile Gas and Willmut Gas. Volume information for Mobile Gas and Willmut Gas has been excluded from 2016 due to immateriality.

Electric Revenues and Cost of Electric Fuel and Purchased Power

In the three months ended June 30, ~~2016, SDG&E's~~2017, our electric revenues increased by ~~$23~~$46 million ~~(3%~~(4%) to ~~$897 million. The change was primarily~~$1.3 billion due to:

§
▪	$6349 million increase ~~in cost of electric fuel and purchased power, including:~~at SDG&E, which included

□	~~an increase from the incremental purchase of renewable energy at higher prices,~~ ~~offset by~~

□	~~a decrease in the cost of purchased power due to declining natural gas prices, and~~

□	~~a decrease in consumption due to energy efficiency initiatives, including rooftop solar installations;~~

§	~~$14 million favorable impact from the retroactive application of the 2016 GRC FD for the first quarter of 2016;~~

§	~~$13 million higher authorized revenue in the 2016 GRC FD; and~~

§	~~$7 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;~~ ~~offset by~~

§◦	$52 million of charges in 2016 associated with prior ~~years'~~years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD, ~~($37~~


◦	$15 million ~~related~~increase in 2017 due to ~~2015 benefits and $15 million related to~~an increase in rates permitted under the ~~true-up of 2012-2014 estimated benefits used~~attrition mechanism in the 2016 GRC FD, ~~to actuals);~~ and

§
◦	$610 million ~~lower~~higher authorized revenues from electric ~~transmission.~~transmission, offset by

~~In the first six months of 2016, SDG&E's electric revenues increased by $61 million (4%), remaining at $1.7 billion primarily due to:~~

§
◦	$8314 million ~~increase~~favorable impact in ~~cost of electric fuel and purchased power, including:~~

□	~~an increase~~2016 from the ~~incremental purchase~~retroactive application of ~~renewable energy at higher prices,~~ ~~offset by~~

□	~~a decrease in the cost of purchased power due to declining natural gas prices, and~~

□	~~a decrease in consumption due to energy efficiency initiatives, including rooftop solar installations;~~

§	~~$27 million higher authorized revenue in~~ the 2016 GRC ~~FD; and~~FD for the first quarter of 2016,

§
◦	$2514 million ~~higher~~lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in ~~operation~~O&M, and ~~maintenance expenses;~~


◦	$12 million charge in 2017 associated with tracking the income tax benefit from certain flow-through items in relation to the forecasted amounts in the 2016 GRC FD; offset by

§
▪	$3 million decrease at Sempra South American Utilities, which included


◦	$20 million lower volumes at Luz del Sur primarily due to the migration of regulated and non-regulated customers to tolling customers, who pay only a tolling fee and do not contribute to customer load, offset by


◦	$10 million due to higher rates at Luz del Sur, and


◦	$7 million due to foreign currency exchange rate effects.

Our utilities’ cost of electric fuel and purchased power decreased by $8 million (1%) to $553 million in the three months ended June 30, 2017 primarily due to a $10 million decrease at Sempra South American Utilities, which included


▪	$9 million lower costs at Chilquinta Energía; and


▪	$5 million from lower volumes at Luz del Sur, net of higher volume at Chilquinta Energía; offset by


▪	$5 million due to foreign currency exchange rate effects.

In the first six months of 2017, our electric revenues increased by $90 million (4%) to $2.6 billion primarily due to:


▪	$81 million increase at SDG&E, which included


◦	$52 million of charges in 2016 associated with prior ~~years'~~years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD, ~~($37~~


◦	$26 million ~~related~~increase in 2017 due to ~~2015 benefits and $15 million related to~~an increase in rates permitted under the ~~true-up of 2012-2014 estimated benefits used~~attrition mechanism in the 2016 GRC FD, ~~to actuals).~~

~~SDG&E and SoCalGas: Natural Gas Revenues and Cost of Natural Gas~~

The tables below show natural gas revenues for SDG&E and SoCalGas for the six months ended June 30, 2016 and 2015. Because the cost of natural gas is recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in market prices, natural gas revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
Natural gas sales Transportation Total
Customer class Volumes Revenue Volumes Revenue Volumes Revenue
Six months ended June 30, 2016:
    Residential 16 $ 191 ― $ 1 16 $ 192
    Commercial and industrial 8 54 5 11 13 65
    Electric generation plants ― ― 9 1 9 1
24 $ 245 14 $ 13 38 258
    Other revenues 20
    Balancing accounts (35)
        Total(1) $ 243
Six months ended June 30, 2015:
    Residential 14 $ 175 ― $ 2 14 $ 177
    Commercial and industrial 8 53 4 7 12 60
    Electric generation plants ― ― 11 ― 11 ―
22 $ 228 15 $ 9 37 237
    Other revenues 21
    Balancing accounts 1
        Total(1) $ 259
(1) Includes sales to affiliates of a negligible amount in 2016 and $1 million in 2015.

~~During the three months ended June 30, 2016, SDG&E's natural gas revenues decreased by $3 million (3%) to $95 million primarily due to lower cost of natural gas sold.~~

SDG&E's average cost of natural gas for the three months ended June 30, 2016 was $2.75 per thousand cubic feet (Mcf) compared to $3.56 per Mcf for the corresponding period in 2015, a 23-percent decrease of $0.81 per Mcf, resulting in lower revenues and cost of $8 million.

During the six months ended June 30, 2016, SDG&E's natural gas revenues decreased by $16 million (6%) to $243 million, and the cost of natural gas sold decreased by $21 million (25%) to $64 million. The decrease in revenues was primarily due to lower cost of natural gas sold, offset by higher demand.

SDG&E's average cost of natural gas for the six months ended June 30, 2016 was $2.70 per Mcf compared to $3.91 per Mcf for the corresponding period in 2015, a 31-percent decrease of $1.21 per Mcf, resulting in lower revenues and cost of $29 million. The decrease in the cost of natural gas sold was offset by higher sales volumes from a cooler winter in 2016 compared to the same period in 2015, which resulted in higher revenues and cost of $8 million.

SOCALGAS
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
Natural gas sales Transportation Total
Customer class Volumes Revenue Volumes Revenue Volumes Revenue
Six months ended June 30, 2016:
    Residential 113 $ 1,117 1 $ 7 114 $ 1,124
    Commercial and industrial 49 328 144 133 193 461
    Electric generation plants ― ― 69 14 69 14
    Wholesale ― ― 64 11 64 11
162 $ 1,445 278 $ 165 440 1,610
    Other revenues 87
    Balancing accounts (47)
        Total(1) $ 1,650
Six months ended June 30, 2015:
    Residential 102 $ 1,036 2 $ 10 104 $ 1,046
    Commercial and industrial 48 324 141 126 189 450
    Electric generation plants ― ― 69 16 69 16
    Wholesale ― ― 73 13 73 13
150 $ 1,360 285 $ 165 435 1,525
    Other revenues 90
    Balancing accounts 213
        Total(1) $ 1,828
(1) Includes sales to affiliates of $35 million in 2016 and $36 million in 2015.

During the three months ended June 30, 2016, SoCalGas' natural gas revenues decreased by $163 million (21%) to $617 million, and the cost of natural gas sold decreased by $49 million (25%) to $147 million. The revenue decrease included

§	~~the decrease in the~~
◦	$16 million higher authorized revenues from electric transmission, and


◦	$15 million higher cost of ~~natural gas sold,~~electric fuel and ~~lower demand, as~~purchased power, which we discuss ~~below;~~below, offset by

$83 million of charges associated with prior years' income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD ($72 million related to 2015 benefits and $11 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals);

§◦	$24 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in ~~operation and maintenance expenses;~~

§	~~$21 million increase in 2015 from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 and the first quarter of 2015 due to increased rate base;~~O&M, and

§
◦	$1510 million charge ~~associated with tracking the income tax benefit from certain flow-through items~~ in ~~relation to forecasted amounts in the 2016 GRC FD;~~ ~~offset by~~

§	~~$14 million favorable impact from the retroactive application of the 2016 GRC FD for the first quarter of 2016;~~

§	~~$11 million higher authorized revenue in the 2016 GRC FD; and~~

§	~~$14 million higher revenues primarily associated with the PSEP and advanced metering assets.~~

SoCalGas' average cost of natural gas for the three months ended June 30, 2016 was $2.37 per Mcf compared to $3.08 per Mcf for the corresponding period in 2015, a 23-percent decrease of $0.71 per Mcf, resulting in lower revenues and cost of $44 million. The decrease in the cost of natural gas sold was also due to slightly lower sales volumes, which resulted in lower revenues and cost of $5 million.

During the six months ended June 30, 2016, SoCalGas' natural gas revenues decreased by $178 million (10%) to $1.7 billion, and the cost of natural gas sold decreased by $63 million (14%) to $400 million. The revenue decrease included

§	~~the decrease in the cost of natural gas sold, offset by higher demand, as we discuss below;~~

§	~~$29 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;~~

§	~~$19 million increase in 2015 from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base;~~

§	~~$15 million charge~~2017 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD; and

§
▪	$9 million increase at Sempra South American Utilities, which included


◦	$29 million due to foreign currency exchange rate effects, and


◦	$20 million due to higher rates at Luz del Sur, offset by


◦	$37 million lower volumes at Luz del Sur primarily due to the migration of regulated and non-regulated customers to tolling customers, who pay only a tolling fee and do not contribute to customer load.

In the first six months of 2017, our utilities’ cost of electric fuel and purchased power increased by $4 million, remaining at $1.1 billion due to:


▪	$15 million increase at SDG&E mainly due to an increase in the cost of purchased power primarily as a result of higher natural gas prices; offset by


▪	$11 million decrease at Sempra South American Utilities, which included


◦	$24 million lower volumes at Luz del Sur, and


◦	$9 million lower costs at Chilquinta Energía, offset by


◦	$20 million due to foreign currency exchange rate effects.

Natural Gas Revenues and Cost of Natural Gas

The table below summarizes average cost of natural gas sold by the California Utilities and included in Cost of Natural Gas. The average cost of natural gas sold at each utility is impacted by market prices, as well as transportation, tariff and other charges.



CALIFORNIA UTILITIES AVERAGE COST OF NATURAL GAS
(Dollars per thousand cubic feet)
	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
SoCalGas	$	2.96	$	2.37	$	3.44	$	2.49
SDG&E	4.07		2.75		4.17		2.70

In the three months ended June 30, 2017, Sempra Energy’s natural gas revenues increased by $157 million (21%) to $890 million, and the cost of natural gas increased by $45 million (25%) to $228 million. The increase in natural gas revenues was primarily due to:


▪	$153 million increase at SoCalGas, which included


◦	$83 million of charges in 2016 associated with prior years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD,


◦	$32 million increase in cost of natural gas sold, including $36 million from higher average gas prices offset by $4 million from lower volumes driven by slightly warmer weather in the second quarter of 2017 compared to the same period in 2016,


◦	$17 million increase due to 2017 attrition,


◦	$13 million decrease in charges in 2017 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD, and


◦	$13 million higher revenues primarily associated with the PSEP, offset by


◦	$14 million favorable impact in 2016 from the retroactive application of the 2016 GRC FD for the first quarter of 2016; and


▪	$17 million increase at SDG&E, which included


◦	$13 million increase in cost of natural gas sold primarily from higher average gas prices, and


◦	$6 million higher revenues primarily associated with the PSEP.

In the three months ended June 30, 2017, natural gas revenues and cost of natural gas at Sempra LNG & Midstream decreased by $18 million and $4 million, respectively, due to the sale of EnergySouth in September 2016.

In the first six months of 2017, Sempra Energy’s natural gas revenues increased by $369 million (19%) to $2.3 billion, and the cost of natural gas increased by $219 million (44%) to $713 million. The increase in natural gas revenues was primarily due to:


▪	$361 million increase at SoCalGas, which included


◦	$187 million increase in cost of natural gas sold, including $161 million from higher average gas prices and $26 million from higher volumes driven mainly by cooler weather in 2017,


◦	$83 million of charges in 2016 associated with prior years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD,


◦	$33 million increase due to 2017 attrition,


◦	$27 million higher revenues primarily associated with the PSEP,


◦	$18 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in O&M, and


◦	$5 million GCIM award approved by the CPUC in ~~February 2015;~~ ~~offset by~~January 2017; and

§
▪	$2651 million increase at SDG&E, which included


◦	$39 million increase in the cost of natural gas sold primarily from higher average gas prices, and


◦	$10 million higher revenues primarily associated with the ~~PSEP and advanced metering assets; and~~PSEP.

§	~~$25 million higher authorized revenue in the 2016 GRC FD.~~

~~For~~In the first six months of ~~2016, SoCalGas' average~~2017, natural gas revenues and cost of natural gas ~~was $2.49 per Mcf compared to $3.09 per Mcf for the corresponding period in 2015, a 19-percent decrease of $0.60 per Mcf, resulting in lower revenues~~at Sempra LNG & Midstream decreased by $56 million and ~~cost of $96 million. The decrease in the cost of natural gas sold was offset by higher sales volumes from a cooler winter in 2016 compared~~$15 million, respectively, due to the ~~same period~~sale of EnergySouth in ~~2015, which resulted in higher revenues and cost of $33 million.~~September 2016.

~~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 bases for the tariffs do not meet the requirements necessary for regulatory accounting treatment under applicable U.S. GAAP. We discuss revenue recognition further for Chilquinta Energía and Luz del Sur in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

~~Operations of Mobile Gas, Willmut Gas and Ecogas qualify for regulatory accounting treatment under applicable U.S. GAAP, similar to the California Utilities.~~

~~The table below summarizes natural gas and electric revenue for our utilities outside of California for the six months ended June 30, 2016 and 2015:~~

OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES
(Dollars in millions)

Six months ended
June 30, 2016
Six months ended
June 30, 2015
Volumes Revenue Volumes Revenue
Natural Gas Sales (billion cubic feet):
Sempra Mexico – Ecogas 15 $ 42 13 $ 44
Sempra Natural Gas:
   Mobile Gas (including transportation) 24 47 24 49
   Willmut Gas 2 9 2 11
   Total 41 $ 98 39 $ 104

Electric Sales (million kilowatt hours):
Sempra South American Utilities:
   Luz del Sur 3,836 $ 464 3,841 $ 440
   Chilquinta Energía 1,481 258 1,496 266
5,317 722 5,337 706
   Other service revenues 21 20
   Total $ 743 $ 726

~~We discuss changes in electric sales and volumes for Sempra South American Utilities under "Sempra Energy Consolidated – Electric Revenues" above.~~

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
(Dollars in millions)
Three months ended June 30, Six months ended June 30,
2016 2015 2016 2015
REVENUES
  Sempra South American Utilities $ 20 $ 26 $ 42 $ 52
  Sempra Mexico 127 133 243 271
  Sempra Renewables 6 10 13 18
  Sempra Natural Gas 72 137 164 292
  Intersegment revenues, eliminations and adjustments(1) (63) (72) (120) (139)
       Total revenues $ 162 $ 234 $ 342 $ 494
COST OF SALES (2)
Cost of natural gas, electric fuel and purchased power:
  Sempra South American Utilities $ 4 $ 7 $ 8 $ 16
  Sempra Mexico 40 45 75 96
  Sempra Natural Gas 77 87 151 192
  Eliminations and adjustments(1) (59) (66) (116) (133)
       Total $ 62 $ 73 $ 118 $ 171
Other cost of sales:
  Sempra South American Utilities $ 14 $ 18 $ 29 $ 29
  Sempra Mexico 3 4 5 9
  Sempra Natural Gas 211 23 231 43
  Eliminations and adjustments(1) (2) (3) (4) (4)
       Total $ 226 $ 42 $ 261 $ 77
(1) Includes eliminations of intercompany activity.
(2) Excludes depreciation and amortization, which are shown separately on Sempra Energy's Condensed Consolidated Statements of Operations.



ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
REVENUES
Sempra South American Utilities	$	19		$	20		$	41		$	42
Sempra Mexico	248			127			482			243
Sempra Renewables	26			6			48			13
Sempra LNG & Midstream	122			72			254			164
Eliminations and adjustments(1)	(79		)	(63		)	(156		)	(120		)
Total revenues	$	336		$	162		$	669		$	342
COST OF SALES(2)
Cost of natural gas, electric fuel and purchased power:
Sempra South American Utilities	$	4		$	4		$	8		$	8
Sempra Mexico	49			40			100			75
Sempra LNG & Midstream	85			77			173			151
Eliminations and adjustments(1)	(76		)	(59		)	(152		)	(116		)
Total	$	62		$	62		$	129		$	118
Other cost of sales:
Sempra South American Utilities	$	12		$	14		$	27		$	29
Sempra Mexico	—			3			3			5
Sempra LNG & Midstream	(50		)	211			(43		)	231
Eliminations and adjustments(1)	—			(2		)	(3		)	(4		)
Total	$	(38	)	$	226		$	(16	)	$	261


(1)	Includes eliminations of intercompany activity.


(2)	Excludes depreciation and amortization, which are shown separately on Sempra Energy’s Condensed Consolidated Statements of Operations.

~~During~~

In the three months ended June 30, ~~2016,~~2017, revenues from our energy-related businesses ~~decreased~~increased by ~~$72~~$174 million ~~(31%)~~ to ~~$162 million. The decrease included~~$336 million primarily due to:

§	~~$65 million decrease at Sempra Natural Gas associated with midstream and LNG marketing activities, including:~~

□▪	$55121 million ~~primarily driven by changes in natural gas prices and lower volumes,~~

□	~~$6 million lower power revenues due to the sale of the second block of Mesquite Power in April 2015, and~~

□	~~$4 million from lower natural gas sales to Sempra Mexico;~~

§	~~$6 million lower revenues~~ increase at Sempra Mexico primarily due to:


◦	$88 million due to ~~lower power prices~~the acquisition of the remaining 50-percent interest in IEnova Pipelines (formerly known as GdC) in September 2016 and ~~volumes~~from other pipeline assets placed in ~~its power business, including $7 million decrease at the TdM power plant;~~service, and

§
◦	$627 million ~~decrease~~due to the acquisition of Ventika in December 2016;


▪	$50 million increase at Sempra ~~South American Utilities~~LNG & Midstream primarily due to ~~lower commercial energy sales~~mark-to-market losses in 2016 from natural gas marketing activities and ~~foreign currency exchange rate effects;~~ from changes in natural gas prices; and


▪	$20 million higher revenues at Sempra Renewables primarily due to solar and wind assets placed in service during 2016; offset by

§
▪	$916 million primarily from ~~lower~~higher intercompany eliminations associated with sales between Sempra ~~Natural Gas~~LNG & Midstream and Sempra Mexico.

~~During~~In the three months ended June 30, ~~2016,~~2017, the cost of natural gas, electric fuel and purchased power for our energy-related businesses ~~decreased by $11 million (15%) to~~remained at $62 million ~~primarily due to:~~and included

§
▪	$109 million ~~decrease at Sempra Natural Gas primarily due to lower natural gas costs;~~

§	~~$5 million decrease~~increase at Sempra Mexico primarily due to ~~lower~~higher natural gas costs; and

§
▪	$38 million ~~decrease~~increase at Sempra ~~South American Utilities~~LNG & Midstream primarily due to ~~lower costs related to commercial energy sales;~~ higher natural gas costs; offset by

§
▪	$717 million primarily from ~~lower~~higher intercompany eliminations of costs associated with sales between Sempra ~~Natural Gas~~LNG & Midstream and Sempra Mexico.

~~During the~~Other cost of sales decreased by $264 million in three months ended June 30, ~~2016, the increase~~2017, primarily due to a $206 million charge in ~~other cost of sales of $184 million included $206 million~~2016 related to Sempra ~~Natural Gas'~~LNG & Midstream’s permanent release of certain pipeline capacity and $57 million settlement proceeds in May 2017 from a breach of contract claim against a counterparty, of which $47 million is related to the charge in 2016 from permanent release of pipeline capacity.

~~For~~In the first six months of ~~2016,~~2017, revenues from our energy-related businesses ~~decreased~~increased by ~~$152~~$327 million ~~(31%)~~ to ~~$342~~$669 million. The ~~decrease~~increase included

§
▪	$~~128~~239 million ~~decrease~~increase at Sempra ~~Natural Gas associated with midstream~~Mexico primarily due to:


◦	$164 million due to the acquisition of the remaining 50-percent interest in IEnova Pipelines in September 2016 and from other pipeline assets placed in service, and


◦	$53 million due to the acquisition of Ventika in December 2016;


▪	$90 million increase at Sempra LNG & Midstream, which included


◦	$75 million primarily due to mark-to-market losses in 2016 from natural gas marketing activities ~~including:~~

□	~~$74 million primarily driven by~~and from changes in natural gas prices, and ~~lower volumes,~~

□
◦	$~~33 million lower power revenues due to the sale of the second block of Mesquite Power in April 2015, and~~

□	~~$21~~16 million from ~~lower~~higher natural gas sales to Sempra Mexico; and

§
▪	$2835 million ~~lower revenues~~increase at Sempra ~~Mexico~~Renewables primarily due to ~~lower power prices~~solar and ~~volumes~~wind assets placed in ~~its power business, including $22 million decrease at the TdM power plant, and lower natural gas prices in its gas business; and~~

§	~~$10 million decrease at Sempra South American Utilities primarily due to lower commercial energy sales and foreign currency exchange rate effects, partially~~ service during 2016; offset by ~~higher materials and services revenues;~~ ~~offset by~~

§
▪	$1936 million ~~primarily~~ from ~~lower~~higher intercompany eliminations associated with sales between Sempra ~~Natural Gas~~LNG & Midstream and Sempra Mexico.

~~For~~In the first six months of ~~2016,~~2017, the cost of natural gas, electric fuel and purchased power for our energy-related businesses ~~decreased~~increased by ~~$53~~$11 million ~~(31%~~(9%) to ~~$118~~$129 million primarily due to:

§
▪	$4125 million ~~decrease at Sempra Natural Gas primarily due to lower natural gas costs and volumes and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015;~~

§	~~$21 million decrease~~increase at Sempra Mexico primarily due to ~~lower~~higher natural gas costs; and

§
▪	$822 million ~~decrease~~increase at Sempra ~~South American Utilities~~LNG & Midstream primarily due to ~~lower costs related to commercial energy sales and foreign currency exchange rate effects;~~ higher natural gas costs;offset by

§
▪	$1736 million ~~primarily~~ from ~~lower~~higher intercompany eliminations of costs associated with sales between Sempra ~~Natural Gas~~LNG & Midstream and Sempra Mexico.

~~During~~In the first six months of ~~2016, the increase in~~2017, other cost of sales ~~of $184~~decreased by $277 million ~~included~~primarily due to a $206 million charge in 2016 related to Sempra ~~Natural Gas'~~LNG & Midstream’s permanent release of certain pipeline capacity and $57 million settlement proceeds in May 2017 from a breach of contract claim against a counterparty, of which $47 million is related to the charge in 2016 from permanent release of pipeline capacity.

Operation and Maintenance

~~Sempra Energy Consolidated~~

Our ~~operation and maintenance expenses~~O&M increased by ~~$14~~$25 million ~~(2%~~(4%) to ~~$727~~$731 million in the three months ended June 30, ~~2016 and increased by $57 million (4%), remaining at $1.4 billion in the first six months of 2016.~~

~~SDG&E~~

~~For the three months ended June 30, 2016, SDG&E's operation and maintenance expenses increased by $11 million (4%) to $266 million~~2017 primarily due to:

§
▪	$930 million increase at ~~Otay Mesa VIE~~Sempra Mexico, primarily ~~due to~~at IEnova Pipelines and Ventika, and from scheduled major maintenance at TdM in the ~~Otay Mesa Energy Center (OMEC) plant;~~second quarter of 2017; and

§
▪	$18 million increase at SoCalGas, which included


◦	$15 million higher non-refundable operating costs, including labor, contract services and administrative and support costs, and


◦	$64 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses);offset by

§
▪	$729 million decrease at SDG&E, which included


◦	$13 million lower ~~litigation expense, $6~~expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses),


◦	$10 million ~~of which is non-refundable.~~decrease at Otay Mesa VIE primarily due to scheduled major maintenance in 2016 at the OMEC plant, and


◦	$10 million lower non-refundable operating costs, including labor, contract services and administrative and support costs.

InDuring the first six months of ~~2016, SDG&E's operation and maintenance expenses~~2017, O&M increased by ~~$40~~$39 million ~~(8%~~(3%) to ~~$512 million~~$1.4 billion primarily due to:

§
▪	$2446 million increase at Sempra Mexico primarily at IEnova Pipelines and Ventika, and from scheduled major maintenance at TdM in the second quarter of 2017; and


▪	$45 million increase at SoCalGas, which included


◦	$30 million higher non-refundable operating costs, including labor, contract services and administrative and support costs, and


◦	$18 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses);

§	~~$12 million higher non-refundable operating costs, including labor, contract services and administrative and support costs; and~~

§	~~$9 million at Otay Mesa VIE primarily due to major maintenance at the OMEC plant;~~ offset by

§
▪	$648 million ~~lower litigation expense, $5 million of~~decrease at SDG&E, which ~~is non-refundable.~~included

~~SoCalGas~~

~~For the three months ended June 30, 2016, SoCalGas' operation and maintenance expenses decreased by $7 million (2%) to $339 million primarily due to:~~

§
◦	$2423 million lower expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses);,


◦	$11 million reimbursement of litigation costs associated with the arbitration ruling over the SONGS replacement steam generators, as we discuss in Note 9 of the Notes to the Condensed Consolidated Financial Statements herein,


◦	$10 million decrease at Otay Mesa VIE primarily due to scheduled major maintenance in 2016 at the OMEC plant, and

§
◦	$75 million lower non-refundable operating costs, including labor, contract services and administrative and support costs; ~~offset by~~and

§
▪	$2122 million ~~impairment of assets related~~decrease at Sempra LNG & Midstream, primarily from lower costs due to the ~~Southern Gas System Reliability project; and~~sale of EnergySouth.

§	~~$3 million higher litigation expense, including $6 million from the favorable resolution of a legal settlement in 2015, offset by $3 million lower other litigation expense.~~

~~In the first six months of 2016, SoCalGas' operation and maintenance expenses increased by $6 million (1%) to $666 million primarily due to:~~

§	~~$21 million impairment of assets related to the Southern Gas System Reliability project;~~

§	~~$7 million higher non-refundable operating costs, including labor, contract services and administrative and support costs; and~~

§	~~$6 million higher litigation expense primarily from the favorable resolution of a legal settlement in 2015;~~ ~~offset by~~

§	~~$29 million lower expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses).~~

~~Plant Closure Adjustment~~

In the first quarter of 2015, SDG&E recorded a $21 million pretax reduction to the loss from plant closure. We discuss SONGS further in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

~~Gain on Sale of Assets~~Impairment Losses

In the second quarter of ~~2015,~~2017, Sempra ~~Natural Gas completed~~Mexico reduced the ~~sale~~carrying value of ~~the remaining 625-MW block of the Mesquite Power plant for net cash proceeds of $347 million, resulting in~~TdM by recognizing a ~~pretax gain on sale of the asset of $61 million ($36 million after-tax).~~

~~Equity Earnings (Losses), Before Income Tax~~

Equity losses, before income tax, for the six months ended June 30, 2016 were $8 million compared to equity earnings, before income tax, of $46 million for the same period in 2015. The change was primarily due to a $44 million ($27 million after-tax)noncash impairment charge ~~related to Sempra Natural Gas' investment in Rockies Express,~~of $71 million, which we discuss ~~further~~ in Notes 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein. In the second quarter of 2016, SoCalGas recorded a $21 million ($13 million after-tax) impairment of assets related to the Southern Gas System Reliability Project.

Equity Earnings (Losses), Before Income Tax

Equity earnings, before income tax, for the six months ended June 30, 2017 were $21 million compared to equity losses, before income tax, of $8 million for the same period in 2016. The change was primarily due to a $44 million impairment charge in the first quarter of 2016 related to Sempra LNG & Midstream’s investment in Rockies Express, offset by $19 million lower equity earnings in 2017 as a result of the sale of our 25-percent interest in Rockies Express in May 2016. We discuss the impairment charge and sale further in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Income, Net

In 2017, as part of our central risk management function, we entered into foreign currency derivatives to hedge Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova. These foreign currency derivatives have notional amounts totaling $850 million and expire in December 2017. The gains associated with these derivatives are included in Other Income, Net, as described below, and partially mitigate the transactional effects of foreign currency and inflation included in “Income Taxes” and in earnings from Sempra Mexico’s equity method investments. We discuss policies governing our risk management in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk” in the Annual Report.

Other income, net, increased by $68 million to $91 million in the three months ended June 30, 2017 primarily due to:

$31 million from net gains in 2017 on foreign currency derivatives compared to $15 million losses in 2016 primarily as a result of significant appreciation of the Mexican peso;


▪	$10 million increase in equity-related AFUDC primarily at Sempra Mexico mainly from the Ojinaga and San Isidro pipeline projects; and


▪	$7 million foreign currency transactional gains in 2017 compared to $5 million losses in 2016.

Other income, net, increased by $188 million to $260 million in the first six months of 2017 primarily due to:

$94 million from net gains in 2017 on foreign currency derivatives compared to $12 million losses in 2016 primarily as a result of significant appreciation of the Mexican peso;


▪	$55 million increase in equity-related AFUDC primarily at Sempra Mexico mainly from the Ojinaga and San Isidro pipeline projects; and


▪	$17 million foreign currency transactional gains in 2017 compared to $7 million losses in 2016.

Interest Expense

Interest expense increased by $43 million (15%) to $328 million in the first six months of 2017 primarily at Sempra Mexico mainly from the recognition of AFUDC for the Ojinaga and San Isidro pipeline projects and from interest on debt assumed in the IEnova Pipelines and Ventika acquisitions in the second half of 2016.

Income Taxes

The table below shows the income tax expense and effective income tax rates for Sempra Energy, SDG&E and SoCalGas.



INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Income tax expense		Effective income tax rate		Income tax (benefit) expense			Effective income tax rate
	Three months ended June 30,
	2017				2016
Sempra Energy Consolidated	$	167	40	%	$	(106	)	95	%
SDG&E	54		26		48			36
SoCalGas	19		24		(29		)	100

	Six months ended June 30,
	2017				2016(1)
Sempra Energy Consolidated	$	462	39	%	$	2		1	%
SDG&E	144		32		113			34
SoCalGas	117		31		54			21


(1)	Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Energy Consolidated

The income tax ~~benefit~~expense in the three months ended June 30, ~~2016~~2017 compared to income tax ~~expense~~benefit in the same period in ~~2015~~2016 was due to apretax income in 2017 compared to pretax loss in ~~the period~~2016. Pretax loss in ~~2016. The pretax loss~~2016 includes the charges associated with prior ~~years'~~years’ tax repairs deductions as a result of the 2016 GRC FD at the California Utilities and losses from the permanent release of pipeline capacity at Sempra ~~Natural Gas. Pretax income in 2015 included the gain from the sale of the Mesquite Power plant.~~LNG & Midstream. Items affecting the effective income tax rate ~~in 2016 include~~include:

§
▪	$52 million income tax expense in 2017 compared to $22 million income tax benefit in 2016 from foreign currency and inflation effects as a result of significant appreciation of the Mexican peso in 2017; and


▪	$25 million valuation allowance in 2017 against deferred tax assets at TdM that is held for sale, including $12 million associated with the 2017 impairment. We discuss the planned sale and the impairment further in Notes 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein; offset by


▪	higher forecasted flow-through items as a percentage of pretax ~~loss;~~income in 2017;

§
▪	$3 million tax benefit in 2017 from a reduction to the outside basis deferred tax liability, net of valuation allowance, compared to $3 million tax expense in 2016 on our outside basis difference in TdM that is held for sale; and


▪	$9 million favorable resolution of prior years’ income tax items in 2017.

The increase in income tax expense in the first six months of 2017 was due to higher pretax income and a higher effective income tax rate. The higher effective income tax rate was primarily due to:


▪	$149 million income tax expense in 2017 compared to $22 million income tax benefit in 2016 from foreign currency ~~translation~~ and inflation ~~adjustments;~~effects as a result of significant appreciation of the Mexican peso in 2017;


▪	$25 million valuation allowance in 2017 against deferred tax assets at TdM that is held for sale, including $12 million associated with the 2017 impairment; and

§	~~lower~~
▪	$2 million income tax expense in 2017 compared to $34 million income tax benefit in 2016 associated with excess tax deficiencies/benefits related to share-based compensation; offset by

▪

$9 million U.S. income tax expense ~~as a result of lower~~in 2016 on planned repatriation of ~~current year~~ earnings from certain non-U.S. subsidiaries. We discuss repatriation in ~~"Results~~“Results of Operations –- Changes in Revenues, Costs and Earnings –- Income ~~Taxes"~~Taxes” in ~~"Management's~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” in the Annual ~~Report.~~Report;

§	~~higher flow-through items as a percentage of pretax income in 2016; and~~

§▪	~~higher income~~$8 million tax benefit in ~~2016~~2017 from ~~foreign currency translation and inflation adjustments;~~ ~~offset by~~

§	~~$32~~a reduction to the outside basis deferred tax liability, net of valuation allowance, compared to $32 million ~~deferred Mexican income~~ tax expense in 2016 on our outside basis difference in TdM ~~as a result~~that is held for sale; and


▪	$9 million favorable resolution of ~~management's decision to hold the asset for sale. We discuss the planned sale further~~prior years’ income tax items in ~~Note 3 of the Notes to Condensed Consolidated Financial Statements herein.~~2017.

SDG&E

The ~~decrease~~increase in SDG~~&E's~~&E’s income tax expense in the three ~~and six~~ months ended June 30, ~~2016 compared to the same periods in 2015~~2017 was ~~primarily~~ due to ~~lower~~higher pretax income offset by a ~~higher~~lower effective income tax rate. Pretax income in 2016 includes the charges associated with prior ~~years'~~years’ tax repairs deductions as a result of the 2016 GRC FD. The ~~higher~~lower effective income tax rate was primarily due to:

§	~~favorable resolution of prior years' income tax items in 2015; and~~

§	~~Otay Mesa VIE's pretax loss in 2016 compared to pretax income in 2015, which is excluded from SDG&E's and Sempra Energy Consolidated's taxable income;~~ ~~offset by~~

§▪	higher forecasted flow-through items as a percentage of pretax income in ~~2016.~~2017; and


▪	$8 million favorable resolution of prior years’ income tax items in 2017.

~~SoCalGas~~

~~SoCalGas' income tax benefit~~The increase in ~~the three months ended June 30, 2016 compared to~~SDG&E’s income tax expense in the ~~same period in 2015~~first six months of 2017 was due to a pretax loss in the period in 2016. The pretax loss includes the charges associated with prior years' tax repairs deductions as a result of the 2016 GRC FD. In addition, the effective income tax rate in 2016 was affected by higher ~~flow-through items as a percentage of pretax loss.~~

~~The decrease in SoCalGas' income tax expense in the six months ended June 30, 2016 compared to the same period in 2015 was primarily due to lower~~ pretax income ~~as discussed for the second quarter above, and~~offset by a lower effective income tax rate. The lower effective income tax rate was primarily due to:


▪	higher forecasted flow-through items as a percentage of pretax income in 2017; and


▪	$8 million favorable resolution of prior years’ income tax items in 2017; offset by


▪	$7 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation.

SoCalGas

SoCalGas’ income tax expense in the three months ended June 30, 2017 compared to income tax benefit in the same period in 2016 was due to pretax income in 2017 compared to pretax loss in 2016. The pretax loss in 2016 includes the charges associated with prior years’ tax repairs deductions as a result of the 2016 GRC FD.

The increase in SoCalGas’ income tax expense in the first six months of 2017 was due to higher pretax income and a higher effective income tax rate. The higher effective income tax rate was primarily due to lower forecasted flow-through ~~items~~deductions as a percentage of pretax income in ~~2016.~~2017 and an income tax benefit of $4 million in 2016 associated with excess tax benefits related to share-based compensation.

We discuss the forecasted effective tax rates anticipated for the full year, excluding the income tax effects that cannot be reliably forecasted, for Sempra Energy, SDG&E and SoCalGas in ~~"Results~~“Results of Operations – Changes in Revenues, Costs and Earnings – Income ~~Taxes"~~Taxes” in ~~"Management's~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” in the Annual Report. We discuss the impact of foreign exchange rates and inflation on income taxes below in ~~"Impact~~“Impact of Foreign Currency and Inflation Rates on Results of Operations."” See Note 5 of the Notes to Condensed Consolidated Financial Statements herein and Notes 1 and 6 of the Notes to Consolidated Financial Statements in the Annual Report for further details about our accounting for income ~~taxes.~~taxes and items subject to flow-through treatment.

Equity Earnings (Losses), Net of Income Tax

Equity earnings, net of income tax, were negligible for the three months ended June 30, 2017 compared to $33 million for the same period in 2016. The change was primarily due to $29 million of equity earnings in 2016 from IEnova Pipelines (formerly known as GdC), including $11 million from DEN, prior to IEnova’s acquisition of the remaining 50-percent interest in IEnova Pipelines in September 2016, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. In the three months ended June 30, 2017, there was a $1 million equity loss at DEN, primarily from foreign currency and inflation effects.

Equity losses, net of income tax, were $8 million for the six months ended June 30, 2017 compared to equity earnings, net of tax, of $50 million for the same period in 2016. The change was primarily due to:


▪	$44 million of equity earnings in 2016 from IEnova Pipelines, including $12 million from DEN, prior to IEnova’s acquisition of the remaining 50-percent interest in IEnova Pipelines in September 2016; and


▪	$11 million of equity losses in 2017 at DEN primarily from foreign currency and inflation effects.

Losses (Earnings) Attributable to Noncontrolling Interests

~~Earnings~~Losses attributable to noncontrolling interests ~~decreased by $14 million and $24 million in the three months and six months ended June 30, 2016, respectively, primarily due to changes at SDG&E.~~

~~SDG&E~~

~~Losses attributable to noncontrolling interest~~ were ~~$13~~$12 million in the three months ended June 30, ~~2016,~~2017 compared to earnings of $4$10 million ~~for~~in the same period ~~in 2015.~~ of 2016 primarily due to:


▪	$15 million losses attributable to noncontrolling interests in 2017 compared to $16 million earnings attributable to noncontrolling interest in 2016 at IEnova, including:


◦	$25 million higher losses attributable to noncontrolling interests from foreign currency and inflation effects without the corresponding benefit from foreign currency derivatives that are not subject to noncontrolling interests, as we discuss above in “Other Income, Net,”


◦	$8 million lower earnings attributable to noncontrolling interests as a result of the decrease in earnings, excluding the effects of foreign currency and inflation, as we discuss above in “Segment Results – Sempra Mexico;” offset by


◦	$2 million higher earnings attributable to noncontrolling interests, excluding the effects of foreign currency and inflation, from the decrease in our controlling interest from 81.1 percent to 66.4 percent following IEnova’s equity offerings in October 2016, which we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report; and


▪	$7 million attribution of losses to tax equity investors at Sempra Renewables; offset by


▪	$17 million increase in earnings at Otay Mesa VIE primarily as a result of scheduled major maintenance at the OMEC plant in 2016.

Losses attributable to noncontrolling ~~interest~~interests were ~~$12~~$1 million infor the six months ended June 30, ~~2016,~~2017 compared to earnings of $8$21 million ~~for~~in the same period ~~in 2015. The changes were~~of 2016 primarily due ~~to an increase in operating expenses~~to:


▪	$10 million losses attributable to noncontrolling interests in 2017 compared to $21 million earnings attributable to noncontrolling interest in 2016 at IEnova, including:


◦	$57 million higher losses attributable to noncontrolling interests from foreign currency and inflation effects without the corresponding benefit from foreign currency derivatives that are not subject to noncontrolling interests, offset by


◦	$18 million higher earnings attributable to noncontrolling interests, excluding the effects of foreign currency and inflation, from the decrease in our controlling interest from 81.1 percent to 66.4 percent following IEnova’s equity offerings in October 2016, and


◦	$8 million higher earnings attributable to noncontrolling interests as a result of the increase in earnings, excluding the effects of foreign currency and inflation, as we discuss above in “Segment Results – Sempra Mexico;” and


▪	$10 million attribution of losses to tax equity investors at Sempra Renewables; offset by


▪	$18 million increase in earnings at Otay Mesa VIE primarily as a result of scheduled major maintenance at the OMEC plant in ~~the second quarter of~~ 2016.

IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS

~~Earnings~~

~~We discuss variations in earnings by segment above in "Segment Results."~~

~~Impact of Foreign Currency and Inflation Rates on Results of Operations~~

~~Foreign Currency Translation~~

~~Our~~Because our operations in South America and our natural gas distribution utility in Mexico use their local currency as their functional ~~currency. The assets~~currency, revenues and ~~liabilities of these foreign operations~~expenses 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 ~~reporting period. The resulting noncash translation adjustments do not enter into~~period for consolidation in Sempra Energy Consolidated’s results of operations. Some income statement activities at our foreign operations and their joint ventures are also impacted by transactional gains and losses. We discuss the ~~calculation~~impact of ~~earnings or retained earnings, but are reflected~~foreign currency and inflation rates on results of operations, including impacts on income taxes and related hedging activity, further in ~~Other Comprehensive Income (Loss) (OCI)~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Impact of Foreign Currency and Inflation Rates on Results of Operations” in ~~Accumulated Other Comprehensive Income (Loss) (AOCI). However, any~~the Annual Report.

Foreign Currency Translation

Any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra ~~Energy's~~Energy’s comparative results of operations. Changes in foreign currency translation rates between years impacted our comparative reported results as follows:

TRANSLATION IMPACT FROM CHANGE IN AVERAGE FOREIGN CURRENCY EXCHANGE RATES
(Dollars in millions)

Second quarter 2016
compared to second quarter 2015

Year-to-date 2016
compared to
year-to-date 2015
Lower earnings from foreign currency translation:
Sempra South American Utilities $ 4 $ 9
Sempra Mexico 1 2
Total $ 5 $ 11



TRANSLATION IMPACT FROM CHANGE IN AVERAGE FOREIGN CURRENCY EXCHANGE RATES
(Dollars in millions)
	Second quarter 2017 compared to second quarter 2016		Year-to-date 2017 compared to year-to-date 2016
Higher earnings from foreign currency translation:
Sempra South American Utilities	$	1	$	3

Foreign Currency Transactional Impacts

~~Some income statement activities at our foreign operations and their joint ventures are also impacted by transactional gains and losses, which we discuss below. A summary of these foreign~~Foreign currency transactional gains and losses included in our reported results isare as follows:

TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION
(Dollars in millions)
Transactional
(losses) gains included
Total reported amount in reported amounts
Three months ended June 30,
2016 2015 2016 2015
Other income, net $ 23 $ 37 $ (20) $ (5)
Income tax (benefit) expense (106) 98 23 7
Equity earnings, net of income tax 33 22 17 5
Earnings 16 295 17 6
Six months ended June 30,
2016 2015 2016 2015
Other income, net $ 72 $ 76 $ (19) $ (6)
Income tax expense 36 261 24 13
Equity earnings, net of income tax 50 37 18 6
Earnings 335 732 20 11



TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION
(Dollars in millions)
	Total reported amounts						Transactional gains (losses) included in reported amounts
	Three months ended June 30,
	2017			2016			2017			2016
Other income, net	$	91		$	23		$	39		$	(20	)
Income tax (expense) benefit	(167		)	106			(52		)	23
Equity earnings, net of income tax	—			33			(9		)	17
Net income	248			27			(35		)	23
Earnings	259			16			(18		)	17
	Six months ended June 30,
	2017			2016(1)			2017			2016
Other income, net	$	260		$	72		$	114		$	(19	)
Income tax expense	(462		)	(2		)	(149		)	24
Equity (losses) earnings, net of income tax	(8		)	50			(22		)	18
Net income	700			391			(96		)	26
Earnings	700			369			(45		)	20


(1)	Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

~~Foreign Currency Exchange Rate and Inflation Impacts on Income Taxes and Related Hedging Activity.~~ Our Mexican subsidiaries have U.S. dollar denominated cash balances, receivables, payables and debt (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 denominated in the Mexican peso that must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation may expose us to fluctuations in Income Tax Expense and Equity Earnings, Net of Income Tax. We utilize short-term foreign currency derivatives as a means to manage these exposures. The derivative activity impacts Other Income, Net.

~~The income tax expense of our South American subsidiaries is similarly impacted by these factors.~~

~~Other Transactions.~~ Although the financial statements of our Mexican subsidiaries and joint ventures (Gasoductos de Chihuahua, or GdC, and Energía Sierra Juárez) have the U.S. dollar as the functional currency, some transactions may be denominated in the local currency; such transactions are remeasured into U.S. dollars. This remeasurement creates transactional gains and losses that are included in Other Income, Net, for our consolidated subsidiaries and Equity Earnings, Net of Income Tax, for our joint ventures.

We utilize cross-currency swaps that exchange our Mexican-peso denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. The impacts of these cross-currency swaps are offset in OCI and are reclassified from AOCI into earnings through Interest Expense as settlements occur.

Certain of our Mexican joint venture projects (Los Ramones I and Los Ramones Norte) generate revenue based on tariffs that are set by government agencies in Mexico, with contracts denominated in Mexican pesos that are indexed to the U.S. dollar, adjusted annually for inflation and fluctuation in the exchange rate. The resultant gains and losses from remeasuring the local currency amounts into U.S. dollars are included in Equity Earnings, Net of Income Tax. The activity of foreign currency forwards and swaps related to these contracts settle through Equity Earnings, Net of Income Tax.

Our South American joint ventures (Eletrans S.A. and Eletrans II S.A., collectively Eletrans) use the U.S. dollar as the functional currency, but have certain construction commitments that are denominated in the Chilean Unidad de Fomento (CLF). Eletrans entered into forward exchange contracts to manage the foreign currency exchange risk of the CLF relative to the U.S. dollar. The forward exchange contracts settle based on anticipated payments to vendors, generally monthly, ending in 2018, with activity recorded in Equity Earnings, Net of Income Tax.

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW

We expect ~~our cash flows from operations~~ to ~~fund a substantial portion of our capital expenditures and dividends. We may also~~ meet our cash requirements through ~~the issuance of securities, bank~~cash flows from operations, unrestricted cash and cash equivalents, borrowings under our credit facilities, distributions from our equity method investments, issuances of securities, project financing and ~~project financing.~~equity sales, including tax equity and partnering in joint ventures.

Our lines of credit provide liquidity and support commercial paper. As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each have five-year revolving credit facilities expiring in 2020. The ~~agreements are syndicated broadly among 20 different lenders. No single lender has greater than a 7-percent share in any agreement. The~~ table below shows the amount of available funds, including available unused credit on these three credit facilities, at June 30, ~~2016.~~2017. Our foreign operations have additional general purpose credit facilities aggregating ~~$1.1~~$1.7 billion, with $1 billion available unused credit at June 30, ~~2016.~~ 2017.



AVAILABLE FUNDS AT JUNE 30, 2017
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E		SoCalGas
Unrestricted cash and cash equivalents(1)	$	223	$	12	$	38
Available unused credit(2)(3)	3,094		745		750


(1)	Amounts at Sempra Energy Consolidated include $150 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated. We discuss repatriation in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.


(2)	Available unused credit is the total available on Sempra Energy’s, Sempra Global’s and the California Utilities’ credit facilities that we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. Borrowings on the shared line of credit at SDG&E and SoCalGas are limited to $750 million for each utility and a combined total of $1 billion.

(3) Because the commercial paper programs are supported by these lines, ~~totaled $843 million at June 30, 2016.~~we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.

AVAILABLE FUNDS AT JUNE 30, 2016
(Dollars in millions)
Sempra Energy
Consolidated SDG&E SoCalGas
Unrestricted cash and cash equivalents(1) $ 616 $ 8 $ 211
Available unused credit(2) 2,589 696 750
(1) Amounts at Sempra Energy Consolidated include $328 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 6 of the Notes to Condensed Consolidated Financial Statements herein. At June 30, 2016, borrowings on the shared line of credit at SDG&E and SoCalGas were limited to $750 million for each utility and a combined total of $1 billion.

Sempra Energy Consolidated

We believe that these available funds, combined with cash flows from operations, distributions from our equity method investments, ~~proceeds~~issuances of securities, ~~issuances,~~ project financing and equity sales, including tax equity and partnering in joint ventures, 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

§
▪	fund expenditures related to the natural gas leak at ~~SoCalGas'~~SoCalGas’ Aliso Canyon natural gas storage facility

In May 2016, SDG&E issued $500 million of 2.50-percent first mortgage bonds maturing in 2026. In June 2016, SoCalGas issued $500 million of 2.60-percent first mortgage bonds, also maturing in 2026. In 2015, Sempra Energy, SDG&E and SoCalGas publicly offered and sold debt securities totaling $1.25 billion, $390 million and $600 million, respectively. Sempra Energy and the California Utilities currently 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 commencement and completion of large ~~projects at Sempra International and Sempra U.S. Gas & Power.~~projects. 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~~Infrastructure businesses before we would reduce funds necessary for the ongoing needs of our utilities. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain ~~strong,~~our investment-grade credit ratings and capital structure.

The net increase in Sempra Energy Consolidated cash and cash equivalents at June 30, 2016 compared to December 31, 2015 of $213 million was primarily due to net increases in publicly traded debt securities and commercial paper borrowings on the Sempra Global and California Utilities credit facilities and proceeds received from the sale of our 25-percent interest in Rockies Express, partially offset by capital expenditures, cash outflows related to the natural gas leak at the Aliso Canyon facility, and common dividends paid. We discuss our Insurance Receivable and our insurance coverage related to the natural gas leak at the Aliso Canyon facility in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

At June 30, 2016, our cash and cash equivalents held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated are $328 million. We discuss repatriation in "Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report.

We have 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 return, 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.

We discuss our principal, general purpose credit facilities more fully in Note 6 of the Notes to Condensed Consolidated Financial Statements herein and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.

Our short-term debt is primarily used to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures and 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 the first six months of ~~2016.~~2017. At our California Utilities, short-term debt is used primarily to meet working capital ~~needs~~needs.

We have significant investments in several trusts to provide for future payments of pensions and ~~temporarily finance capital expenditures.~~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 return, mortality tables, and regulations, impact funding requirements for pension and other postretirement benefit plans and SDG&E’s NDT. At the California Utilities, funding requirements are generally recoverable in rates. We discuss our employee benefit plans and SDG&E’s NDT, including our investment allocation strategies for assets in these trusts, in Notes 7 and 13, respectively, of the Notes to Consolidated Financial Statements in the Annual Report.

Loans to Affiliates

At June 30, 2017, Sempra Energy has provided loans to unconsolidated affiliates totaling $399 million, which we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

California Utilities

SDG&E and SoCalGas expect that the available funds described above, cash flows from operations, and debt issuances will continue to be adequate to ~~meet~~fund their ~~working capital and capital expenditure requirements.~~respective operations.

~~SoCalGas~~SDG&E declared and paid common stock dividends of ~~$50~~$175 million in ~~2015~~the year ended December 31, 2016 and ~~$100~~an additional $175 million in ~~2014.~~ the first quarter of 2017. In July 2017, SDG&E declared and paid common stock dividends of $275 million. SDG&E expects to pay dividends approximating 75 percent of its earnings in 2017, subject to the discretion and approval of its board of directors.

As a result of ~~an increase in SoCalGas'~~SoCalGas’ large capital investment ~~programs~~program, SoCalGas has not declared or paid common stock dividends since 2015. SoCalGas does not anticipate paying common stock dividends in 2017, in order to maintain its authorized capital structure while managing its large capital program of over $1 billion in 2017.

Changes in balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change in status between over- and under- collected, may have a significant impact on cash flows, as these changes generally represent the ~~next few years,~~difference between when costs are incurred and when they are ultimately recovered in rates through billings to customers. SDG&E uses the ERRA balancing account to record the net of its actual cost incurred for electric fuel and purchased power. SDG&E’s ERRA balance was undercollected by $130 million at June 30, 2017 and $25 million at December 31, 2016. During the first six months of 2017, the increase in ~~SoCalGas'~~the ERRA undercollected balance was primarily due to lower electric volume in conjunction with seasonalized electric rates. The CPUC authorized ~~common equity weighting effective January 1, 2013, SoCalGas' dividends on common stock declared on~~ an ~~annual historical basis may not be indicative~~ERRA Trigger mechanism in conjunction with California state law that allows for recovery of future declarations, and may be temporarily suspended over the next few years to maintain SoCalGas' authorized capital structure during the periods of high capital investments. We discuss the cost of capital proceeding in Note 14ERRA balances that exceed 5 percent of the ~~Notes~~prior year’s electric commodity revenues. To reduce the undercollected ERRA balance, SDG&E filed an ERRA Trigger application with the CPUC in May 2017 requesting recovery of $120 million to ~~Consolidated Financial Statements~~be amortized in rates over a 14-month

period beginning November 2017. In July 2017, the CPUC issued a proposed decision approving the request as filed. We expect the final decision in the ~~Annual Report.~~third quarter of 2017.

~~In connection with~~SoCalGas and SDG&E use the CFCA balancing account to record the difference between the authorized margin and other costs allocated to core customers. Because warm weather experienced in 2016 and 2017 resulted in lower natural gas consumption compared to authorized levels, SoCalGas’ CFCA balance was undercollected by $119 million at June 30, 2017 and $114 million at December 31, 2016. SDG&E’s CFCA balance was undercollected by $24 million at June 30, 2017 and $66 million at December 31, 2016.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

We provide information on the natural gas leak at the Aliso Canyon storage facility, as of July 28, 2016, 181 lawsuits have been filed against SoCalGas, some of which have also named Sempra Energy, and in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, against certain officers and directors of Sempra Energy and/or SoCalGas. All of these cases, other than the derivative and securities law claims, are coordinated before a single court in the Los Angeles County Superior Court for pretrial management. Pursuant to the parties' agreement, the court ordered that the individual and business entity plaintiffs would proceed by filing two consolidated master complaints, one for the individual tort cases, and a second for the class action cases. On July 25, 2016, the individuals and business entities asserting tort claims filed a Consolidated Case Complaint for Individual Actions through which their separate lawsuits will be managed for pretrial purposes. In addition, the Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the California Air Resources Board (CARB), joined that existing lawsuit. The complaint, as amended, includes allegations of violations of certain California Health and Safety Code and California Government Code sections. The South Coast Air Quality Management District (SCAQMD) also filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. On February 2, 2016, the Los Angeles District Attorney's Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. On February 16, 2016, SoCalGas pled not guilty to the complaint. No trial date has been set.

~~On July 25, 2016, the County of Los Angeles, on behalf of itself and the people of California, filed a complaint alleging that the four~~ natural gas storage ~~fields operated or formerly operated by SoCalGas~~facility further in ~~Los Angeles County require safety upgrades, including installation~~Note 11 of ~~sub-surface safety shut-off valves on every well~~the Notes to Condensed Consolidated Financial Statements herein and that SoCalGas failed to comply with the directive issued by the LA County Department of Public Health (DPH), discussed below. It seeks preliminary and permanent injunctive relief, civil penalties, and damages for the County's costs to respond to the leak,in “Factors Influencing Future Performance” below, as well as ~~punitive damages~~in Note 15 of the Notes to Consolidated Financial Statements and ~~attorneys' fees.~~

“Risk Factors” in the Annual Report. The costs of defending against ~~these~~the related civil and criminal lawsuits and cooperating with ~~these~~related investigations, and any damages, restitution, and civil, administrative and criminal fines, costs and other penalties, if awarded or imposed, as well as costs of mitigating the actual natural gas released, 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 receiving insurance recoveries, such costs could have a material adverse effect on ~~SoCalGas'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of operations. Also, higher operating costs and additional capital expenditures incurred by SoCalGas as a result of new laws, orders, rules and regulations arising out of this incident or our responses thereto could be significant and may not be recoverable in customer rates, which may have a material adverse effect on ~~SoCalGas'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of ~~operations, cash flows, and financial condition.~~

On May 13, 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 have participated in the relocation program, or who are located within a five mile radius of the Aliso Canyon natural gas storage facility and have experienced symptoms from the natural gas leak (the Directive). SoCalGas does not believe that the DPH has the authority to issue the Directive and has filed a petition for writ of mandate to set aside the Directive.operations.

The total costs incurred to remediate and stop the leak and to mitigate local community impacts 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'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of operations.

~~We discuss the Aliso Canyon facility further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein, and in "Factors Influencing Future Performance" below.~~

In May 2016, SDG&E declared common stock dividends of $175 million, which were paid on July 6, 2016. SDG&E declared and paid common stock dividends of $300 million in 2015 and $200 million in 2014. SDG&E expects to continue paying common dividends over the next five years, at or above the level paid in 2015. While it expects to maintain a large capital program (exceeding $1 billion per year), SDG&E expects that its cash flows will support these dividends to the parent.

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. In December 2015, the CPUC approved SDG&E's 2016 ERRA revenue requirement of $1.3 billion, an increase of $43 million from its 2015 revenue requirement. As the new revenue requirement was effective on January 1, 2016, management expects the ERRA balance to remain relatively stable through year-end 2016. SDG&E's ERRA balance was undercollected by $110 million at June 30, 2016 and overcollected by $25 million at December 31, 2015. During the first six months of 2016, the ERRA undercollected balance was caused by lower sales driven primarily by seasonality. We discuss the revenue requirement for ERRA further in Note 14 of the Notes to Consolidated Financial Statements and other 2015 impacts on ERRA balances in "Capital Resources and Liquidity – Overview – California Utilities" in "Management's Discussion and Analysis of Financial Condition and Results of Operations," both in the Annual Report.

SoCalGas and SDG&E use the Core Fixed Cost Account (CFCA) balancing account to record the difference between the authorized margin and other costs allocated to the core market, and the actual revenues billed to customers in rates for recovery of these costs. Because warmer weather experienced in 2014 and 2015 resulted in lower natural gas consumption compared to authorized levels, SoCalGas' CFCA balance was undercollected by $238 million at June 30, 2016 and $328 million at December 31, 2015. SDG&E's CFCA balance was undercollected by $71 million at June 30, 2016 and $105 million at December 31, 2015.

Under its current ratemaking treatment, SoCalGas and SDG&E have the authority through an Annual Regulatory Account Balance Update filing to recover undercollections accumulated in the prior year, consisting of actual recorded activity through August and an estimate for the remainder of the year. SoCalGas and SDG&E are currently amortizing $417 million and $99 million, respectively, of the December 31, 2015 CFCA balance in 2016 rates.

In July 2016, the CPUC issued a proposed decision addressing a number of outstanding requests and authorizing SoCalGas and SDG&E to recover, subject to refund, the revenue requirements associated with 50 percent of their incurred PSEP Phase 1 costs; file two reasonableness review applications for Phase 1 projects completed through 2017; file a Phase 2 revenue requirement forecast application for costs to be incurred in 2017 and 2018; and include in their 2019 GRC applications all other PSEP costs not the subject of prior applications. We expect the CPUC to issue a final decision in the proceeding in the third quarter of 2016.

Sempra South American Utilities

We expect ~~working capital and capital expenditure requirements, projects and loans~~ to ~~affiliates~~fund operations at Chilquinta Energía and Luz del Sur ~~to be funded by~~and dividends at Luz del Sur with available funds, including credit facilities, funds internally generated by those businesses, ~~issuance~~issuances of corporate bonds and other external borrowings. At June 30, 2016 and December 31, 2015, Sempra South American Utilities had outstanding loans of $79 million and $72 million, respectively, to an affiliate to finance development projects. We discuss these transactions in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Mexico

We expect ~~working capital and capital expenditure requirements, projects, joint venture investments~~to fund operations and dividends in Mexico ~~to be funded by~~with available funds, including credit facilities, and funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent or affiliates, and partnering in joint ventures.

In ~~2015 and 2014, Sempra Mexico~~the year ended December 31, 2016, IEnova paid dividends of ~~$32~~$26 million ~~and $31 million, respectively,~~ to its minority shareholders. No dividends were paid in the six months ended June 30, 2017. On July 25, 2017, IEnova declared $67 million in dividends to its minority shareholders, payable in August 2017.

~~We discuss IEnova's pending acquisition~~IMG is a joint venture between a subsidiary of ~~Petróleos Mexicanos' (or PEMEX,~~IEnova and a subsidiary of TransCanada. In April 2017, IEnova entered into a revolving credit facility agreement, expiring in March 2022, with IMG for up to $9.0 billion Mexican pesos or approximately $500 million U.S. dollar-equivalent, to provide financing to IMG for the ~~Mexican state-owned oil company) 50-percent interest in GdC and related expected financing~~construction of the ~~transaction in Note 3~~Sur de Texas - Tuxpan natural gas marine pipeline and for general corporate purposes, including repayment of ~~the Notes to Condensed Consolidated Financial Statements herein.~~

other outstanding debt. At June 30, ~~2016 and December 31, 2015, Sempra Mexico had~~2017, $3.2 billion Mexican pesos or approximately $177 million U.S. dollar-equivalent is outstanding ~~loans~~against the line of ~~$105~~credit. IEnova also has provided guarantees for certain obligations of IMG not to exceed $288 million, ~~and $111 million, respectively, to unconsolidated affiliates to fund development projects. We~~as we discuss ~~these transactions~~ in Note 54 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Mexico also expects to generate cash from the sale of its 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein, in February 2016, management approved a plan to market and sell the plant, which had a book value of $254 million at June 30, 2016.

~~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, including tax equity. The ~~Sempra Renewables projects have planned in-service dates through 2017.~~

varying costs and structure of these alternative financing sources impact the projects’ returns and their earnings profile.

Sempra ~~Natural Gas~~LNG & Midstream

We expect Sempra ~~Natural Gas~~LNG & Midstream 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, project financing and ~~project financing. In May 2016, Sempra Natural Gas received $443 million~~partnering in proceeds from the sale of its investment in Rockies Express. Sempra Natural Gas also expects to receive approximately $323 million, subject to adjustment at closing, from the pending sale of EnergySouth Inc., as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. In the short-term, we plan to use the sale proceeds from these transactions to pay down commercial paper at Sempra Energy, pending redeployment for other growth opportunities.joint ventures.

Sempra ~~Natural Gas,~~LNG & Midstream, through its interest in Cameron LNG JV, is developing a natural gas liquefaction export facility at the Cameron LNG JV terminal. The majority of the current three-train liquefaction project is project-financed, with most or all of the remainder of the capital requirements to be provided by the project partners, including Sempra Energy, through equity contributions under a joint venture agreement. 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. ~~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~~Cameron LNG JV’s obligations under the financing ~~agreements.~~agreements for a maximum amount of $3.9 billion. 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~~We anticipate that the guarantees ~~are anticipated to~~will be terminated ~~in the second half of 2019.~~approximately nine months after all three trains achieve commercial operation.

We discuss Cameron LNG JV and the joint venture financing further in Notes 3 and 4 of the Notes to Consolidated Financial Statements, in “Risk Factors,” and in “Factors Influencing Future Performance” in the Annual Report. We also discuss Cameron LNG JV in “Factors Influencing Future Performance” below.

CASH FLOWS FROM OPERATING ACTIVITIES

																	CASH PROVIDED BY OPERATING ACTIVITIES	(Dollars in millions)
	Six months ended June 30, 2016		2016 change				Six months ended June 30, 2015		Six months ended June 30, 2017		2017 change				Six months ended June 30, 2016(1)
Sempra Energy Consolidated	$	882	$	(337)	(28)	%	$	1,219	$	1,889	$	973	106	%	$	916
SDG&E		508		(42)	(8)			550	690		182		36		508
SoCalGas		262		(221)	(46)			483	855		593		226		262

(1) Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy ~~decreased~~increased in ~~2016~~2017 primarily due to:

§
▪	$~~354~~713 million ~~increase~~higher net income, adjusted for noncash items included in ~~receivable~~earnings, in 2017 compared to 2016, primarily due to improved results at ~~SoCalGas for expected insurance recovery of certain expenditures~~our operating segments; and


▪	$573 million net increase related to the natural gas leak at the Aliso Canyon natural gas storage facility, comprised of:


◦	$52 million net decrease in insurance receivable in 2017 compared to a $354 million net increase in 2016. The $52 million net decrease includes $104 million in insurance proceeds, offset primarily by $53 million of additional accruals, and


◦	$10 million net increase in reserve for accrued expenditures in 2017 compared to a $157 million net decrease in ~~reserve for accrued expenditures related to the leak.~~2016. The ~~$157~~$10 million net ~~decrease~~increase includes ~~$520~~$53 million of additional accruals, offset primarily by $49 million of cash ~~expenditures,~~ expenditures; offset by ~~$363 million of additional accruals;~~

$212 million lower net income at the California Utilities, adjusted for noncash items included in earnings, in 2016 compared to 2015, including charges for income tax benefits previously generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD, as we discuss in "Results of Operations" above; and

§	$14 million decrease in inventories in 2016 compared to a $124 million decrease in 2015, primarily due to lower gas inventory at SoCalGas as a result of the current moratorium on natural gas injections at its Aliso Canyon natural gas storage facility; ~~offset by~~

§
▪	$25110 million decrease in accounts payable in ~~2016~~2017 compared to a ~~$198~~$25 million decrease in ~~2015, primarily due~~2016;


▪	$63 million increase in income taxes receivable in 2017 compared to ~~the current moratorium on natural gas injections at the Aliso Canyon storage facility as well as lower average cost of natural gas purchased;~~a $7 million decrease in 2016;

§
▪	$~~145~~261 million ~~net~~decrease in accounts receivable in 2017 compared to a $328 million decrease in 2016; and

▪

$79 million increase in net overcollected regulatory balancing accounts at SoCalGas (including long-term amounts included in regulatory assets) in ~~2016 at the California Utilities~~2017 compared to a ~~$37~~$140 million ~~net~~ increase in undercollected regulatory balancing accounts in 2015. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time. See further discussion of changes in regulatory balances at both SDG&E and SoCalGas below; and

§	~~$328 million decrease in accounts receivable in 2016 compared to a $216 million decrease in 2015, primarily due to lower natural gas prices at SoCalGas~~ in 2016.

SDG&E

Cash provided by operating activities at SDG&E ~~decreased~~increased in ~~2016~~2017 primarily due to:

§
▪	$~~108~~178 million ~~lower~~higher net income, adjusted for noncash items included in earnings, in ~~2016~~2017 compared to ~~2015;~~2016; and

§
▪	$635 million decrease in net undercollected regulatory balancing accounts in 2016 compared to a $102 million decrease (including long-term amounts included in regulatory assets) in 2015, primarily due to changes in electric commodity accounts; ~~offset by~~

§	~~$19 million decrease in accounts receivable in 2016 compared to a $27 million increase in 2015;~~

§	~~$32 million increase in greenhouse gas allowances in 2016 compared to a $79 million increase in 2015;~~

§	~~$31 million increase~~ in income taxes receivable in ~~2016~~2017 compared to a ~~$60~~$31 million increase in ~~2015;~~2016; offset by

§
▪	$6321 million increase in accounts receivable in 2017 compared to a $19 million decrease in 2016; and


▪	$41 million increase in accounts payable in ~~2016~~2017 compared to a ~~$41~~$63 million increase in ~~2015; and~~2016.

§	$23 million reduction to the SONGS regulatory asset due to cash received for our portion of the Department of Energy settlement with Southern California Edison related to spent fuel storage, as we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

SoCalGas

Cash provided by operating activities at SoCalGas ~~decreased~~increased in ~~2016~~2017 primarily due to:

§
▪	$~~354~~573 million net increase ~~in receivable for expected insurance recovery of certain expenditures~~ related to the natural gas leak at the Aliso Canyon natural gas storage facility, comprised of:


◦	$52 million net decrease in insurance receivable in 2017 compared to a $354 million net increase in 2016. The $52 million net decrease includes $104 million in insurance proceeds, offset primarily by $53 million of additional accruals, and


◦	$10 million net increase in reserve for accrued expenditures in 2017 compared to a $157 million net decrease in ~~reserve for accrued expenditures related to the leak.~~2016. The ~~$157~~$10 million net ~~decrease~~increase includes ~~$520~~$53 million of additional accruals, offset primarily by $49 million of cash ~~expenditures, offset by $363~~expenditures; and


▪	$129 million ~~of additional accruals;~~

§	~~$104 million lower~~higher net income, adjusted for noncash items included in earnings, in ~~2016~~2017 compared to ~~2015; and~~2016; offset by

§
▪	$35234 million decrease in ~~inventories~~accounts receivable in ~~2016~~2017 compared to a ~~$124~~$308 million decrease in ~~2015, primarily due to lower gas inventory as a result of the current moratorium on natural gas injections at the Aliso Canyon storage facility;~~ ~~offset by~~2016; and

§
▪	$~~140~~79 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in ~~2016~~2017 compared to a ~~$139~~$140 million increase in ~~net undercollected balances in 2015, primarily due to changes in fixed-cost balancing accounts;~~

§	$108 million decrease in accounts payable in 2016 compared to a $224 million decrease in 2015, primarily due to the current moratorium on natural gas injections at the Aliso Canyon storage facility, as well as lower average cost of natural gas purchased; and

§	~~$308 million decrease in accounts receivable in 2016 compared to a $218 million decrease in 2015, primarily due to lower natural gas prices in~~ 2016.

~~The table below shows the contributions to pension and other postretirement benefit plans.~~

CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
Six months ended June 30, 2016
Other
Pension postretirement
benefits benefits
Sempra Energy Consolidated $ 23 $ 2
SDG&E 2 ―
SoCalGas ― 1

CASH FLOWS FROM INVESTING ACTIVITIES



CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	Six months ended June 30, 2017			2017 change					Six months ended June 30, 2016
Sempra Energy Consolidated	$	(2,067	)	$	474		30	%	$	(1,593	)
SDG&E	(734		)	(36		)	(5	)	(770		)
SoCalGas	(766		)	166			28		(600		)

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
Six months ended Six months ended
June 30, 2016 2016 change June 30, 2015
Sempra Energy Consolidated $ (1,593) $ 392 33 % $ (1,201)
SDG&E (770) 164 27 (606)
SoCalGas (600) (282) (32) (882)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy increased in ~~2016~~2017 primarily due to:

§	~~$540 million increase in capital expenditures;~~

§	~~in 2015, $347 million of net proceeds received from Sempra Natural Gas' sale of the remaining block of its Mesquite Power plant; and~~

§	~~$65 million lower repayments of advances to unconsolidated affiliates;~~ ~~offset by~~

§▪	$443 million of net proceeds received from Sempra ~~Natural Gas'~~LNG & Midstream’s sale of its investment in Rockies Express in ~~May~~ 2016;


▪	$174 million higher advances to unconsolidated affiliates; and

§
▪	$51 million increase in ~~2015, $113 million investment in Rockies Express to repay project debt.~~expenditures for investments; offset by


▪	$204 million decrease in capital expenditures.

SDG&E

Cash used in investing activities at SDG&E ~~increased~~decreased in ~~2016~~2017 primarily due ~~to a $172 million advance to Sempra Energy.~~to:


▪	$31 million decrease in advances to Sempra Energy in 2017 compared to a $172 million net increase in 2016; offset by


▪	$161 million increase in capital expenditures.

SoCalGas

Cash used in investing activities at SoCalGas ~~decreased~~increased in ~~2016~~2017 due to:

§
▪	$5084 million ~~decrease~~increase in net advances to Sempra Energy in ~~2016~~2017 compared to a ~~$279~~$50 million ~~increase~~decrease in ~~2015;~~ ~~offset by~~2016; and

§
▪	$4732 million increase in capital ~~expenditures in 2016.~~expenditures.

~~ANNUAL CONSTRUCTION EXPENDITURES AND INVESTMENTS~~

Capital Expenditures

Sempra Energy Consolidated Expenditures for Property, Plant and Equipment

The following table summarizes capital expenditures in 2017 compared to 2016.



EXPENDITURES FOR PP&E
(Dollars in millions)
	Six months ended June 30,
	2017		2016
SDG&E:
Improvements to natural gas, including certain pipeline safety, and electric and generation
distribution systems	$	503	$	360
PSEP	21		65
Improvements to electric transmission systems	229		168
Electric generation plants and equipment	10		9
SoCalGas:
Improvements to natural gas distribution, transmission and storage systems, and for certain pipeline safety	572		444
PSEP	86		150
Advanced metering infrastructure	24		56
Sempra South American Utilities:
Improvements to electric transmission and distribution systems and generation projects in Peru	49		57
Improvements to electric transmission and distribution infrastructure in Chile	28		25
Sempra Mexico:
Construction of the Sonora, Ojinaga and San Isidro pipeline projects	124		128
Construction of other natural gas pipeline and wind projects, and capital expenditures at Ecogas	31		12
Sempra Renewables:
Construction costs for wind projects	58		27
Construction costs for solar projects/facilities	42		430
Sempra LNG & Midstream:
Cameron Interstate Pipeline expansion and other LNG liquefaction development costs	10		55
Other	2		13
Parent and other	13		7
Total	$	1,802	$	2,006

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 ~~Federal Energy Regulatory Commission (FERC). However, in 2016,~~FERC. In 2017, we expect to make capital expenditures and investments of approximately ~~$5.6 billion. These expenditures include~~

$2.7 billion at the California Utilities for capital projects and plant improvements ($1.3 billion at SDG&E and $1.4 billion at SoCalGas), excluding incremental amounts that may result from the natural gas leak at the Aliso Canyon facility or related increased requirements for all natural gas storage facilities

§	$2.9 billion at our other subsidiaries for acquisition of our joint venture partner's 50-percent interest in GdC, capital projects in Mexico and South America, and development of LNG, natural gas and renewable generation projects

T~~he California Utilities' 2016 planned capital expenditures~~$4 billion, an increase from the $3.4 billion summarized in “Capital Resources and ~~investments include~~

~~SDG&E~~

§	~~$800 million for improvements to natural gas, including pipeline safety, and electric generation and distribution systems~~

§	~~$500 million for improvements to electric transmission systems~~

~~SoCalGas~~

§	~~$1.2 billion for improvements to distribution, transmission and storage systems, and for pipeline safety, including $360 million for the PSEP~~

§	~~$100 million for advanced metering infrastructure~~

§	~~$100 million for other natural gas projects~~

~~The California Utilities expect to finance these expenditures and investments with cash flows from operations and debt issuances.~~

~~In 2016, the expected capital expenditures and investments of approximately $2.9 billion at our other subsidiaries include~~

~~Sempra South American Utilities~~

§	approximately $210 million for capital projects in South America (approximately $160 million and $50 million in Peru and Chile, respectively), primarily related to improvements to electric transmission and distribution systems

~~Sempra Mexico~~

approximately $475 million to $525 million for capital projects, including approximately $400 million for the development of the Sonora, Ojinaga and San Isidro – Samalayuca pipeline projects, all developed solely by Sempra Mexico, and approximately $80 million current year equity investment in the Infraestructura Marina del Golfo (IMG) joint venture for the development of the South Texas – Tuxpan pipeline

§	approximately $1.1 billion for the pending acquisition of our joint venture partner's 50-percent interest in GdC, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein

~~Sempra Renewables~~

§	~~approximately $950 million for the development of wind and solar renewable projects, including Black Oak Getty Wind, Mesquite Solar 2, Mesquite Solar 3, Copper Mountain Solar 4 and Apple Blossom Wind~~

~~Sempra Natural Gas~~

§	approximately $160 million for development of LNG and natural gas transportation projects, including approximately $50 million capitalized interest on our investment in the Cameron LNG JV, and $70 million for development of the Cameron Interstate Pipeline

Capital expenditure amounts include capitalized interest. At the California Utilities, the amounts also include the portion of allowance for funds used during construction (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 StatementsLiquidity” in the Annual Report. The increase is primarily attributable to an additional solar project at Sempra Renewables and additional capital expenditures at SDG&E.

CASH FLOWS FROM FINANCING ACTIVITIES



CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	Six months ended June 30, 2017			2017 change			Six months ended June 30, 2016(1)
Sempra Energy Consolidated	$	44		$	(838	)	$	882
SDG&E	48			(202		)	250
SoCalGas	(63		)	(554		)	491

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
Six months ended Six months ended
June 30, 2016 2016 Change June 30, 2015
Sempra Energy Consolidated $ 916 $ 866 $ 50
SDG&E 250 179 71
SoCalGas 491 (54) 545

(1) Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Energy Consolidated

At Sempra Energy, cash provided by financing activities ~~increased~~decreased in ~~2016,~~2017, primarily due to:

§
▪	$~~865~~493 million ~~increase~~decrease in short-term debt in ~~2016~~2017 compared to ~~a $339 million decrease in 2015;~~ ~~offset by~~

~~$163 million lower issuances of debt, including a decrease in issuances of long-term debt of $530 million ($1 billion in 2016 compared to $1.5 billion in 2015, partially offset by~~ an ~~increase in commercial paper and other short-term debt borrowings with maturities greater than 90 days of $367 million ($386~~$865 million increase in ~~2016 compared to $19 million in 2015);~~2016; offset by

§
▪	$~~140~~548 million higher ~~payments on debt, including higher payments~~issuances of ~~long-term debt of $716 million ($888 million in 2016 compared to $172 million in 2015), partially offset by lower payments of commercial paper and other short-term~~ debt with maturities greater than 90 days, ~~of $576~~including:


◦	$350 million for commercial paper and other short-term debt ($98736 million in ~~2016~~2017 compared to ~~$674~~$386 million in ~~2015);~~2016), and

§
◦	$27198 million ~~higher~~for long-term debt ($1.2 billion in 2017 compared to $1 billion in 2016).

SDG&E

At SDG&E, cash provided by financing activities decreased in 2017, primarily due to:


▪	$175 million common dividends paid in 2017;


▪	$100 million lower issuances of long-term debt; and


▪	$35 million higher payments of long-term debt; offset by


▪	$5 million increase in short-term debt in 2017 compared to a $114 million decrease in 2016.

SoCalGas

~~SDG&E~~

~~Cash provided by~~At SoCalGas, financing activities ~~at SDG&E increased~~were a use of cash in 2017 compared to a source of cash in 2016, primarily due to:

§
▪	$~~110~~499 million ~~higher~~ issuances of long-term debt in 2016; and

§
▪	$~~114~~62 million decrease in short-term debt in ~~2016 compared to a $206 million decrease in 2015;~~ ~~offset by~~2017.

§	~~$23 million higher payments on long-term debt.~~

~~SoCalGas~~

Cash provided by financing activities at SoCalGas decreased in 2016 primarily due to $100 million lower issuances of long-term debt in 2016, partially offset by a $50 million decrease in short-term debt in 2015.

COMMITMENTS

We discuss significant changes to contractual commitments since December 31, ~~2015~~2016 at Sempra Energy, SDG&E and SoCalGas in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

CREDIT RATINGS

The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels during the first six months of ~~2016.~~2017. Our credit ratings may affect the rates at which borrowings bear interest and ofthe commitment fees on available unused credit. We provide additional information about our credit ratings at Sempra Energy, SDG&E and SoCalGas in ~~"Management's~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Credit ~~Ratings"~~Ratings” in the Annual Report.

FACTORS INFLUENCING FUTURE PERFORMANCE

~~CALIFORNIA UTILITIES~~

~~Overview~~

~~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 projectsWe discuss various factors that we ~~discuss below and~~have identified that could influence our future performance in ~~various sections of this report and~~“Factors Influencing Future Performance” in the Annual Report. We discuss below significant, new developments to those factors that have occurred in 2017, as well as any new factors that we have identified in 2017. You should read the information below together with “Factors Influencing Future Performance” and “Risk Factors” contained in the Annual Report.

SDG&E

Capital Project Updates

We summarize below updates regarding certain major capital projects at SDG&E.



CAPITAL PROJECTS – SDG&E

Project description		Estimated capital cost (in millions)				Status
South Orange County Reliability Enhancement
§	December 2016 CPUC final decision granted a Certificate of Public Convenience and Necessity to replace/upgrade existing electric transmission lines and substation infrastructure to enhance the capacity and reliability of electric service to the south Orange County area.		$	381	§	Construction expected to start in the second half of 2017.
					§	Rehearing requests filed by the City of San Juan Capistrano and local opposition group pending with CPUC.
Electric Vehicle Charging
§	January 2017 application, pursuant to SB 350, to perform various activities and make investments in support of electric vehicle charging.		$	298	§	Application pending
§	Estimated implementation cost of $51 million of O&M.
Energy Storage
§	August 2016 CPUC approval to own and operate two energy storage projects totaling 37.5 MW to enhance electric reliability in the San Diego service territory.	Not disclosed			§	Completed in first quarter of 2017.
§	April 2017 application to procure up to 70 MW of utility-owned energy storage to provide local capacity.	Not disclosed			§	Application pending
Utility Billing and Customer Information Systems Software
§	April 2017 application to replace the software.		$	220	§	Application pending
§	Estimated implementation cost of $67 million of O&M.				§	May 2017 ruling authorizes SDG&E to establish a memorandum account to record related costs prior to receiving a final decision on the application.

Sunrise Powerlink Project Cost Cap

In ~~addition, SoCalGas' performance will depend on~~August 2015, SDG&E filed a petition with the ~~resolution~~CPUC requesting that it revise and confirm the project cost cap for 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. While post-energization construction activities for the project were completed in 2013, certain matters relating to outstanding claims were not resolved until the first quarter of 2015. The filing requested CPUC approval of the final expenditure report for the project and the proposed revisions to the total project cost cap. As evidenced in the final report, actual expenditures for the project totaled $1.9 billion (in 2012 dollars, on a net present value basis), which exceeds the total project cost cap approved by the CPUC in 2008 by $4.4 million.

In June 2017, the CPUC dismissed SDG&E’s petition as moot since the Sunrise Powerlink transmission project has been fully constructed and found that, although the CPUC may establish a cost cap for electric transmission projects, the recovery of the associated costs is under FERC jurisdiction. The decision also finds that SDG&E complied with the CPUC’s quarterly reporting requirements, resolving the issue of whether the adequacy of such reporting should be further investigated.

Potential Impacts of Community Choice Aggregation and Direct Access

SDG&E provides electric services, including the commodity of electricity, to the majority of its customers (“bundled customers”). SDG&E procures electricity, typically on a long-term basis, on behalf of these bundled customers. However, SDG&E’s earnings are “decoupled” from electric sales volumes, one aspect of which is that commodity costs for electricity are directly passed through to bundled customers (see discussion in “Revenues – California Utilities” in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report). SDG&E’s bundled customers have the option to purchase the commodity of electricity from alternate suppliers under defined programs, including CCA and DA. In such cases, California law (SB 350) prohibits remaining bundled customers from experiencing any cost increase as a result of electric commodity no longer being consumed by the departing customers. Existing rate mechanisms may not be sufficient to ensure that remaining bundled customers do not experience any cost increase as a result of departing customers. SDG&E, PG&E and Edison filed a joint application with the CPUC in April 2017 to replace these existing mechanisms and ensure compliance with state law. In June 2017, the CPUC initiated a rulemaking proceeding to address this matter and dismissed the joint application without prejudice, since the issues it raised will be addressed in the rulemaking.

Currently, DA in SDG&E’s service area is limited by state law and is approximately 17 percent of SDG&E’s annual demand, and there are no CCA providers in SDG&E’s service area. However, several local political jurisdictions, including the City of San Diego and a few other, smaller municipalities, are considering the formation of a CCA which, if implemented, could result in the departure of more than half of SDG&E’s bundled load. State law requires that customers opting to have a CCA procure their energy must also absorb the cost of energy procurement commitments already made by SDG&E on their behalf. If mechanisms to ensure compliance with state law were not in place at the time of these potentially significant reductions in SDG&E’s served load, remaining bundled customers of SDG&E could potentially experience large increases in rates for commodity costs under commitments made on behalf of the CCA customers. If legislative, regulatory or legal ~~regulatory~~action were taken to prevent the timely recovery of these procurement costs, the unrecovered costs could have a material adverse effect on SDG&E’s and ~~other matters concerning~~Sempra Energy’s cash flows, financial condition and results of operations.

SONGS

SDG&E has a 20-percent ownership interest in SONGS, formerly a 2,150-MW nuclear generating facility near San Clemente, California, that is in the ~~natural gas leak at Aliso Canyon. We discuss certain regulatory matters below and in~~process of being decommissioned by Edison, the majority owner of SONGS. In Notes 9 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein, and in Notes 13 14 and 15 of the Notes to Consolidated Financial Statements ~~in the Annual Report.~~

~~Joint Matters~~

~~CPUC General Rate Case (GRC)~~

In November 2014, the California Utilities filed their 2016 General Rate Case (2016 GRC) applications to establish their authorized 2016 revenue requirements and the ratemaking mechanisms by which those requirements would change on an annual basis over the subsequent three-year (2016-2018) period. In June 2016, the CPUC approved a final decision (2016 GRC FD) in the California Utilities' 2016 GRC, effective retroactive to January 1, 2016. The adopted revenue requirements associated with the seven-month period through July 2016 will be recovered in rates over a 17-month period, beginning August 2016, in order to minimize the impact on ratepayers, thus adversely impacting the California Utilities' cash flows. We discuss the 2016 GRC and the 2016 GRC FD in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in ~~Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.~~

~~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 their natural gas pipeline operations and investments. In August 2011, the California Utilities filed implementation plans with the CPUC to test or replace natural gas transmission pipelines located in populated areas that have not been pressure tested, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. The California Utilities' total estimated cost for Phase 1 (the 10-year period of 2012 to 2022) of a two-phase plan was $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). We anticipate that these cost estimates may be updated to reflect the development of more detailed estimates, actual cost experience as portions of the work are completed and changes in scope. 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 GRC proceedings concluded in 2013. Similarly, these costs are not included in the 2016 GRC approved revenue requirements.

In June 2014, the CPUC issued a final decision 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 that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of June 30, 2016, SDG&E and SoCalGas have recorded PSEP costs of $15 million and $195 million, respectively, in the CPUC-authorized regulatory account.

SDG&E and SoCalGas have filed with the CPUC for recovery of certain PSEP costs incurred through June 11, 2014 of $0.1 million and $26.8 million, respectively. The CPUC Office of Ratepayer Advocates (ORA), The Utility Reform Network (TURN), and the Southern California Generation Coalition (SCGC) have recommended disallowances of certain of these costs. We expect a decision on this application in the second half of 2016.

In October 2014, SDG&E and SoCalGas filed a petition for modification with the CPUC requesting authority to recover PSEP costs from customers as incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of recovery of such costs in the subsequent year. In July 2016, the CPUC issued a proposed decision addressing a number of outstanding requests and authorizing SoCalGas and SDG&E to recover, subject to refund pending reasonableness reviews, the revenue requirements associated with 50 percent of their incurred PSEP Phase 1 costs recorded to regulatory accounts; file two reasonableness review applications for Phase 1 projects completed through 2017; file a Phase 2 revenue requirement forecast application for costs to be incurred in 2017 and 2018; and include in their 2019 GRC applications, and any future GRCs, all other PSEP costs not the subject of prior applications. We expect the CPUC to issue a final decision in the proceeding in the third quarter of 2016.

In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC's June 2014 final decision. In March 2015, the CPUC issued a decision denying the ORA's and TURN's second request for rehearing, but keeping the record open to admit additional evidence on the limited issue of pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961. The ORA and TURN allege 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 December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipelines. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. In May 2016, the CPUC issued a decision denying the request for rehearing. Through June 30, 2016, the after-tax disallowed costs for SoCalGas and SDG&E are $3.6 million and $0.5 million, respectively.

~~We provide additional information regarding these rulemaking proceedings and the California Utilities' PSEP in Note 14 of the Notes to Consolidated Financial Statements~~“Risk Factors” in the Annual Report, we discuss regulatory and ~~in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.~~

~~Safety Enforcement~~

California Senate Bill (SB) 291 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. In exercising the citation authority, the CPUC staff will take into account voluntary reporting of potential violations, voluntary resolution efforts undertaken, prior history of violations, the gravity of the violation and the degree of culpability. The CPUC also has implemented both electric and gas safety enforcement programs whereby electric and gas utilities may be cited by CPUC staff for violations of the CPUC's safety requirements or federal standards.

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 May 2016, the CPUC's Safety and Enforcement Division issued a citation to SoCalGas for violation of General Order 112, resulting in a $2.25 million penalty that was subsequently paid. The citation is associated with findings from two 2015 audits of SoCalGas' Southeast Region for failure to promptly remediate corrosion issues in accordance with Federal regulations.

~~SDG&E Matters~~

~~2007 Wildfire Litigation~~

In regard to the 2007 wildfire litigation, SDG&E's payments for claims settlements plus funds estimated to be required for settlement of outstanding claims and legal fees 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 June 30, 2016, Sempra Energy's and SDG&E's Condensed Consolidated Balance Sheets include assets of $355 million in Other Regulatory Assets (long-term), of which $353 million isother matters related to ~~CPUC-regulated operations and $2 million is related to FERC-regulated operations, for costs incurred and the estimated resolution of pending claims.~~ SONGS, including:


▪	a reopened CPUC proceeding that is considering whether a SONGS-related amended settlement agreement approved in 2014 is reasonable and in the public interest;


▪	matters concerning the ability to timely withdraw funds from trust accounts for the payment of decommissioning costs; and


▪	the arbitration decision finding MHI liable for breach of contract in connection with the replacement steam generators at the SONGS nuclear power plant, subject to a contractual limitation of liability, and awarding MHI 95 percent of its arbitration costs as MHI was found to be the prevailing party.

Wildfire Claims Cost Recovery

In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of ~~these~~an estimated $379 million in costs related to the October 2007 wildfires that have been recorded to the Wildfire Expense Memorandum Account, as we discuss in Note 1011 of the Notes to Condensed Consolidated Financial Statements ~~herein. SDG&E requested a CPUC decision by~~herein and Note 15 of the ~~end of 2016 and is proposing~~Notes to ~~recover~~Consolidated Financial Statements in the ~~costs in rates over a six- to ten-year period.~~ Annual Report.

In April 2016, the CPUC issued a ruling ~~was issued~~ establishing the scope and schedule for the proceeding, which will be managed in two phases. Phase 1 ~~will address~~addresses SDG~~&E's~~&E’s operational and management prudence surrounding the 2007 wildfires. We expect a Phase 1 draft decision from the CPUC in the second half of 2017. Phase 2 will address whether SDG~~&E's~~&E’s actions and decision-making in connection with settling legal claims in relation to the wildfires were ~~reasonable. Evidentiary hearings in Phase 1 are scheduled to be held in January 2017,~~reasonable, with a final CPUC decision ~~scheduled to be issued in the second half of 2017. The procedural schedule for Phase 2 will be determined after~~expected by early 2019. In October 2016, intervening parties submitted Phase 1 ~~is concluded.~~testimony raising various concerns with SDG&E’s operations and management prior to and during the 2007 wildfires, and SDG&E responded to that testimony in December 2016. Participating parties asked that the CPUC reject SDG&E’s request for cost recovery.

Recovery of these costs in rates will require future regulatory 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 June 30, ~~2016,~~2017, the resulting after-tax charge against earnings would have been up to approximately ~~$210~~$207 million. A failure to obtain substantial or full recovery of the requested amount of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on SDG&E’s and Sempra ~~Energy's and SDG&E's~~Energy’s financial condition, cash flows and results of operations. We discuss the October 2007 wildfires and how we assess the probability of recovery of our regulatory assets in ~~Note~~Notes 15 and 1, respectively, of the Notes to Consolidated Financial Statements in the Annual Report.

We provide additional information concerning these matters in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.Other SDG&E Matters

~~SONGS~~

We discuss regulatory and other matters related to SONGS in Notes 9 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 13 and 15 of the Notes to Consolidated Financial StatementsSee “Factors Influencing Future Performance” in the Annual Report ~~and in "Risk Factors" in the Annual Report.~~for a discussion about:


▪	Electric Rate Reform – California Assembly Bill 327


▪	Distributed Energy Storage – California Assembly Bill 2868


▪	Renewable Energy Procurement


▪	Clean Energy and Pollution Reduction Act – California SB 350

~~Rim Rock 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 were in dispute regarding whether all conditions precedent in the contribution agreement had been achieved by the developer of the project. As a result, SDG&E had not made the investment. On February 11, 2016, SDG&E, the project developer and several of the project developer's parent and affiliated entities entered into a conditional settlement agreement, which was approved by the CPUC in July 2016 and will become final and non-appealable 30 days after the CPUC approval, provided that no party requests rehearing. Under the settlement agreement, among other things, the parties agreed to terminate the tax equity investment arrangement, continue the power purchase agreement for the wind farm generation and release all claims against each other. The settlement agreement will not result in rate increases to SDG&E customers or a material impact on Sempra Energy's or SDG&E's financial condition, results of operations or cash flows. We discuss this matter further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

~~Electric Rate Reform – State of California Assembly Bill 327~~

In October 2013, the Governor of California signed Assembly Bill (AB) 327. This bill became law on January 1, 2014. This 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 July 2015, the CPUC adopted a decision that establishes comprehensive reform and a framework for rates that are more transparent, fair and sustainable. The decision directs changes beginning in summer 2015 and provides a path for continued reforms through 2020, including a minimum monthly bill of $10.00 ($5.00 for CARE customers). The changes also include fewer rate tiers and a gradual reduction in the difference between the tiered rates, similar to the tier differential that existed prior to the 2000-2001 Energy Crisis. The number of tiers was reduced from four to three in 2015 and was reduced to two on July 1, 2016. The rate differential between the highest and lowest tiers was reduced from approximately 2.4 times to 2.18 times in 2015, and will reduce to 1.25 times by as early as 2019. The decision also directs the utilities to pursue expanded time of use rates and implements a super user electric (SUE) surcharge in 2017 for usage that exceeds average customer usage by approximately 400 percent. The decision still allows the utilities to seek a fixed charge, but sets certain conditions for its implementation, which would be no sooner than 2020. The changes implemented should result in significant rate relief for higher-use SDG&E customers who do not exceed the SUE threshold and will result in a rate structure that better aligns rates with the actual cost to serve customers.

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, which required 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 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 their annual consumption, they receive compensation at a rate equal to a wholesale energy price.

In August 2015, SDG&E proposed a successor NEM tariff that is intended to ensure that all NEM customers pay for the grid and other services they receive, supports the continued growth and adoption of distributed energy resources and helps California meet its energy policy goals. In January 2016, SDG&E, Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison) filed a joint recommendation to continue the pursuit of a fair and equitable rate structure for all customers. Subsequently in January 2016, the CPUC adopted a final decision in the case that makes modest changes now to require NEM customers to pay some costs that would otherwise be borne by non-NEM customers and moves new NEM customers to time-of-use rates. Together with a reduction in tiered rate differentials and the potential implementation of a fixed charge discussed under electric rate reform, the NEM successor tariff begins a process of reducing the cost burden on non-NEM customers. In March 2016, SDG&E, Edison, PG&E, TURN and the California Coalition of Utility Employees filed applications with the CPUC requesting rehearing of its January 2016 decision. A CPUC decision on the rehearing requests is expected in 2016. SDG&E implemented the adopted successor NEM tariff in July 2016, after reaching the 617-MW cap established for the prior NEM program.

Appropriate NEM reform is necessary to ensure that SDG&E is authorized to recover, from NEM customers, the costs incurred in providing grid and energy services, as well as mandated legislative and regulatory public policy programs. SDG&E believes this design would be preferable to recovering these costs from customers not participating 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 CPUC could have a material adverse effect on SDG&E's business, cash flows, financial condition, results of operations and/or prospects. For additional discussion, see "Risk Factors" in the Annual Report.

~~California Senate Bill 350~~

SB 350, signed into law in October 2015, creates new requirements for the utilities in the areas of renewable procurements, energy efficiency, resource planning, and electric vehicle (EV) infrastructure. Specifically, the state mandated renewable portfolio standard will be raised to 50 percent by 2030 and requires all load serving entities, including SDG&E, to file integrated resource plans that will ultimately enable the electric sector to achieve reductions in greenhouse gas emissions of 40 percent compared to 1990 levels by 2030. SB 350 also clearly specifies that the utilities will be asked to file applications with the CPUC that highlight how they can help with the development and expansion of the electric charging infrastructure necessary to support the growth of the EV market expected due to the state's alternative fuel vehicle policy initiative. SB 350 also enhances focus on improving efficiency in older buildings. We expect to meet the higher renewable portfolio standard and greenhouse gas emissions reductions requirement and are supportive of greater infrastructure development to support electric vehicle charging. Our Electric Vehicle Charging Program, which we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, does not include potential additional opportunities associated with SB 350.

~~SoCalGas Matters~~SOCALGAS

Aliso Canyon Natural Gas Storage Facility Gas Leak

In October 2015, SoCalGas discovered a leak at one of its ~~injection and withdrawal~~injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility located in Los Angeles County, which SoCalGas has ~~been~~ operated ~~by SoCalGas~~as a gas storage facility since 1972. SoCalGas worked closely with several of the ~~world's~~world’s leading experts to stop the ~~leak, including planning and obtaining all necessary approvals for drilling relief wells.~~leak. On February 18, 2016, ~~the California Department of Conservation's Division of Oil, Gas, and Geothermal Resources (DOGGR)~~DOGGR confirmed that the well was permanently sealed.

Local Community Mitigation Efforts

Pursuant to a stipulation and ~~court~~ order ~~and in response to claims made pursuant to lawsuits described below,~~by the Los Angeles County Superior Court, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. ~~In connection with~~Following the ~~temporary relocation support, on April 27, 2016, the California Superior Court (Superior Court) ordered an extension~~permanent sealing of the ~~relocation support term pending~~well, the ~~completion of the DPH's indoor testing. Following the release of the results of the DPH's~~DPH conducted indoor testing of certain homes in the Porter Ranch community, ~~which~~and concluded that indoor conditions did not present a long-term health risk and that it was safe for residents to return ~~home,~~home. In May 2016, the Los Angeles County Superior Court ~~issued an order on May 20, 2016,~~ordered SoCalGas to offer to clean residents’ homes at SoCalGas’ expense as ~~supplemented by~~a condition to ending the ~~Superior Court on May 25, 2016, ruling that: (1) currently relocated residents be given~~relocation program. SoCalGas completed the ~~choice to request residence~~residential cleaning ~~to be performed according to the DPH's proposed protocol~~program and ~~at SoCalGas' expense, and (2)~~ the relocation program ~~for currently relocated residents would terminate. As of~~ended in July ~~24, 2016, the relocation program has ended.~~2016.

Apart from the Los Angeles County Superior Court order, onin May ~~13,~~ 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 ~~have~~ participated in the relocation program, or who are located within a five mile radius of the Aliso Canyon natural gas storage facility and have experienced symptoms from the natural gas leak (the Directive). SoCalGas ~~does not believe~~disputes the Directive, contending that ~~the DPH has the authority to issue the Directive~~it is invalid and unenforceable, and has filed a petition for writ of mandate to set aside the Directive.

The total costs incurred to remediate and stop the leak and to mitigate local community impacts are significant and may increase, and we may be subject to potentially significant damages, restitution, and civil, administrative and criminal fines, costs and other penalties. To the extent any of these costs are 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.

Litigation

In connection with the natural gas leak at the Aliso Canyon natural gas storage facility, as of August 3, 2017, 281 lawsuits, including over 25,500 plaintiffs, are pending against SoCalGas, some of which have also named Sempra Energy. Derivative and securities claims have also been filed on behalf of Sempra Energy and/or SoCalGas or their shareholders against certain officers and directors of Sempra Energy and/or SoCalGas. We provide further detail on these cases, as well as on complaints filed by the California Attorney General, acting in an independent capacity and on behalf of the people of the State of California and the CARB, together with the Los Angeles City Attorney; the SCAQMD; and the County of Los Angeles, on behalf of itself and the people of the State of California; and on a misdemeanor criminal complaint filed by the Los Angeles County District Attorney’s Office; in Note 11 of the Notes to Condensed Consolidated Financial Statements herein. Additional litigation may be filed against us in the future related to the Aliso Canyon natural gas storage facility incident or our responses thereto.

The costs of defending against these civil and criminal lawsuits, cooperating with these investigations, and any damages, restitution, and civil, administrative and criminal fines, costs and other penalties, if awarded or imposed, as well as costs of mitigating the actual natural gas released, 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 receiving insurance recoveries, such costs could have a material adverse effect on ~~SoCalGas'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of operations.

Governmental Investigations

Various governmental agencies including the DOGGR, DPH, SCAQMD, CARB, California Division of Occupational Safety and Health (DOSH), CPUC, the Los Angeles Regional Water Quality Control Board, Pipeline and Hazardous Materials Safety Administration (PHMSA), U.S. Environmental Protection Agency (EPA), Los Angeles District Attorney's Office, and California Attorney General's Office,have investigated or are investigating this incident.

▪

In January 2016, the Governor of the State of California issued an Order (the Governor’s Order) proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon natural gas storage facility. The Governor’s Order imposes various orders with respect to: stopping the leak; protecting public health and safety; ensuring accountability; and strengthening oversight. We provide further detail regarding the Governor’s Order and the CARB’s Aliso Canyon Methane Leak Climate Impacts Mitigation Program, issued pursuant to the Governor’s Order, in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

▪

In January 2016, SoCalGas entered into a Stipulated Order for Abatement with the SCAQMD and agreed to take various actions in connection with injecting and withdrawing natural gas at the Aliso Canyon natural gas storage facility, sealing the well, monitoring, reporting, safety and funding a health impact study, among other things. In February 2017, SoCalGas entered into a settlement agreement with the SCAQMD, and in March 2017, the Hearing Board terminated the Abatement Order. We provide further detail regarding the SCAQMD stipulated Abatement Order in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.


▪	In January 2016, DOGGR and the CPUC selected Blade to conduct an independent analysis under the direction and supervision of DOGGR and the CPUC to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon natural gas storage facility gas leak. The timing of the root cause analysis is under the control of Blade, DOGGR and the CPUC.


▪	In February 2017, the CPUC opened a proceeding to determine the feasibility of minimizing or eliminating use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region, as we discuss below in “Regulatory Proceedings” and “SB 380.”

Natural Gas Storage Operations and Reliability

Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, with a storage capacity of ~~July 28, 2016, 181 lawsuits~~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. SoCalGas did not inject natural gas into the Aliso Canyon natural gas storage facility after October 25, 2015, pursuant to orders by DOGGR and the Governor, and in accordance with SB 380. Limited withdrawals of natural gas from the Aliso Canyon natural gas storage facility have been ~~filed (177~~made in ~~Los Angeles County Superior Court, 2 in San Diego County Superior Court,~~2017 to augment natural gas supplies during critical demand periods. In April and ~~2 in~~June of 2017, SoCalGas advised the ~~United States District Court for the Southern District~~CAISO, CEC, CPUC and PHMSA of California) against SoCalGas, some of which have also named Sempra Energy, and, in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, against certain officers and directors of Sempra Energy and/or SoCalGas. These various lawsuits assert causes of action for negligence, negligence per se, strict liability, property damage, fraud, public and private nuisance (continuing and permanent), trespass, breach of fiduciary duties, inverse condemnation, fraudulent concealment, loss of consortium and violation of federal securities laws, among other things, and additional litigation may be filed against us in the future related to this incident. Many of these complaints seek class action status, compensatory and punitive damages, injunctive relief, costs of future medical monitoring and attorneys' fees. Pursuant to the parties' agreement, the court orderedits concerns that the ~~individual~~inability to inject natural gas into the Aliso Canyon natural gas storage facility poses a risk to energy reliability in Southern California.

On July 19, 2017, DOGGR issued its Order to: Test and ~~business entity plaintiffs would proceed by filing two consolidated master complaints, one for~~Take Temporary Actions Upon Resuming Injection: Aliso Canyon Gas Storage Facility, lifting the ~~individual tort cases,~~prohibition on injection at the Aliso Canyon natural gas storage facility, subject to its requirements that SoCalGas conduct and report results of a ~~second for the class action cases. The Los Angeles City Attorney~~leak survey and ~~Los Angeles County Counsel have also filed a complaint on behalf~~measurement of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the CARB, joined this lawsuit. The complaint, as amended, includes allegations of violations of California Health and Safety Code sections 41700, prohibiting discharge of air contaminants that cause annoyance to the public, and 25510, requiring reporting of the release of hazardous material,total site methane emissions before resuming injection operations, as well as ~~California Government Code section 12607 for equitable relief for~~other requirements after injection resumes. The CPUC additionally issued a directive to SoCalGas to maintain a range of working gas in the ~~protection~~Aliso Canyon natural gas storage facility at a target of ~~natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance,~~23.6 Bcf (approximately 28 percent of its maximum capacity), and to impose civil penalties. The SCAQMD also filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. That suit seeks up to $250,000 in civil penalties for each day the violations occurred.at all times above 14.8 Bcf. On July ~~13, 2016, the SCAQMD amended its complaint to seek a declaration that SoCalGas is required to pay the costs of a longitudinal study of the health of persons exposed to the gas leak.~~

All of these cases, other than the derivative and securities law claims, are coordinated before a single court in the Los Angeles County Superior Court for pretrial management. As ordered by the court in the coordination proceeding, on July 25, 2016, the individuals and business entities asserting tort claims filed a Consolidated Case Complaint for Individual Actions through which their separate lawsuits will be managed for pretrial purposes, asserting causes of action for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment and loss of consortium against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, property damage and diminution in property value, a temporary injunction, costs of future medical monitoring, and attorneys' fees.

On February 2, 2016, the Los Angeles District Attorney's Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. On February 16, 2016, SoCalGas pled not guilty to the complaint. No trial date has been set.

~~On July 25, 2016,~~24, 2017, the County of Los Angeles ~~on behalf of itself and~~filed an application for a temporary restraining order to block DOGGR’s order. On July 28, 2017, the ~~people of the State of California, filed a complaint against SoCalGas in the Los Angeles County~~ Superior Court ~~for public nuisance, unfair competition, breach of franchise agreement, breach of lease,~~denied the application on the ground that, pursuant to Public Utilities Code sections 714 and ~~damages. This suit alleges that~~1759(a), the ~~four~~CPUC has jurisdiction over regulating injections at the Aliso Canyon natural gas storage ~~fields operated~~facility, and the Court therefore lacks jurisdiction to rule on the County’s application. On July 31, 2017, the County filed a petition for writ of mandate, prohibition, stay or ~~formerly operated~~other appropriate relief and a request for immediate stay in the Court of Appeal, seeking review of the Superior Court’s order denying the County’s application for a temporary restraining order. Later the same day, the Court of Appeal denied the County’s request for an immediate stay on injections. We provide further detail regarding DOGGR’s order and the County of Los Angeles’ petition in Note 11 of the Notes to Condensed Consolidated Financial Statements herein. Also on July 19, 2017, the CEC released a letter to the CPUC indicating that its staff is prepared to work with the CPUC and other agencies on a plan to phase out the use of the Aliso Canyon natural gas storage facility within ten years. The CEC and other stakeholders will be providing input into the SB 380 proceeding underway at the CPUC that addresses the future of the Aliso Canyon natural gas storage facility. Having completed the steps outlined by state agencies in order to safely begin injections at the Aliso Canyon natural gas storage facility, as of July 31, 2017, SoCalGas resumed limited injections.

If the Aliso Canyon natural gas storage facility were determined to be out of service for any meaningful period of time or permanently closed, or if future revenues were otherwise insufficient to recover its recorded value, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At June 30, 2017, the Aliso Canyon natural gas storage facility has a net book value of $582 million, including $237 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 ~~Los Angeles County require safety upgrades, including~~customer rates, and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Regulatory Proceedings

In February 2017, the ~~installation~~CPUC opened a proceeding pursuant to SB 380 to determine the feasibility of ~~sub-surface safety shut-off valves on every well. It additionally alleges that SoCalGas failed~~minimizing or eliminating the use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region. The proceeding will be conducted in two phases, with Phase 1 undertaking a comprehensive effort to ~~comply~~develop the appropriate analyses and scenarios to evaluate the impact of reducing or eliminating the use of the Aliso Canyon natural gas storage facility and Phase 2 evaluating the impacts of reducing or eliminating the use of the Aliso Canyon natural gas storage facility using the scenarios and models adopted in Phase 1. In accordance with the ~~Directive. It seeks preliminary~~Phase 1 schedule, public participation hearings began in April 2017, and ~~permanent injunctive relief, civil penalties,~~workshops and ~~damages~~additional public participation hearings are expected to occur later in 2017.

longer to complete than initially contemplated. In response, and as required by Section 455.5, the CPUC issued an OII to address whether the Aliso Canyon natural gas storage facility or any portion of that facility has been out of service for nine consecutive months pursuant to Section 455.5, and if it is determined to have been out of service, whether the CPUC should adjust SoCalGas’ rates to reflect the period the facility is deemed to have been out of service. As required under Section 455.5, if hearings on the investigation are necessary, they will be consolidated with SoCalGas’ next GRC proceeding. In the event that the CPUC determines that all or any portion of the facility has been out of service for nine consecutive months, the amount of any refund to ratepayers and the inability to earn a return on those assets could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

In March 2016, the CPUC ordered SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to ~~respond~~own and operate the Aliso Canyon natural gas storage facility and, in September 2016, approved SoCalGas’ request to begin tracking these revenues as of March 17, 2016. The CPUC will determine at a later time whether, and to what extent, the authorized revenues tracked in the memorandum account may be refunded to ratepayers.

Insurance

Excluding directors and officers liability insurance, we have four kinds of insurance policies that together provide between $1.2 billion to $1.4 billion in insurance coverage, depending on the nature of the claims. These policies are subject to various policy limits, exclusions and conditions. We have been communicating with our insurance carriers and intend to pursue the full extent of our insurance coverage. Through June 30, 2017, we have received $273 million of insurance proceeds for a portion of control-of-well expenses and a portion of temporary relocation costs. There can be no assurance that we will be successful in obtaining insurance coverage for costs related to the leak under the applicable policies, and to the extent we are not successful in obtaining coverage or these costs exceed the amount of our coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Our recorded estimate as ~~well~~of June 30, 2017 of $832 million of certain costs in connection with the Aliso Canyon natural gas storage facility leak may rise significantly as ~~punitive damages and attorneys' fees.~~

~~The costs of defending against these civil and criminal lawsuits and cooperating with these investigations,~~more information becomes available, and any ~~damages, restitution, and civil and criminal fines,~~ costs ~~and other penalties, if awarded or imposed,~~not included in our estimate could be ~~significant and to~~material. 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'~~SoCalGas’ and Sempra ~~Energy's~~Energy’s cash flows, financial condition and results of operations.

On January 6, 2016, the Governor of the State of California issued the Governor's Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor's Order implements various orders with respect to:Regulation

§	~~stopping the leak;~~

§	~~protecting public health and safety;~~

§	~~ensuring accountability; and~~

§	~~strengthening oversight.~~

We provide further detail regarding the Governor's Order and CARB's Aliso Canyon Methane Leak Climate Impacts Mitigation Program, issued pursuant to the Governor's Order, in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

On January 23, 2016, the Hearing Board of the SCAQMD ordered SoCalGas to, among other things, stop the leak, control the release of natural gas into the air, and conduct air monitoring and public health studies. We provide further detail regarding the SCAQMD's order in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

On January 25, 2016, the DOGGR and CPUC selected Blade Energy Partners to conduct an independent analysis under their supervision and to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon leak. We expect the root cause analysis to be completed in late 2016 or early 2017, but the timing is dependent on the DOGGR and the CPUC. In addition, effective February 5, 2016, the DOGGR amended the California Code of Regulations to require all underground natural gas storage facility operators, including SoCalGas, to take further steps to help ensure the safety of their gas storage operations. On July 8, 2016, DOGGR issued a Discussion Draft of new permanent regulations for all storage fields in California.

On April 1, 2016, the Secretary of the U.S. Department of Energy (DOE) and PHMSA jointly announced the formation of an Interagency Task Force on Natural Gas Storage Safety in response to the leak at Aliso Canyon to assess and make recommendations on best practices, response plans and safe operation of gas storage facilities. On June 22, 2016, President Obama signed the "Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016" or the "PIPES Act of 2016." Each of the PHMSA, DOGGR, SCAQMD, EPA and CARB ~~has~~have each commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. ~~We provide further details regarding~~As we discuss in “Factors Influencing Future Performance” in the ~~PIPES Act~~Annual Report, DOGGR issued new draft regulations for all storage fields in California, and ~~regulations issued by DOGGR following~~in 2016, the ~~Governor's Order, in Note 11~~California Legislature enacted four separate bills providing for additional regulation of ~~the Notes to the Condensed Consolidated Financial Statements herein.~~

~~The California legislature has enacted and the Governor has signed SB 380, which among other things: (1) continues the prohibition against SoCalGas injecting any natural gas into the Aliso Canyon~~ natural gas storage facility until a comprehensive review of the safety of the gas storage wells at the facility is completed by governmental agencies; (2) requires the CPUC, in consultation with various governmental agencies and other entities, to determine the range of working gas necessary in Aliso Canyon to ensure safety and reliability for the region and just and reasonable rates in California, and publish a report with such determination for public review and comment; and (3) requires the CPUC, no later than July 1, 2017, to open a proceeding to determine the feasibility of minimizing or eliminating use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region.

facilities. Additional hearings in the ~~state legislature,~~California Legislature, as well as with various other federal and state regulatory agencies, have been or ~~are expected to~~may be scheduled, additional legislation has been proposed in the ~~state legislature,~~California Legislature, and additional laws, orders, rules and regulations may be adopted. The Los Angeles County Board of Supervisors has formed a task force to review and potentially implement new, more stringent land use (zoning) requirements and associated regulations and enforcement protocols for oil and gas activities, including natural gas storage field ~~operations. Such new requirements~~operations, which could materially affect new or modified uses of the Aliso Canyon natural gas storage facility and other natural gas storage fields located in Los Angeles County.

We discuss these matters further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in Note 15 of the Notes to Consolidated Financial Statements, “Factors Influencing Future Performance” and “Risk Factors” in the Annual Report.

PIPES Act of 2016

In June 2016, the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” or the “PIPES Act of 2016” was enacted. Among other things, the PIPES Act of 2016:


▪	requires PHMSA to issue, within two years of passage, “minimum safety standards for underground natural gas storage facilities;”


▪	imposes a “user fee” on underground storage facilities as needed to implement the safety standards;

▪

grants PHMSA authority to issue emergency orders and impose emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for hearing, if the Secretary of Energy determines that an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes or is causing an imminent hazard; and


▪	directs the Secretary of Energy to establish an Interagency Task Force comprised of representatives from various federal agencies and representatives of state and local governments.

In December 2016, PHMSA published an interim final rule pursuant to the PIPES Act of 2016 that revises the federal pipeline safety regulations relating to underground natural gas storage facilities. The interim final rule incorporates consensus safety measures for the construction, maintenance, risk-management, and integrity-management procedures for natural gas storage. SoCalGas began the process of implementing such safety measures prior to formal adoption by PHMSA and is developing the associated documents and procedures required to demonstrate compliance with the standards.

SB 380

In May 2016, SB 380 became law and requires, among other things:


▪	that natural gas injections into the Aliso Canyon natural gas storage facility be prohibited until a comprehensive review of the safety of the gas storage wells at the facility was completed, as we discuss below;


▪	that all gas storage wells returning to service at the Aliso Canyon natural gas storage facility inject or produce gas only through the interior metal tubing and not through the annulus between the tubing and the well casing, which allows SoCalGas wells to operate with two complete barriers to mitigate the potential for an uncontrolled release of natural gas; and

▪

a CPUC proceeding (which was opened in February 2017) to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region, and to consult with various governmental agencies and other entities in making its determination. The order establishing the scope of the proceeding expressly excludes issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Aliso Canyon natural gas storage facility gas leak.

On July 19, 2017, DOGGR issued an order lifting the prohibition of the injection of natural gas into the Aliso Canyon natural gas storage facility and the CPUC’s Executive Director issued his concurrence with that determination, subject to certain conditions. On July 21, 2017, the County ~~including~~of Los Angeles filed a petition for writ of mandate against DOGGR and its State Oil and Gas Supervisor and the CPUC and its Executive Director, as to which SoCalGas is the real party in interest. The petition alleges that DOGGR has failed to properly conduct the comprehensive safety review ~~under~~required by SB 380 and failed to perform an Environmental Impact Review pursuant to CEQA. The petition seeks a writ of mandate requiring DOGGR and the State Oil and Gas Supervisor to comply with SB 380 and CEQA, as well as declaratory and injunctive relief against any authorization to inject natural gas.

On July 28, 2017, the Superior Court denied the County’s application for a temporary restraining order to block DOGGR’s order on the ground that, pursuant to Public Utilities Code sections 714 and 1759(a), the CPUC has jurisdiction over regulating injections at the Aliso Canyon natural gas storage facility, and the Court therefore lacks jurisdiction to rule on the County’s application. On July 31, 2017, the County filed a petition for writ of mandate, prohibition, stay or other appropriate relief and a request for immediate stay in the Court of Appeal, seeking review of the Superior Court’s order denying the County’s application for a temporary restraining order. Later the same day, the Court of Appeal denied the County’s request for an immediate stay on injections. SoCalGas completed the steps outlined by state agencies in order to safely begin injections at the Aliso Canyon natural gas storage facility and, as of July 31, 2017, resumed limited injection. We provide further detail regarding DOGGR’s order and the petition filed by the County of Los Angeles above and in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

SB 888

In September 2016, SB 888 became law, which requires that a penalty assessed against a gas corporation by the CPUC with regard to a natural gas storage facility leak must at least equal the amount necessary to fully offset the impact on the climate from the greenhouse gases emitted by the leak, as determined by the CARB. The CPUC also must consider the extent to which the gas corporation has mitigated or is in the process of mitigating the impact on the climate from greenhouse gas emissions resulting from the leak.

Proposed Legislation – SB 57

Proposed SB 57 seeks to extend the moratorium on natural gas injections at the Aliso Canyon natural gas storage facility until the root cause analysis of the leak that started in October 2015 has been completed. It would also require the CPUC to “act in a manner that will maximize transparency” in the course of completing its analysis regarding the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility. In addition, the bill would enable the Governor to authorize reinjection, production and withdrawal at the Aliso Canyon natural gas storage facility as necessary to respond to or avoid emergencies. The bill did not pass a vote in the California ~~Environmental Quality Act~~Senate but may be considered again.

Additional Safety Enhancements

In February 2017, SoCalGas notified the CPUC that it is accelerating its well integrity assessments on the natural gas storage wells at its La Goleta, Honor Rancho and ~~mitigation~~Playa del Rey natural gas storage fields consistent with the testing prescribed by SB 380 for the Aliso Canyon natural gas storage facility, proposed new DOGGR regulations, and SoCalGas’ Storage Risk Management Plan. In addition, SoCalGas indicated its plan to reconfigure its operating natural gas storage wells such that natural gas will be injected or produced only through the interior metal tubing and not through the annulus between the tubing and the well casing to maintain a double barrier and additional layer of ~~environmental impacts associated~~safety, which is consistent with ~~new~~the direction of federal and ~~modified uses~~state regulations. SoCalGas anticipates that this work will reduce the injection and withdrawal capacity of each of these other storage fields. Depending on the ~~fields.~~volume of natural gas in storage in each field at the time natural gas is injected or withdrawn, the reduction could be significant and could impact natural gas reliability and electric generation. In March 2017, SoCalGas revised its plan, as directed by the CPUC, for converting all wells to tubing-only operation to maintain a prescribed withdrawal capacity.

Higher operating costs and additional capital expenditures incurred by SoCalGas as a result of new laws, orders, rules and regulations arising out of ~~this~~the Aliso Canyon natural gas storage facility incident or our responses thereto could be significant and to the extent not covered by insurance or recoverable in customer rates, 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 service reliability during peak demand periods, including peak electric generation needs in the summer, as well as heating needs in the winter. Aliso Canyon, with a storage capacity of 86 billion cubic feet (Bcf), is the largest SoCalGas storage facility and an important element of SoCalGas' delivery system. Aliso Canyon represents 63 percent of SoCalGas' owned natural gas storage inventory capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, in accordance with the Governor's Order, but in conflict with the CPUC's reliability-based direction. On March 4, 2016, the DOGGR issued Order 1109, ~~Order to Take Specific Actions Regarding Aliso Canyon Gas Storage Facility (Safety Review Testing Regime)~~. On April 7, 2016, SoCalGas announced its safety framework to comply with the DOGGR Order 1109, which consists of phased testing for each of the active injection wells in the Aliso Canyon storage facility. SoCalGas will continue this moratorium on further injections until all required approvals have been obtained.

If the Aliso Canyon facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the facility, significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At June 30, 2016, the Aliso Canyon facility has a net book value of $441 million, including $199 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, and ~~SoCalGas'~~SoCalGas’ and Sempra ~~Energy's results of operations, cash flows and financial condition may be materially adversely affected.~~

On March 17, 2016, the CPUC issued a decision directing SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon gas storage field. The CPUC will determine at a later time whether, and to what extent, the tracked revenues may be refunded to ratepayers. Pursuant to the CPUC's decision, on March 24, 2016, SoCalGas filed an advice letter requesting to establish a memorandum account to track all business-as-usual costs to own and operate the Aliso Canyon storage field, which has been protested by TURN and SCGC. On April 22, 2016, the CPUC's Energy Division issued a suspension notice for SoCalGas' advice letter citing the need for additional time for staff review.

We have at least four kinds of insurance policies that provide in excess of $1 billion in insurance coverage. We have been communicating with our insurance carriers and intend to pursue the full extent of our insurance coverage. These policies are subject to various policy limits, exclusions and conditions. There can be no assurance that we will be successful in obtaining insurance coverage for costs related to the leak under the applicable policies, and to the extent we are not successful, it could result in a material charge against the earnings of SoCalGas and Sempra Energy.

Our estimate at June 30, 2016 of $717 million of certain costs in connection with the Aliso Canyon storage facility leak may rise significantly as more information becomes available, 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 Sempra Energy's and SoCalGas'Energy’s cash flows, financial condition and results of ~~operations.~~ operations may be materially adversely affected by any such new laws, orders, rules and regulations.

SoCalGas Billing Practices

In ~~addition,~~May 2017, the CPUC issued an OII to determine whether SoCalGas violated any provisions of the California Public Utilities Code, General Orders, CPUC decisions, or other requirements pertaining to billing practices from 2014 through 2016. In particular, the CPUC is examining the timeliness of monthly bills, extending the billing period for customers, and issuing estimated bills. Under the OII, the CPUC will also examine SoCalGas’ gas tariff rules and consider whether to impose penalties or other remedies. We expect a decision on the OII in 2018.

CALIFORNIA UTILITIES – JOINT MATTERS

Capital Project Updates

We summarize below updates regarding certain major joint capital projects at our California Utilities.



CAPITAL PROJECTS – CALIFORNIA UTILITIES

Project description		Estimated capital cost (in millions)				Status
Mobile Home Park Utility Upgrade Program
§	May 2017 application filed with the CPUC to convert an additional 20 percent of eligible units to direct utility service, for a total of 30 percent of mobile homes.		$	471	§	Application pending
			to
			$	508
§	Estimated implementation cost of $2 million of O&M at SDG&E and $3 million to $4 million of O&M at SoCalGas.
Pipeline Safety Enhancement Plan
§	March 2017 application filed with the CPUC to recover forecasted costs associated with twelve Phase 1B and Phase 2A pipeline safety projects.		$	198	§	Application pending
§	Estimated implementation cost of $57 million of O&M at SoCalGas.

Incentive Mechanisms

Energy Efficiency

The CPUC has established incentive mechanisms that are based on the effectiveness of energy efficiency programs. In March 2017, the CPUC approved the settlement agreements reached with the ORA and TURN regarding the incentive awards for program years 2006 through 2008, wherein the parties agreed that SDG&E and SoCalGas would offset up to a total of approximately $4 million each against future incentive awards over the next three years beginning in 2017. If the total incentive awards ultimately authorized for 2017 through 2019 are less than approximately $4 million for either utility, the applicable utility is released from paying any remaining unapplied amount.

Natural Gas Procurement

In June 2017, SoCalGas filed an application for a GCIM award of $4 million for natural gas procured for its core customers during the 12-month period ended March 31, 2017. A CPUC decision is expected in the first half of 2018.

In June 2016, SoCalGas filed an application for a GCIM award of $5 million for the 12-month period ended March 31, 2016. The CPUC approved the award in January 2017.

Natural Gas Pipeline Operations Safety Assessments

In 2011, the California Utilities filed implementation plans with the CPUC to implement the CPUC’s significant and urgent safety directive to test or replace natural gas transmission pipelines that have not been pressure tested and to reduce the time for valves to stop the flow of gas if a break in a pipeline occurs (referred to as PSEP). In 2014, the CPUC issued a final decision approving 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. In 2016, the CPUC issued a final decision authorizing SoCalGas and SDG&E to recover, subject to refund pending reasonableness review, 50 percent of the revenue requirements associated with completed Phase 1 projects. The decision also incorporates a forward looking schedule to (1) file two reasonableness review applications for Phase 1 projects completed through 2017, (2) file one forecast application for Phase 2 project costs to be incurred in 2017 and 2018, and (3) include all other PSEP costs in future GRCs.

In September 2016, SoCalGas and SDG&E filed a joint application with the CPUC for its second PSEP reasonableness review and rate recovery of costs of certain pipeline safety projects completed by June 30, 2015 and recorded in their authorized regulatory accounts. The total costs submitted for review are $195 million ($180 million for SoCalGas and $15 million for SDG&E). SoCalGas and SDG&E expect a decision from the CPUC in 2018. This proceeding has been challenged by consumer advocacy groups. However, we believe these costs were prudent, were incurred in accordance with the program, and should be substantially approved for recovery.

In March 2017, SoCalGas and SDG&E filed an application with the CPUC requesting approval of the forecasted revenue requirement necessary to recover the costs associated with twelve Phase 1B and Phase 2A pipeline safety projects. The California Utilities expect to incur total costs for the twelve projects of approximately $255 million ($198 million in capital expenditures and $57 million in O&M) to be effective in rates on January 1, 2019. SoCalGas and SDG&E expect a CPUC decision in the second half of 2018.

As shown in the table below, SoCalGas and SDG&E have made significant pipeline safety investments under this program, and SoCalGas expects to continue making significant investments as approved through various regulatory proceedings. SDG&E’s PSEP program is expected to be substantially complete in 2017, with the exception of the Pipeline Safety & Reliability Project that is currently under regulatory review.



PIPELINE SAFETY ENHANCEMENT PLAN – REASONABLENESS REVIEW SUMMARY
(Dollars in millions)
	2011 through June 30, 2017
	Total invested(1)		CPUC review completed(2)		CPUC review pending(3)		2018 recovery filing(4)(5)
Sempra Energy Consolidated:
Capital	$	1,351	$	8	$	143	$	1,200
Operation and maintenance	173		25		63		85
Total	$	1,524	$	33	$	206	$	1,285
SoCalGas:
Capital	$	1,031	$	8	$	129	$	894
Operation and maintenance	164		25		62		77
Total	$	1,195	$	33	$	191	$	971
SDG&E:
Capital	$	320	$	—	$	14	$	306
Operation and maintenance	9		—		1		8
Total	$	329	$	—	$	15	$	314

(1) Excludes disallowed costs through June 30, 2017 of $6 million at SoCalGas and $1 million at SDG&E for pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961.

(2) Approved in December 2016; excludes $2 million of PSEP-specific insurance costs for which recovery may be requested in a future filing.

(3) Reasonableness Review Application for completed projects totaling $195 million filed in September 2016. Also includes approximately $11 million of pre-engineering costs incurred to support projects under development and submitted as part of the Forecast Application filed in March 2017. Both decisions expected in 2018.

(4) Reasonableness Review Application to be filed in late 2018 and expected to include substantially all of these costs. Remaining costs not included in the ~~$717 million estimate, could~~2018 application are expected to be ~~material,~~filed in a future GRC.

(5) Authorized to recover 50 percent of the revenue requirement annually, subject to refund.

Regulatory Compliance and Safety Enforcement

In October 2016, the CPUC’s CPED issued a citation to SoCalGas for alleged violations of certain environmental mitigation measures related to the Aliso Canyon Turbine Replacement Project, and imposed a fine in the amount of $699,500. SoCalGas subsequently appealed the citation and the resulting fine. In March 2017, SoCalGas and the CPED filed a joint settlement agreement with the CPUC to resolve all matters related to the October 2016 citation. As a part of the settlement agreement, SoCalGas agreed to pay $250,000 to the state’s general fund and to retain an independent firm to conduct compliance training seminars for the ~~extent~~benefit of SoCalGas and CPUC personnel at a cost not ~~covered~~to exceed $25,000. The parties agreed that the settlement agreement did not constitute an admission by ~~insurance (including~~SoCalGas or denial by CPED with respect to any ~~costs in excess~~issue of ~~applicable policy limits), could have~~fact or law, or of any violation or liability by any party. In May 2017, the CPUC issued a ~~material adverse effect on Sempra Energy's and SoCalGas' cash flows, financial condition and results of operations.~~decision approving the settlement as filed.

~~We discuss this matter further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in "Risk Factors"~~Other California Utilities – Joint Matters

For a discussion about “Future Risk-Based GRC,” see “Factors Influencing Future Performance” in the Annual Report.

~~Industry Developments~~

SEMPRA SOUTH AMERICAN UTILITIES

Chilquinta Energía’s most recent review process for distribution rates was completed in November 2016, covering the period from November 2016 through October 2020. We expect a final decree to be released during the second half of 2017 and to be retroactive from November 2016, which we do not expect to have a material impact on our results.

Capital ~~Projects~~Project Updates

We ~~describe~~summarize below updates regarding certain major capital projects ~~electric and natural gas regulation and rates, and~~at Sempra South American Utilities’ joint venture partnerships.



CAPITAL PROJECTS – SEMPRA SOUTH AMERICAN UTILITIES

Project description		Our share of estimated capital cost (in millions)				Status
Chilquinta Energía - Eletrans
§	220-kV electric transmission line awarded in June 2017.		$	50	§	Estimated completion: 2021
§	Transmission line in the northern region of Chile to extend approximately 133 miles.
§	Once in operation, will earn a return in U.S. dollars, indexed to the CPI, for 20 years and a regulated return thereafter.
§	50-percent equity interest in joint venture.

Other Sempra South American Utilities Matters

For a discussion about other ~~pending proceedings and investigations that affect the California~~Sempra South American Utilities ~~in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements~~matters, see “Factors Influencing Future Performance” in the Annual Report.

SEMPRA ~~INTERNATIONAL~~MEXICO

Capital Project Updates

~~As we discuss in "Cash Flows from Investing Activities," our investments will significantly impact our future performance. In addition to the discussion~~We summarize below ~~we provide information about these investments in "Capital Resources and Liquidity" herein and in our Annual Report.~~

~~Sempra South American Utilities~~

~~Overview~~

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. Sempra South American Utilities is also expected to provide earnings from constructioncertain major capital projects ~~when completed and from other investments, but will require substantial funding for these investments.~~

Revenues at Chilquinta Energía are based on rates set by the National Energy Commission (Comisión Nacional de Energía). The current rates for sub-transmission, in effect since 2011, and previously extended to cover 2015, have been further extended until December 2017. The next rate reviews for sub-transmission are scheduled to be completed, with tariff adjustments also going into effect, in January 2018 and will cover the period from January 2018 to December 2019. A change in law issued in July 2016 will change the rate methodology for sub-transmission beginning in 2020. The next rate reviews for distribution are scheduled to be completed, with tariff adjustments also going into effect, in November 2016 and will cover the period from November 2016 to October 2020.

Luz del Sur serves primarily regulated customers, and revenues are based on rates set by the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería). The next rate reviews are scheduled to bethat were completed in 2017 ~~and will cover the period from November 2017 to October 2021.~~at Sempra Mexico.



CAPITAL PROJECTS COMPLETED IN 2017 – SEMPRA MEXICO

Project description
Sonora Pipeline
§	Awarded two contracts in October 2012 by the CFE to build and operate a 500-mile pipeline network.	§	First segment completed in stages from fourth quarter of 2014 through August 2015.
§	Comprised of two segments that interconnect to the U.S. interstate pipeline system.	§	Second segment completed in May 2017.
§	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.
§	Capacity is fully contracted by the CFE under two 25-year contracts denominated in U.S. dollars.
Ojinaga Pipeline
§	December 2014 agreement with CFE for development, construction and operation of the approximately 137-mile pipeline.	§	Pipeline completed in June 2017.
§	Natural gas transportation services agreement for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity, equal to 1.4 Bcf per day.
San Isidro Pipeline
§	July 2015 agreement with CFE for development, construction and operation of the approximately 14-mile pipeline.	§	Pipeline completed in March 2017.
§	Natural gas transportation services agreement for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity, equal to 1.1 Bcf per day.	§	Compressor station completed in June 2017.

We ~~discuss revenues~~summarize below updates regarding certain major capital projects at Sempra South American Utilities in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report. We discuss the impact of tax reform in Chile and Peru in "Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report.Mexico.

Sempra Energy has a combined $761 million in goodwill recorded at June 30, 2016 related to Chilquinta Energía and Luz del Sur. Goodwill is subject to impairment testing annually, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report.

~~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-kilovolt (kV) transmission lines in Chile. The approximately 100-mile, $80 million transmission line extending from Cardones to Diego de Almagro was completed in November 2015. The remaining 50-mile, $85 million transmission line extending from Ciruelos to Pichirropulli is expected to be completed in 2017.

In June 2013, Eletrans II S.A. was awarded two 220-kV transmission lines in Chile. The transmission lines will extend approximately 60 miles, and we estimate the projects will cost approximately $80 million in total and be completed in 2018.

~~Once the transmission lines are in operation, they will earn a return in U.S. dollars, indexed to the Consumer Price Index, for twenty years and a regulated return thereafter.~~

Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A., its affiliate, totaling $79 million outstanding at June 30, 2016 to provide project financing for the construction of transmission lines.

~~The projects will be financed by the joint venture partners during construction. 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. In May 2016, Luz del Sur received regulatory approval for a second transmission investment plan that includes the development and operation of five substations and their related transmission lines in Lima. We estimate that the project will cost approximately $130 million and will be in service beginning in 2017 through 2020 as portions are completed. Once in operation, the capitalized cost of the projects will earn the regulated return for 30 years. The projects 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 and from joint venture investments. We expect projects, joint venture investments and dividends in Mexico to be funded by available funds, including credit facilities, and funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent, partnering in joint ventures and proceeds from the planned sale of its TdM natural gas-fired power plant.

IEnova and PEMEX are 50-50 partners in the joint venture Gasoductos de Chihuahua S. de R.L. de C.V. (GdC). In July 2015, IEnova entered into an agreement to purchase PEMEX's 50-percent interest in GdC. In July 2016, IEnova announced the parties reached an agreement to restructure the transaction in order to satisfy conditions imposed by Mexico's antitrust commission. Subject to final approval by the Mexico antitrust commission, IEnova expects to move forward with the acquisition of GdC's assets, for a purchase price of approximately $1.1 billion. The transaction remains subject to satisfactory completion of the Mexican antitrust review and customary closing conditions, and may require further approvals from other Mexican authorities. We expect the transaction to close in the third quarter of 2016.

Sempra Energy has committed to provide interim financing to close the transaction. We expect to ultimately finance the acquisition with a combination of debt and equity at IEnova based on market conditions.

~~We discuss the pending acquisition further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.~~

The sharp decline in crude oil prices beginning in late 2014 and continuing into 2016, as well as low natural gas prices, have had a negative impact on PEMEX's revenues, income and cash flows. Certain rating agencies have expressed several concerns regarding PEMEX's financial condition, including the total amount of PEMEX's debt and the significant increase in PEMEX's indebtedness over the last several years, as well as its substantial unfunded reserve for retirement pensions and seniority premiums. In November 2015, a major U.S. credit rating agency revised PEMEX's global foreign currency and local currency credit ratings from A3 to Baa1 and changed the outlook for its credit ratings to negative. In March 2016, the same major credit rating agency further downgraded PEMEX's global foreign currency and local currency credit ratings from Baa1 to Baa3. In May 2016, in connection with a proposed debt offering by PEMEX, the same major credit agency reaffirmed that the outlook on PEMEX's credit ratings remains negative. PEMEX is also subject to the control of the Mexican government, which could limit its ability to satisfy its external debt obligations. Although PEMEX is a State Productive Enterprise of Mexico, its financing obligations are not guaranteed by the Mexican government. As both a partner in the GdC joint venture and a customer with capacity contracts for transportation services on Sempra Mexico's ethane and propane pipelines, if PEMEX were unable to meet any or all of its obligations to Sempra Mexico, it could have a material adverse effect on Sempra Energy's financial condition, results of operations and cash flows.

In February 2016, management approved a plan to market and sell Sempra Mexico's TdM, a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we stopped depreciating the plant and classified the plant as an asset held for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. We expect to complete the sale in the second half of 2016.

~~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. The first segment was completed in stages, with a section completed in the fourth quarter of 2014 and the final section completed in August 2015. We expect to complete the second segment in 2016. The capacity is fully contracted by the CFE under two 25-year contracts denominated in U.S. dollars.

In 2014, the GdC joint venture and affiliates of PEMEX executed agreements for the development of Los Ramones Norte, a natural gas pipeline of approximately 280 miles and two compression stations, which connects with the first phase of Los Ramones and runs to the vicinity of San Luis Potosi, with an estimated cost of $1.45 billion. The GdC joint venture has a 50-percent interest in the project. The pipeline began commercial operation in February 2016. The two compression stations began operations in June 2016. The pipeline's capacity is fully contracted under a 25-year transportation services agreement with the National Center of Natural Gas Control (Centro Nacional de Control de Gas Natural, or CENAGAS), denominated in Mexican pesos, indexed to the U.S. dollar and adjusted annually for inflation and fluctuation of the exchange rate. The transportation services agreement was transferred from PEMEX to CENAGAS in January 2016.

Sempra Mexico has loans to an affiliate of its joint venture with PEMEX totaling $88 million outstanding at June 30, 2016 to finance a portion of its investment in the Los Ramones Norte pipeline project.

In December 2014, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars, for 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 137-mile, 42-inch pipeline, with an estimated cost of $300 million. We expect the pipeline to begin operations in the first half of 2017.

In July 2015, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the San Isidro pipeline, equal to 1.1 Bcf per day. Sempra Mexico will be responsible for the development, construction and operation of the approximately 14-mile pipeline, with an estimated cost of $110 million. We expect the pipeline to begin operations in the first half of 2017.

In May 2016, IEnova entered into a natural gas transportation services agreement with CFE for a 21-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the Empalme Lateral pipeline, equal to 226 million cubic feet (MMcf) per day. IEnova will be responsible for the development, construction and operation of the approximately 12-mile pipeline, with an estimated cost of $12 million. We expect the pipeline to begin operations in the first half of 2017.

In June 2016, Infraestructura Marina del Golfo, a joint venture between IEnova and a subsidiary of TransCanada Corporation (TransCanada), was awarded the right to build, own and operate the Sur de Texas – Tuxpan natural gas pipeline by the CFE. IEnova has a 40-percent interest in the project and TransCanada owns the remaining 60-percent interest. The project has an estimated cost of $2.1 billion, is expected to be completed in late 2018 and is fully contracted under a 25-year natural gas transportation service contract, denominated in U.S. dollars, with the CFE.

IEnova continues to monitor CFE project opportunities and carefully analyze CFE bids in order to participate in those that fit its overall growth strategy. Competition for recent pipeline projects has been intense with numerous bidders competing aggressively for these projects. There can be no assurance that IEnova will be successful in bidding for new CFE projects.

The ability to successfully complete pipeline projects, like other major construction projects, is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see "Risk Factors" in our Annual Report.

~~Energía Sierra Juárez~~

In June 2015, we began commercial operations of the first phase of the Energía Sierra Juárez wind generation project, a 50-percent joint venture with InterGen N.V. The project is designed to provide up to 1,200 MW of capacity if fully developed. The 155-MW first phase of the Energía Sierra Juárez wind generation project is fully contracted by SDG&E. Future expansion of Energía Sierra Juárez will depend, among other factors, on the ability to obtain additional power purchase contracts.

~~Sempra Mexico has a U.S. dollar-denominated loan to Energía Sierra Juárez, its affiliate, totaling $17 million outstanding at June 30, 2016 to finance the first phase of the project.~~



CAPITAL PROJECTS – SEMPRA MEXICO

Project description		Estimated capital cost (in millions)				Status
Pima Solar
§	Awarded 110-MW photovoltaic project located in Sonora, Mexico in March 2017.		$	115	§	Construction expected to commence in the fourth quarter of 2017.
§	Entered into a 20-year, U.S. dollar-denominated PPA in March 2017 to provide renewable energy, clean energy certificates and capacity.				§	Estimated completion: fourth quarter of 2018.
Liquid Fuels Terminals at Port of Veracruz, Puebla and Mexico City
§	Awarded a 20-year concession in July 2017 to build and operate a marine terminal in the Port of Veracruz in Mexico for the receipt, storage and delivery of liquid fuels.		$	155	§	Includes marine concession fees totaling $55 million for concession rights: half to be paid in August 2017 and half to be paid in January 2018.
§	Capacity of 1.4 million barrels of gasoline, diesel and jet fuel to supply the central region of Mexico.				§	Expected completion of marine terminal: end of 2018.
§	IEnova will also build and operate two storage terminals located near Puebla and Mexico City with storage capacities of 500,000 and 800,000 barrels, respectively.		$	120	§	Expected completion of two inland storage terminals: first half of 2019.
§	Entered into three, long-term, U.S. dollar-denominated terminal services agreements in July 2017 with Valero Energy for the full capacity of the marine terminal and the two inland storage terminals.
§	Pursuant to these agreements, Valero Energy has the option to purchase a 50-percent interest in each of the three terminals after commencement of commercial operations, subject to approval by the Port of Veracruz, COFECE and the CRE.

Energía Costa Azul LNG Terminal

In ~~February~~May 2015, Sempra ~~Natural Gas,~~LNG & Midstream, IEnova, and a subsidiary of PEMEX entered into a ~~Memorandum of Understanding (MOU) to collaborate in~~project development agreement for the joint development of athe proposed natural gas liquefaction project at ~~IEnova's~~IEnova’s existing regasification terminal at Energía Costa Azul. The ~~MOU defines~~agreement specifies how the ~~basis~~parties will share costs, and establishes a framework for the parties to ~~explore PEMEX's participation in this potential~~work jointly on permitting, design, engineering and commercial activities associated with exploring the development of the 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; we have also started to share developmentproject. We are sharing costs with ~~PEMEX.~~PEMEX on the development efforts pursuant to the agreement, and have applied for the primary governmental authorizations for the liquefaction project. Energía Costa Azul has profitable long-term regasification contracts for 100 percent of the ~~facility,~~regasification facility’s capacity, 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 financially than continuing to supply regasification services under our existing contracts.

Development of this project is subject to ~~a number of~~numerous risks and uncertainties, including the receipt of a number of permits and regulatory approvals; finding suitable partners and customers; obtaining financing; negotiating and completing suitable commercial agreements, including joint venture agreements, ~~tolling capacity~~LNG sales agreements, gas supply agreements and construction contracts; reaching a final investment decision; and other factors associated with this potential investment. ~~See "Risk Factors"~~For a discussion of these risks, see “Risk Factors” in ~~our~~the Annual Report.

Termoeléctrica de Mexicali

Our TdM power plant is currently held for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

Other Sempra Mexico Matters

For a discussion about other Sempra Mexico matters, see “Factors Influencing Future Performance” in the Annual Report.

SEMPRA ~~U.S. GAS & POWER~~RENEWABLES

Sempra ~~Renewables~~

~~Overview~~Renewables’ performance is primarily a function of the solar and wind power generated by its assets. Power generation from these assets depends on solar and wind resource levels, weather conditions, and Sempra Renewables’ ability to maintain equipment performance.

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 2017. 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 other forms of equity sales, including tax equity. The varying costs of these alternative financing sources impact the projects' returns.

~~Sempra Renewables'~~Renewables’ future performance and the demand for renewable energy is impacted by various market factors, most notably state mandated requirements for utilities to deliver a portion of total energy load from renewable energy sources. ~~The rules governing these requirements are generally known as the Renewables Portfolio Standard (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.

~~Apple Blossom Wind~~Capital Project Updates

We summarize below a new solar project at Sempra Renewables.



CAPITAL PROJECT – SEMPRA RENEWABLES

Project description			Status
Solar Project
§	Capable of producing up to 200 MW of solar power once fully constructed, located in Fresno County, California, acquired in July 2017.	§	Expect commercial operation dates and corresponding contracted energy sales to commence in phases beginning in the fourth quarter of 2017 and the first half of 2018.
§	Fully contracted under four PPAs with an average contract term of 18 years.

SEMPRA LNG & MIDSTREAM

Capital Project Updates

We summarize below Sempra LNG & Midstream’s completion of the Cameron Interstate Pipeline expansion project.



CAPITAL PROJECT COMPLETED IN 2017 – SEMPRA LNG & MIDSTREAM

Project description
Cameron Interstate Pipeline Expansion
§	3.5-mile, 36-inch pipeline addition to existing Cameron Interstate Pipeline, adding bi-directional flow of up to 1.5 Bcf of natural gas per day.	§	Expansion project completed in the second quarter of 2017.
§	Includes construction of a compressor station and construction of and modifications to meter stations.
§	Authorized by FERC in June 2014 and approved to commence service in April 2017.

We summarize below updates regarding the Cameron LNG JV three-train liquefaction joint venture project at Sempra LNG & Midstream.



CAPITAL PROJECT – SEMPRA LNG & MIDSTREAM

Project description			Status
Cameron LNG JV Three-Train Liquefaction Project
§	Sempra Energy contributed Cameron LNG, LLC’s existing facilities to Cameron LNG JV, of which Sempra Energy indirectly owns 50.2 percent, and construction began in the second half of 2014.	§	Recently, the EPC contractor notified the Cameron LNG JV that its project schedule had again changed. Based on several factors, we think it is reasonable to expect that the first LNG train could be delayed into 2019, with the second and third LNG trains following throughout 2019.
§	Anticipated incremental investment of approximately $7 billion by Cameron LNG JV.
§	Capacity of 13.9 Mtpa of LNG with an expected export capacity of 12 Mtpa of LNG, or approximately 1.7 Bcf per day.
§	Authorized to export up to 14.95 Mtpa of LNG to both FTA and Non-FTA countries.
§	20-year liquefaction and regasification tolling capacity agreements for full nameplate capacity.

Cameron LNG JV Three-Train Liquefaction Project

~~In July 2016, Sempra Renewables acquired~~Large-scale construction projects like the ~~Apple Blossom Wind project, a 100-MW wind farm currently under~~design, development ~~in Huron County, Michigan. Consumers Energy has contracted for all of the energy generated from the project for 15 years upon project completion, which is expected by the end of 2017.~~

~~Black Oak Getty Wind Project~~

~~In March 2015, Sempra Renewables acquired the Black Oak Getty Wind project, a 78-MW wind farm currently under construction in Stearns County, Minnesota. Sempra Renewables is completing the~~and construction of the ~~wind farm,~~Cameron LNG JV liquefaction facility involve numerous risks and uncertainties, including among others, the potential for unforeseen engineering challenges, substantial construction delays and increased costs. Cameron LNG JV has a turnkey EPC contract, and if the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, the project could face substantial construction delays and potentially significantly increased costs, which could, if serious enough, require Cameron LNG JV to engage a substitute contractor. In October 2016, the EPC contractor indicated that the Cameron LNG project would not achieve its originally scheduled dates for completion. Recently, the EPC contractor notified the Cameron LNG JV that its project schedule had again changed. This change projected further delays to the Cameron LNG project, which we expect will result in the ~~project to be fully operational by the end of 2016. Minnesota Municipal Power Agency has contracted for the energy generated from the project for 20 years upon project completion.~~

~~Copper Mountain Solar~~

~~Copper Mountain Solar is a photovoltaic generation facility operated~~anticipated earnings and under construction by Sempra Renewables in Boulder City, Nevada. When fully developed and constructed, the project will be capable of producing up to approximately 550 MW of solar power, with 458 MW currently in operation, of which Sempra Renewables has 50-percent ownership of 400 MW through joint venture partnerships, and 100-percent ownership of the 58-MW facility. It is being developed in multiple phases as power sales become contracted.

In July 2014, Sempra Renewables signed a 20-year power purchase agreement (PPA) with Edison for all of the solar power from Copper Mountain Solar 4 beginning in 2020. The CPUC approved the PPA in March 2015. We expect Copper Mountain Solar 4 to be in service by the end of 2016. Sempra U.S. Gas & Power will market the output from Copper Mountain Solar 4 before the start of the Edison contract term. Copper Mountain Solar 4 will total 94 MW when completed.

~~Mesquite Solar~~

Mesquite Solar is a photovoltaic generation facility under construction by Sempra Renewables in Maricopa County, Arizona. If fully developed and constructed, the project will be capable of producing up to approximately 700 MW of solar power, with 150 MW currently in operation in a joint venture with Consolidated Edison Development (Mesquite Solar 1). In June 2015, Sempra Renewables signed a 20-year power sale agreement with Edison for 100 MW of solar power from the second phase of Mesquite Solar (Mesquite Solar 2). The CPUC approved the PPA in December 2015. In July 2015, Sempra Renewables signed a 25-year PPA with the Western Area Power Administration on behalf of the U.S. Department of the Navy for 150 MW of solar power from the third phase of Mesquite Solar (Mesquite Solar 3). We expect Mesquite Solar 2 and 3 to be in service by the end of 2016.

~~Sempra Natural Gas~~

~~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 exportassociated cash flows from the Cameron LNG JV ~~terminal (discussed~~project coming in ~~"Cameron Liquefaction" below)~~later than originally anticipated. Based on several factors, we think it is reasonable to expect that the first LNG train could be delayed into 2019, with the second and third LNG trains following throughout 2019. These factors include the updated schedule recently received from the EPC contractor, Cameron LNG JV’s own review of the project’s schedule, and the inherent risks in constructing and testing facilities such as Cameron LNG. We continue to work with the EPC contractor and our Cameron LNG JV partners regarding the project’s schedule and the EPC contractor’s delays. During the course of construction of large projects like Cameron LNG, contractors often assert that they are owed additional compensation, schedule extensions, or both. Cameron LNG JV has received information from the EPC contractor claiming they are owed additional amounts beyond the contract value. The contractor has informed Cameron LNG JV that they will supplement this information at a future date. We have not yet been provided with sufficient details that would enable an evaluation of the validity or amount of such purported claims. For a discussion of the Cameron LNG JV and of these risks and other risks relating to the development of the Cameron LNG JV liquefaction project that could adversely affect our future performance, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Our Business - Sempra LNG & Midstream” and “Risk Factors” in the Annual Report.

Proposed Additional Cameron Liquefaction Expansion

Cameron LNG JV has received the major permits necessary to expand the current configuration of the Cameron LNG JV liquefaction project from the current three liquefaction trains under construction. The proposed expansion project includes up to two additional liquefaction trains, capable of increasing LNG production capacity by approximately 9 Mtpa to 10 Mtpa, and up to two additional full containment LNG storage tanks (one of which was permitted with the original three-train project). Advancement of the project includes


▪	DOE FTA approval received in July 2015


▪	Non-FTA approval received in July 2016


▪	FERC permit received in May 2016

Under the Cameron LNG JV financing agreements, expansion of the Cameron LNG JV 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. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all 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 are taking place, and we are considering a variety of options to attempt to move this project forward. These activities have contributed to delays in developing firm pricing information and securing customer commitments, and there can be no assurance that these issues will be resolved in a timely manner, which could materially and adversely impact the near-term marketing of this project and ability to secure customer commitments. In light of these developments, we are unable to predict when we and/or Cameron LNG JV might be able to move forward on this project.

The expansion of the Cameron LNG JV facilities beyond the first three trains is subject to a number of risks and uncertainties, including amending the Cameron LNG JV agreement among the partners, obtaining customer commitments, completing the required commercial agreements, securing and maintaining all necessary permits, approvals and consents, obtaining financing, reaching a final investment decision among the Cameron LNG JV partners, and other factors associated with the potential investment. See “Risk Factors” in the Annual Report.

Other LNG Liquefaction Development

Design, regulatory and commercial activities are ongoing for potential LNG liquefaction developments at our Port Arthur, Texas site and at Sempra Mexico’s Energía Costa Azul facility. For these development projects, ~~if anticipated cash flows support~~we have met with potential customers and determined there is an interest in long-term contracts for LNG supplies beginning in the 2022 to 2025 time frame.

Port Arthur

In November 2016, Sempra LNG & Midstream submitted a request to the FERC seeking authorization to site, construct and operate the proposed Port Arthur LNG natural gas liquefaction and export facility in Port Arthur, Texas.


▪	The proposed project is designed to include


◦	two natural gas liquefaction trains with production capability of approximately 13.5 Mtpa, or 698 Bcf per year;


◦	three LNG storage tanks;


◦	natural gas liquids and refrigerant storage;


◦	feed gas pre-treatment facilities; and


◦	two berths and associated marine and loading facilities.


▪	In June 2015, Sempra LNG & Midstream filed permit applications with the DOE for authorization to export the LNG produced from the proposed project to all current and future non-FTA countries.


▪	In August 2015, Sempra LNG & Midstream received authorization from the DOE to export the LNG produced from the proposed project to all current and future FTA countries.

▪

In February 2016, Sempra LNG & Midstream and Woodside Petroleum Ltd. entered into a project development agreement for the joint development of the proposed Port Arthur LNG liquefaction project. The agreement specifies how the parties will share costs, and establishes a framework for the parties to work jointly on permitting, design, engineering, commercial and marketing activities associated with developing the Port Arthur LNG liquefaction project.

▪

In June 2017, Sempra LNG & Midstream, Woodside Petroleum Ltd. and Korea Gas Corporation signed a memorandum of understanding that provides a framework for cooperation and joint discussion by the parties regarding key aspects of the potential development of the Port Arthur LNG project, including engineering and construction work, O&M activities, feed gas sourcing, offtake of LNG and the potential for Korea Gas Corporation to purchase LNG from, and become an equity participant in, the Port

Arthur LNG project. The memorandum of understanding does not commit any party to buy or sell LNG or otherwise participate in the Port Arthur liquefaction LNG project.

Also, in November 2016, Sempra LNG & Midstream filed a permit application with the FERC for a pipeline project that will provide natural gas transportation service for the Port Arthur LNG liquefaction project. In February 2017, Sempra LNG & Midstream initiated the FERC pre-filing review process for a potential permit application for an additional pipeline project that would also provide natural gas transportation service for the Port Arthur LNG liquefaction project.

Development of the Port Arthur LNG liquefaction project is subject to a number of risks and uncertainties, including completing the required commercial agreements, such as joint venture agreements, LNG sales agreements and gas supply agreements; completing construction contracts; securing all necessary permits and approvals; obtaining financing and incentives; reaching a final investment decision; and other factors associated with the potential investment. See “Risk Factors” in the Annual Report.

Energía Costa Azul

We further ~~investment. However,~~discuss Sempra LNG & Midstream’s participation in potential LNG liquefaction development at Sempra Mexico’s Energía Costa Azul facility above in “Sempra Mexico – Energía Costa Azul LNG Terminal.”

Natural Gas Storage Assets

The future performance of our natural gas storage assets could be impacted by changes in the U.S. natural gas market, which could ~~also~~ lead to sustained diminished natural gas storage values.

The recorded value of our long-lived natural gas storage assets at June 30, 2017 is $1.5 billion. 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 further depressed asset values. ~~In addition, our~~Future investment in Bay Gas, Mississippi Hub and LA Storage will be dependent on market demand and estimates of long-term storage values. Our LA Storage development project ~~may be unable to attract cash flow commitments sufficient to support further investment or to extend its FERC~~ construction permit ~~beyond~~expired in June 2017 and future development will require approval of a new construction permit by the ~~current expiration date of June 2017.~~FERC. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is not currently contracted.

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 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 June 30, 2016 is $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.

RBS SEMPRA COMMODITIES

For a discussion about RBS 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' 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 77 percent of the project and ProLiance Transportation LLC owns the remaining 23 percent. The project's location provides access to several LNG facilities in the area.

~~Natural Gas Distribution Utilities~~

In April 2016, Sempra Natural Gas signed a definitive agreement to sell 100 percent of the outstanding equity of EnergySouth, the parent company of Mobile Gas and Willmut Gas. We expect to receive cash proceeds of approximately $323 million, subject to normal adjustments at closing, and the buyer will assume existing debt of approximately $67 million. In the second quarter of 2016, we reclassified the assets and liabilities of EnergySouth to held for sale. We expect to recognize an after-tax gain on the sale of approximately $70 million. The transaction is subject to customary regulatory approvals. In addition, the State of Missouri Public Service Commission (MPSC) in July 2016 opened an investigation into whether the transaction will have any effect on Missouri ratepayers and is subject to MPSC's jurisdiction. We expect the sale to close in 2016. We discuss this transaction in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

~~Cameron Liquefaction~~

~~Cameron LNG JV Three-Train Liquefaction Project.~~ We discuss the 2014 formation of the Cameron LNG JV, including the contribution of our share of equity to the joint venture through the contribution of the Cameron LNG, LLC regasification terminal in Hackberry, Louisiana, in Note 3 of the Notes to Consolidated Financial StatementsCommodities, see “Factors Influencing Future Performance” in the Annual ~~Report. The existing regasification terminal is capable of processing 1.5 Bcf of natural gas per day~~Report and it currently 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. As described below, we expect this agreement to be terminated during the first half of 2017 due to progress on the construction of the three-train liquefaction project. 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.

The current liquefaction project under construction, which will utilize Cameron LNG JV's existing facilities, is comprised of three liquefaction trains designed to a 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. 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. 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 exceeding our current expectations. 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.

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 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 the full nameplate capacity of the facility.

Sempra Natural Gas has agreements totaling 1.45 Bcf per day of firm natural gas transportation service to the Cameron LNG JV facilities on the Cameron Interstate Pipeline with ENGIE 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.

Construction on the current project began in the second half of 2014 under an engineering, procurement and construction (EPC) contract with a joint venture between CB&I Shaw Constructors, Inc., a wholly owned subsidiary of Chicago Bridge & Iron Company N.V., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation.

In August 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 JV liquefaction project. Concurrently, Sempra Energy entered into completion guarantees under which it has severally guaranteed 50.2 percent of the debt, or a maximum principal amount 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 JV 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 JV has 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 JV 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 JV liquefaction project that could adversely affect our future performance, see "Risk Factors" in the Annual Report.

Cameron LNG JV has a terminal services agreement with one customer that requires the customer to pay capacity reservation and usage fees to use its 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 JV's EPC contractor in October 2014, we expect this termination date to occur during the first half of 2017.

In December 2014, Cameron LNG JV 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. In April 2015, Cameron LNG JV filed the corresponding DOE Non-FTA permit application.

~~Proposed Additional Cameron Liquefaction Expansion.~~ Cameron LNG JV is also pursuing the permitting to expand the current configuration from the current three liquefaction trains under construction. The expansion project is expected to include up to two additional liquefaction trains, capable of increasing LNG production capacity by approximately 9 Mtpa to 10 Mtpa, and up to two additional full containment LNG storage tanks (one of which was permitted with the original three-train project). In February 2015, Cameron LNG JV filed the DOE FTA application and the pre-filing application at FERC for two additional trains and the one LNG storage tank. In May 2015, the joint venture filed a corresponding DOE Non-FTA permit application. In July 2015, Cameron LNG JV received approval of the DOE FTA application. In September 2015, Cameron LNG JV submitted the FERC application and was formally noticed by FERC in October 2015. In February 2016, Cameron LNG JV received the FERC environmental assessment and in May 2016, received the FERC permit. In July 2016, Cameron LNG JV received the authorization to export LNG to countries that do not have a free-trade agreement with the U.S.

Under the Cameron LNG JV financing agreements, expansion of the Cameron LNG JV 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. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all 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 currently does not want to invest additional capital in Cameron LNG JV with respect to the expansion. As a result, alternatives are being developed and negotiated with all partners to allocate the required equity, commitments and guarantees to the remaining three partners that are supportive of the development of the expansion and to secure the consent of all of the partners to allow the expansion to proceed. These activities have contributed to delays in developing firm pricing information and securing customer commitments. In light of these developments, the decision to reach a final investment decision could be delayed beyond the first half of 2017. Failure to obtain the unanimous consent of all of our partners to move forward on the expansion project or to obtain the necessary customer commitments could further delay this project.

The expansion of the Cameron LNG JV facilities beyond the first three trains is subject to a number of risks and uncertainties, including obtaining customer commitments, completing the required commercial agreements, amending the Cameron LNG JV agreement among the partners, securing all necessary permits, approvals and consents, obtaining financing, reaching a final investment decision among the Cameron LNG JV partners, and other factors associated with the potential investment. See "Risk Factors" in the Annual Report.

We discuss the deconsolidation of Cameron LNG, LLC, the Cameron LNG JV project financing obligations and Sempra Energy's completion guarantee further in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.

~~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 met with potential customers and determined there is an interest in long-term contracts for LNG supplies beginning in the 2021 to 2025 time frame.

~~Port Arthur.~~ In March 2015, Sempra Natural Gas submitted a request to the FERC to initiate the pre-filing review for the proposed Port Arthur LNG natural gas liquefaction and export facility in Port Arthur, Texas. The proposed project is designed to include two natural gas liquefaction trains with total export capability of approximately 10 Mtpa, or 1.4 Bcf per day; two 160,000-cubic-meter storage tanks; marine facilities for vessel berthing and loading; natural gas liquids and refrigerant storage; feed gas pre-treatment; truck loading and unloading areas; and combustion turbine generators for self-generation of electrical power.

In March 2015, Sempra Natural Gas also submitted a request to the FERC to initiate the pre-filing review for the proposed Port Arthur pipeline project. The proposed project consists of two 42-inch-diameter feed gas pipelines (7 and 27 miles long), two compressor stations, receipt meter stations, and other appurtenant facilities in Orange and Jefferson Counties, Texas, and Cameron Parish, Louisiana. The pipelines would provide up to 1.6 Bcf per day of capacity to the Port Arthur LNG facilities.

In March and June 2015, Sempra Natural Gas filed permit applications with the DOE for authorization to export the LNG produced from the proposed project to all current and future FTA and Non-FTA countries, respectively. In August 2015, Sempra Natural Gas received authorization from the DOE to export the LNG produced from the proposed project to all current and future FTA countries.

In February 2016, Sempra Natural Gas and Woodside Petroleum Ltd. (Woodside) entered into a project development agreement for the joint development of the proposed Port Arthur LNG liquefaction project. The agreement specifies how the parties will share costs, and establishes a framework for the parties to work jointly on permitting, design, engineering, commercial and marketing activities associated with developing the Port Arthur LNG liquefaction project.

Development of the Port Arthur LNG liquefaction project is subject to a number of risks and uncertainties, including completing the required commercial agreements, such as joint venture agreements, tolling capacity agreements or gas supply and LNG sales agreements; completing construction contracts; securing all necessary permits and approvals; obtaining financing and incentives; reaching a final investment decision; and other factors associated with the potential investment. See "Risk Factors" in the Annual Report.

~~Energía Costa Azul~~. We further 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."

~~LNG Liquefaction Development Costs~~

Total expenditures on LNG liquefaction development for the six months ended June 30, 2016 were $21 million, including capitalized costs of $11 million (pretax). After-tax LNG development costs expensed for the three months and six months ended June 30, 2016 were $2 million and $6 million, respectively. We expect to expense approximately $20 million to $25 million, after-tax, in 2016 for liquefaction and LNG integrated midstream development costs.

~~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 $67 million at June 30, 2016 reflects remaining distributions expected to be received from the partnership as it is dissolved. The amount of distributions, if any, may be impacted by the matters we discuss related to RBS Sempra Commodities under "Other Litigation" in Note 11 of the Notes to Condensed Consolidated Financial Statements herein. 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.

OTHER SEMPRA ENERGY MATTERS

We may be further impacted by depressed and rapidly changing economic conditions. These conditions may also affect our counterparties. Moreover, the dollar may fluctuate significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. We discuss "Concentration of Credit Risk" in Note 11 of the Notes to Condensed Consolidated Financial Statements herein, "Impact of Foreign Currency and Inflation Rates on Results of Operations" and "Foreign Currency and Inflation Rate Risk" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein and "Credit Risk," "Foreign Currency Rate Risk" and "Foreign Inflation Risk" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report. North American natural gas prices, when in decline, negatively affect profitability at Sempra Natural Gas. Also, a reduction in projected global demand for LNG 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 commodity prices,~~about Other Sempra Energy Matters, see ~~"Risk Factors"~~“Factors Influencing Future Performance” in the Annual Report.

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. 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 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in "Risk Factors" in the Annual Report.

LITIGATION

We describe legal proceedings ~~which~~that could adversely affect our future performance in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We view certain accounting policies as critical because their application is the most relevant, judgmental, and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss these accounting policies in ~~"Management's~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” in the Annual Report.

We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes.

NEW ACCOUNTING STANDARDS

We discuss the relevant pronouncements that have recently been issued or become effective and have had or may have an impact on our financial statements and/or disclosures in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We provide disclosure regarding derivative activity in Note 7 of the Notes to Condensed Consolidated Financial Statements herein. We discuss our market risk and risk policies in detail in ~~"Management's~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” herein and in the Annual Report.

INTEREST RATE RISK

The table below shows the nominal amount of long-term debt at June 30, ~~2016~~2017 and December 31, ~~2015:~~2016:



NOMINAL AMOUNT OF LONG-TERM DEBT(1)
(Dollars in millions)
	June 30, 2017						December 31, 2016
	Sempra Energy Consolidated		SDG&E		SoCalGas		Sempra Energy Consolidated		SDG&E		SoCalGas
Utility fixed-rate	$	7,600	$	4,591	$	3,009	$	7,218	$	4,209	$	3,009
Utility variable-rate	300		300		—		445		445		—
Non-utility fixed-rate	6,906		—		—		6,703		—		—
Non-utility variable-rate	728		—		—		719		—		—

NOMINAL AMOUNT OF LONG-TERM DEBT(1)
(Dollars in millions)
June 30, 2016 December 31, 2015
Sempra Energy Sempra Energy
Consolidated SDG&E SoCalGas Consolidated SDG&E SoCalGas
    Utility fixed-rate $ 7,236 $ 4,227 $ 3,009 $ 6,362 $ 3,849 $ 2,513
    Utility variable-rate 450 450 ― 455 455 ―
    Non-utility fixed-rate 5,972 ― ― 6,780 ― ―
    Non-utility variable-rate 157 ― ― 166 ― ―
(1) Excluding capital lease obligations, build-to-suit lease and interest rate swaps, and before reductions/increases for unamortized discount/premium and reductions for debt issuance costs.


(1)	Before the effects of acquisition-related fair value adjustments, interest rate swaps, reductions/increases for unamortized discount/premium and reduction for debt issuance costs, and excluding capital lease obligations and build-to-suit lease.

Interest rate risk sensitivity analysis measures interest rate risk by calculating the estimated changes in earnings that would result from a hypothetical change in market interest rates. If interest rates changed by ~~one~~ten percent on all of Sempra ~~Energy's~~Energy’s effective variable-rate, long-term debt at June 30, ~~2016,~~2017, the change in earnings over the next 12-month period ending June 30, ~~2017~~2018 would be $1$4 million ~~(after-tax), including $1 million (after-tax) at SDG&E.~~(after tax). These hypothetical changes in earnings are based on our long-term debt position after the effect of interest rate swaps.

~~We provide additional information about interest rate swap transactions in Note 7 of the Notes to Condensed Consolidated Financial Statements herein.~~

FOREIGN CURRENCY AND INFLATION RATE RISK

We discuss our foreign currency and inflation exposure ~~above~~ in ~~"Results~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations ~~– Changes in Revenues, Costs and Earnings~~ – Impact of Foreign Currency and Inflation Rates on Results of ~~Operations" herein. We also discuss our foreign currency exposure at our Mexican~~Operations” herein and ~~South American subsidiaries in "Management's Discussion and Analysis of Financial Condition and Results of Operations – Foreign Currency Rate Risk"~~ in the Annual Report. At June 30, ~~2016,~~2017, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2015. If IEnova's potential acquisition of the remaining 50-percent interest in GdC is completed, Sempra Mexico will be subject to additional foreign currency rate risk. However, similar to our current Mexican operations, GdC's functional currency is the U.S. dollar and its assets are covered by long-term, U.S. dollar-based contracts.2016.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra Energy, SDG&E and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the ~~Securities and Exchange Commission~~SEC and is accumulated and communicated to the management of each company, including each respective ~~Chief Executive Officer~~principal executive officer and ~~Chief Financial Officer,~~principal 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~~principal executive officers and ~~Chief Financial Officers~~principal 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 June 30, ~~2016,~~2017, the end of the period covered by this report. As discussed below, we excluded Ventika and IEnova Pipelines (formerly known as GdC) from our evaluation of changes in Sempra Energy’s disclosure controls and procedures, to the extent subsumed by Ventika’s and IEnova Pipelines’ internal control over financial reporting. Based on these evaluations, the ~~Chief Executive Officers~~principal executive officers and ~~Chief Financial Officers~~principal financial officers of Sempra Energy, SDG&E and SoCalGas concluded that their respective ~~company's~~company’s disclosure controls and procedures were effective at the reasonable assurance level.

INTERNAL CONTROL OVER FINANCIAL REPORTING

~~There~~Other than the changes which may be associated with the 2016 acquisitions described below (which did not impact SDG&E or SoCalGas), there have been no changes in the ~~companies'~~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'~~companies’ internal control over financial reporting.

As we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report, we acquired Ventika in December 2016 and the remaining 50-percent interest in IEnova Pipelines (formerly known as GdC) in September 2016. The carrying value of Ventika’s net assets was $278 million or 1.8 percent of Sempra Energy’s net assets at June 30, 2017. Ventika’s losses for the six months ended June 30, 2017 were $23 million or 3.3 percent of total Sempra Energy earnings for the six months ended June 30, 2017. The carrying value of IEnova Pipelines’ net assets was $2.3 billion or 14.9 percent of Sempra Energy’s net assets at June 30, 2017. IEnova Pipelines’ earnings for the six months ended June 30, 2017 were $20 million or 2.9 percent of total Sempra Energy earnings for the six months ended June 30, 2017. We are in the process of integrating Ventika and IEnova Pipelines. Our management is analyzing, evaluating and, where necessary, will implement changes in, Ventika’s and IEnova Pipelines’ controls and procedures. Due to the limited period of time since the acquisition dates, we have not had sufficient time to assess the internal controls of Ventika and IEnova Pipelines. Therefore, we excluded Ventika and IEnova Pipelines from our evaluation of disclosure controls and procedures above, to the extent subsumed by Ventika’s and IEnova Pipelines’ internal control over financial reporting. We intend to include Ventika and IEnova Pipelines in the overall assessment of, and report on, internal control over financial reporting as soon as practicable, but in no event later than one year from the respective acquisition dates.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters 1) described in Notes 9 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 13 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, or 2) referred to in ~~"Management's~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations"~~Operations” herein and in the Annual Report.

ITEM 1A. RISK FACTORS

When evaluating our company and its subsidiaries, we urge you to carefully consider the risks and other information in this Quarterly Report on Form 10-Q, including the factors discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Factors Influencing Future Performance,” as well as the risk factors disclosed in Item 1A. to Part I of our Annual Report. There have ~~not~~ been ~~any~~no material changes from the risk factors as previously disclosed in our Annual Report. Any of the risks and other information discussed in this Quarterly Report on Form ~~10-K for~~10-Q or any of the ~~year ended December 31, 2015.~~risks disclosed in Item 1A. to Part I of our Annual Report, as well as additional risks and uncertainties not currently known to us or that we currently deem immaterial, could materially and adversely affect our businesses, cash flows, results of operations, financial condition, prospects and/or the trading prices of our securities or those of our subsidiaries.

ITEM 6. EXHIBITS

The following exhibits relate to each registrant as indicated.



EXHIBIT 12 -- STATEMENTS RE: COMPUTATION OF RATIOS

		Sempra Energy
	~~Sempra Energy~~
	12.1		Sempra Energy Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
			~~Stock Dividends.~~

	San Diego Gas & Electric Company
	12.2		San Diego Gas & Electric Company Computation of Ratio of Earnings to Combined
			Fixed Charges and Preferred Stock Dividends.

	Southern California Gas Company
	12.3		Southern California Gas Company Computation of Ratio of Earnings to Combined Fixed
			Charges and Preferred Stock Dividends.


	EXHIBIT 31 -- SECTION 302 CERTIFICATIONS

		Sempra Energy
	~~Sempra Energy~~
	31.1		~~Statement~~ Certification of Sempra ~~Energy's Chief~~Energy’s Principal Executive Officer pursuant to Rules ~~13a-14 and 15d-14~~
			~~of the Securities Exchange Act of 1934.~~

	~~31.2~~		~~Statement of Sempra Energy's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14~~
			~~of the Securities Exchange Act of 1934.~~

	~~San Diego Gas & Electric Company~~
	~~31.3~~		~~Statement of San Diego Gas & Electric Company's Chief Executive Officer pursuant to Rules~~
			13a-14 and 15d-14 of the Securities Exchange Act of 1934.



~~31.4~~	~~Statement~~ 31.2 Certification of ~~San Diego Gas & Electric Company's Chief~~Sempra Energy’s Principal Financial Officer pursuant to Rules
		13a-14 and 15d-14 of the Securities Exchange Act of 1934.

	~~Southern California Gas Company~~

~~31.5~~San Diego Gas & Electric Company
	~~Statement~~ 31.3 Certification of ~~Southern California~~San Diego Gas ~~Company's Chief~~& Electric Company’s Principal Executive Officer pursuant to Rules
			13a-14 and 15d-14 of the Securities Exchange Act of 1934.

	~~31.6~~		~~Statement~~ 31.4 Certification of ~~Southern California~~San Diego Gas ~~Company's Chief~~& Electric Company’s Principal Financial Officer pursuant to Rules
			13a-14 and 15d-14 of the Securities Exchange Act of 1934.

Southern California Gas Company
31.5 Certification of Southern California Gas Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

			31.6 Certification of Southern California Gas Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

EXHIBIT 32 -- SECTION 906 CERTIFICATIONS

		Sempra Energy
	~~Sempra Energy~~
	32.1		~~Statement~~ Certification of Sempra ~~Energy's Chief~~Energy’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.

	32.2		~~Statement~~ Certification of Sempra ~~Energy's Chief~~Energy’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.

	San Diego Gas & Electric Company
	32.3		~~Statement~~ Certification of San Diego Gas & Electric ~~Company's Chief~~Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
			~~U.S.C. Sec. 1350.~~

	32.4		~~Statement~~ Certification of San Diego Gas & Electric ~~Company's Chief~~Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
			~~U.S.C. Sec. 1350.~~

	Southern California Gas Company
	32.5		~~Statement~~ Certification of Southern California Gas ~~Company's Chief~~Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
			~~U.S.C. Sec. 1350.~~

	32.6		~~Statement~~ Certification of Southern California Gas ~~Company's Chief~~Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
			~~U.S.C. Sec. 1350.~~


	EXHIBIT 101 -- INTERACTIVE DATA FILE

	Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
	~~101.INS~~		~~XBRL Instance Document~~

	101.SCH		XBRL Taxonomy Extension Schema Document

	101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

	101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

	101.LAB		XBRL Taxonomy Extension Label Linkbase Document



101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

~~SIGNATURES~~

Sempra Energy:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SEMPRA ENERGY, (Registrant)

Date: August 4, ~~2016~~2017	By: /s/ Trevor I. Mihalik
	Trevor I. Mihalik Senior Vice President, Controller and Chief Accounting Officer



San Diego Gas & Electric Company:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SAN DIEGO GAS & ELECTRIC COMPANY, (Registrant)

Date: August 4, ~~2016~~2017	By: /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer



Southern California Gas Company:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SOUTHERN CALIFORNIA GAS COMPANY, (Registrant)

Date: August 4, ~~2016~~2017	By: /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

124

SEMPRA ENERGY FORM 10-Q SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-Q SOUTHERN CALIFORNIA GAS COMPANY FORM 10-Q TABLE OF CONTENTS

		Page
Information Regarding Forward-Looking Statements		46

PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	68
Item 2.	~~Management's~~ Management’s Discussion and Analysis of Financial Condition and Results of Operations	8180
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	~~128~~121
Item 4.	Controls and Procedures	~~129~~122

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	~~130~~123
Item 1A.	Risk Factors	~~130~~123
Item 6.	Exhibits	~~130~~123

Signatures		~~132~~
		125

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
		June 30,		December 31,
		2016		2015(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	1,777	$	622
Accounts payable – trade			1,140		1,133
Accounts payable – other			101		142
Due to unconsolidated affiliates			8		14
Dividends and interest payable			314		303
Accrued compensation and benefits			289		423
Regulatory balancing accounts – overcollected			120		34
Current portion of long-term debt			907		907
Fixed-price contracts and other derivatives			54		56
Customer deposits			150		153
Reserve for Aliso Canyon costs			117		274
Liabilities held for sale			222		―
Other			481		551
Total current liabilities			5,680		4,612
Long-term debt ($298 and $303 at June 30, 2016 and December 31, 2015, respectively, related to VIE)			13,178		13,134

Deferred credits and other liabilities:
Customer advances for construction			152		149
Pension and other postretirement benefit plan obligations, net of plan assets			1,171		1,152
Deferred income taxes			3,071		3,157
Deferred investment tax credits			32		32
Regulatory liabilities arising from removal obligations			2,891		2,793
Asset retirement obligations			2,491		2,126
Fixed-price contracts and other derivatives			262		240
Deferred credits and other			1,384		1,176
Total deferred credits and other liabilities			11,454		10,825

Commitments and contingencies (Note 11)

Equity:
Preferred stock (50 million shares authorized; none issued)			―		―
Common stock (750 million shares authorized; 250 million and 248 million shares
outstanding at June 30, 2016 and December 31, 2015, respectively; no par value)			2,681		2,621
Retained earnings			9,952		9,994
Accumulated other comprehensive income (loss)			(852)		(806)
Total Sempra Energy shareholders' equity			11,781		11,809
Preferred stock of subsidiary			20		20
Other noncontrolling interests			762		750
Total equity			12,563		12,579
Total liabilities and equity		$	42,875	$	41,150
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.



SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	June 30, 2017			December 31, 2016(1)
	(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	1,826		$	1,779
Accounts payable – trade	1,054			1,346
Accounts payable – other	113			130
Due to unconsolidated affiliates	11			11
Dividends and interest payable	339			319
Accrued compensation and benefits	314			409
Regulatory balancing accounts – overcollected	204			122
Current portion of long-term debt	1,287			913
Fixed-price contracts and other derivatives	109			83
Customer deposits	158			158
Reserve for Aliso Canyon costs	63			53
Liabilities held for sale	47			47
Other	538			557
Total current liabilities	6,063			5,927

Long-term debt ($289 and $293 at June 30, 2017 and December 31, 2016, respectively, related to VIE)	15,000			14,429

Deferred credits and other liabilities:
Customer advances for construction	146			152
Pension and other postretirement benefit plan obligations, net of plan assets	1,240			1,208
Deferred income taxes	4,191			3,745
Deferred investment tax credits	27			28
Regulatory liabilities arising from removal obligations	2,746			2,697
Asset retirement obligations	2,469			2,431
Fixed-price contracts and other derivatives	330			405
Deferred credits and other	1,559			1,523
Total deferred credits and other liabilities	12,708			12,189

Commitments and contingencies (Note 11)

Equity:
Preferred stock (50 million shares authorized; none issued)	—			—
Common stock (750 million shares authorized; 251 million and 250 million shares outstanding at June 30, 2017 and December 31, 2016, respectively; no par value)	3,046			2,982
Retained earnings	11,004			10,717
Accumulated other comprehensive income (loss)	(718		)	(748		)
Total Sempra Energy shareholders’ equity	13,332			12,951
Preferred stock of subsidiary	20			20
Other noncontrolling interests	2,253			2,270
Total equity	15,605			15,241
Total liabilities and equity	$	49,376		$	47,786



Sempra Energy	~~249,801,432~~251,077,626 shares
San Diego Gas & Electric Company	Wholly owned by Enova Corporation, which is wholly owned by Sempra Energy
Southern California Gas Company	Wholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy



GLOSSARY


2016 GRC FD	final decision in the California Utilities’ 2016 General Rate Case
AFUDC	allowance for funds used during construction
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2016
AOCI	Accumulated Other Comprehensive Income (Loss)
ASU	Accounting Standards Update
Bay Gas	Bay Gas Storage Company, Ltd.
Bcf	billion cubic feet
Blade	Blade Energy Partners
CAISO	California Independent System Operator
California Utilities	San Diego Gas & Electric Company and Southern California Gas Company, collectively
Cameron LNG JV	Cameron LNG Holdings, LLC
CARB	California Air Resources Board
CCA	Community Choice Aggregation
CCM	cost of capital adjustment mechanism
CEC	California Energy Commission
CEQA	California Environmental Quality Act
CFCA	Core Fixed Cost Account
CFE	Comisión Federal de Electricidad (Federal Electricity Commission in Mexico)
Chilquinta Energía	Chilquinta Energía S.A. and its subsidiaries
COFECE	Comisión Federal de Competencia Económica (Mexican Competition Commission)
CPED	Consumer Protection and Enforcement Division
CPI	Consumer Price Index
CPUC	California Public Utilities Commission
CRE	Comisión Reguladora de Energía (Energy Regulatory Commission in Mexico)
CRR	congestion revenue right
DA	Direct Access
DEN	Ductos y Energéticos del Norte, S. de R.L. de C.V.
DOE	U.S. Department of Energy
DOGGR	California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources
DPH	Los Angeles County Department of Public Health
Ecogas	Ecogas México, S. de R.L. de C.V.
Edison	Southern California Edison Company
Eletrans	Eletrans S.A., Eletrans II S.A. and Eletrans III S.A., collectively
EnergySouth	EnergySouth Inc.
EPA	U.S. Environmental Protection Agency
EPC	engineering, procurement and construction
EPS	earnings per common share
ERRA	Energy Resource Recovery Account
FERC	Federal Energy Regulatory Commission
FTA	Free Trade Agreement
GCIM	Gas Cost Incentive Mechanism
GdC	Gasoductos de Chihuahua, S. de R.L. de C.V.
GHG	greenhouse gas
GRC	General Rate Case
HLBV	hypothetical liquidation at book value
HMRC	United Kingdom’s Revenue and Customs Department
IEnova	Infraestructura Energética Nova, S.A.B. de C.V.
IEnova Pipelines	IEnova Pipelines, S. de R.L. de C.V.
IMG	Infraestructura Marina del Golfo
IRS	Internal Revenue Service
ISFSI	independent spent fuel storage installation
JP Morgan	J.P. Morgan Chase & Co.
kV	kilovolt
LA Storage	LA Storage, LLC



GLOSSARY (CONTINUED)


LNG	liquefied natural gas
LPG	liquid petroleum gas
Luz del Sur	Luz del Sur S.A.A. and its subsidiaries
MHI	Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc., collectively
Mississippi Hub	Mississippi Hub, LLC
MMBtu	million British thermal units (of natural gas)
Mobile Gas	Mobile Gas Service Corporation
Mtpa	million tonnes per annum
MW	megawatt
MWh	megawatt hour
NDT	Nuclear Decommissioning Trusts
NEIL	Nuclear Electric Insurance Limited
NEPA	National Environmental Policy Act
NRC	Nuclear Regulatory Commission
OCI	Other Comprehensive Income (Loss)
OII	Order Instituting Investigation
O&M	operation and maintenance expense
OMEC	Otay Mesa Energy Center
OMEC LLC	Otay Mesa Energy Center LLC
ORA	CPUC Office of Ratepayer Advocates
Otay Mesa VIE	OMEC LLC VIE
PEMEX	Petróleos Mexicanos (Mexican state-owned oil company)
PG&E	Pacific Gas and Electric Company
PHMSA	Pipeline and Hazardous Materials Safety Administration
PP&E	property, plant and equipment
PPA	power purchase agreement
PSEP	Pipeline Safety Enhancement Plan
RAMP	Risk Assessment Mitigation Phase
RBS	The Royal Bank of Scotland plc
RBS SEE	RBS Sempra Energy Europe
RBS Sempra Commodities	RBS Sempra Commodities LLP
Rockies Express	Rockies Express Pipeline LLC
ROE	return on equity
RSA	restricted stock award
RSU	restricted stock unit
SB	Senate Bill
SCAQMD	South Coast Air Quality Management District
SDCA	United States District Court for the Southern District of California
SDG&E	San Diego Gas & Electric Company
SEC	United States Securities and Exchange Commission
SEDATU	Secretaría de Desarrollo Agrario, Territorial y Urbano (Mexican agency in charge of agriculture, land and urban development)
SFP	secondary financial protection
SoCalGas	Southern California Gas Company
SONGS	San Onofre Nuclear Generating Station
SONGS OII	CPUC’s Order Instituting Investigation into the SONGS Outage
TdM	Termoeléctrica de Mexicali
TransCanada	TransCanada Corporation
Tribunal	International Chamber of Commerce International Court of Arbitration Tribunal
TURN	The Utility Reform Network
U.S. GAAP	accounting principles generally accepted in the United States of America
Valero Energy	Valero Energy Corporation
VAT	value-added tax
Ventika	Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V., collectively
VIE	variable interest entity
Willmut Gas	Willmut Gas Company

§
▪	the resolution of civil and criminal litigation and regulatory ~~investigations;~~investigations;

§
▪	risks posed by ~~decisions and~~ actions of third parties who control the operations of our investments, ~~in which we do not have a controlling interest,~~ and risks that our partners or counterparties will be unable ~~(due to liquidity issues, bankruptcy or otherwise)~~ or unwilling to fulfill their contractual ~~commitments;~~commitments;

§
▪	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 and ~~employees;~~employees;

§	~~failure~~
▪	capital markets and economic conditions, including the availability of credit and the liquidity of our investments; and fluctuations in inflation, interest and currency exchange rates and our ability to ~~obtain regulatory approval for projects required to enhance safety and reliability;~~effectively hedge the risk of such fluctuations;

§
▪	changes in the tax code as a result of potential federal tax reform, such as the elimination of the deduction for interest and non-deductibility of all, or a portion of, the cost of imported materials, equipment and commodities;


▪	changes in foreign and domestic trade policies and laws, including border tariffs, revisions to favorable international trade agreements, and changes that make our exports less competitive or otherwise restrict our ability to export;


▪	the ability to win competitively bid infrastructure projects against a number of strong and aggressive competitors ~~willing to aggressively bid for these projects;~~;

§
▪	the impact on reliability of ~~San Diego Gas & Electric Company's (SDG&E)~~SDG&E’s electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources ~~and increased reliance on natural gas and natural gas transmission systems;~~;

§
▪	the impact on competitive customer rates ofdue to the growth in distributed and local power generation and the corresponding decrease in demand for power delivered through SDG~~&E's~~&E’s electric transmission and distribution ~~system;~~system and from possible



SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Three months ended June 30,						Six months ended June 30,
	2017			2016(1)			2017			2016(1)
	(unaudited)
REVENUES
Utilities	$	2,197		$	1,994		$	4,895		$	4,436
Energy-related businesses	336			162			669			342
Total revenues	2,533			2,156			5,564			4,778

EXPENSES AND OTHER INCOME
Utilities:
Cost of electric fuel and purchased power	(553		)	(561		)	(1,080		)	(1,076		)
Cost of natural gas	(228		)	(183		)	(713		)	(494		)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power	(62		)	(62		)	(129		)	(118		)
Other cost of sales	38			(226		)	16			(261		)
Operation and maintenance	(731		)	(706		)	(1,445		)	(1,406		)
Depreciation and amortization	(368		)	(314		)	(728		)	(642		)
Franchise fees and other taxes	(101		)	(96		)	(211		)	(207		)
Impairment losses	(71		)	(21		)	(71		)	(22		)
Equity earnings (losses), before income tax	18			14			21			(8		)
Other income, net	91			23			260			72
Interest income	8			6			14			12
Interest expense	(159		)	(142		)	(328		)	(285		)
Income (loss) before income taxes and equity earnings (losses) of certain unconsolidated subsidiaries	415			(112		)	1,170			343
Income tax (expense) benefit	(167		)	106			(462		)	(2		)
Equity earnings (losses), net of income tax	—			33			(8		)	50
Net income	248			27			700			391
Losses (earnings) attributable to noncontrolling interests	12			(10		)	1			(21		)
Preferred dividends of subsidiary	(1		)	(1		)	(1		)	(1		)
Earnings	$	259		$	16		$	700		$	369


Basic earnings per common share	$	1.03		$	0.06		$	2.79		$	1.48
Weighted-average number of shares outstanding, basic (thousands)	251,447			250,096			251,290			249,915

Diluted earnings per common share	$	1.03		$	0.06		$	2.77		$	1.47
Weighted-average number of shares outstanding, diluted (thousands)	252,822			252,036			252,609			251,775

Dividends declared per share of common stock	$	0.83		$	0.75		$	1.65		$	1.51

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Sempra Energy shareholders' equity
	Pretax		Income tax		Net-of-tax		Noncontrolling
	amount		benefit (expense)		amount		interests (after-tax)		Total
	Three months ended June 30, 2016 and 2015
	(unaudited)
2016:
Net (loss) income	$	(89)	$	106	$	17	$	10	$	27
Other comprehensive income (loss):
Foreign currency translation adjustments		11		―		11		―		11
Financial instruments		(78)		35		(43)		1		(42)
Pension and other postretirement benefits		2		(1)		1		―		1
Total other comprehensive (loss) income		(65)		34		(31)		1		(30)
Comprehensive (loss) income		(154)		140		(14)		11		(3)
Preferred dividends of subsidiary		(1)		―		(1)		―		(1)
Comprehensive (loss) income, after preferred
dividends of subsidiary	$	(155)	$	140	$	(15)	$	11	$	(4)
2015:
Net income	$	394	$	(98)	$	296	$	24	$	320
Other comprehensive income (loss):
Foreign currency translation adjustments		(43)		―		(43)		(5)		(48)
Financial instruments		95		(36)		59		6		65
Pension and other postretirement benefits		2		(1)		1		―		1
Total other comprehensive income		54		(37)		17		1		18
Comprehensive income		448		(135)		313		25		338
Preferred dividends of subsidiary		(1)		―		(1)		―		(1)
Comprehensive income, after preferred
dividends of subsidiary	$	447	$	(135)	$	312	$	25	$	337

		Six months ended June 30, 2016 and 2015
		(unaudited)
SEMPRA ENERGY												SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)												CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)												(Dollars in millions)
												Sempra Energy shareholders’ equity
												Pretax amount			Income tax (expense) benefit			Net-of-tax amount			Noncontrolling interests (after-tax)			Total
												Three months ended June 30, 2017 and 2016
												(unaudited)
2017:
Net income (loss)												$	427		$	(167	)	$	260		$	(12	)	$	248
Other comprehensive income (loss):
Foreign currency translation adjustments												3			—			3			2			5
Financial instruments												(43		)	17			(26		)	(4		)	(30		)
Pension and other postretirement benefits												2			(1		)	1			—			1
Total other comprehensive loss												(38		)	16			(22		)	(2		)	(24		)
Comprehensive income (loss)												389			(151		)	238			(14		)	224
Preferred dividends of subsidiary												(1		)	—			(1		)	—			(1		)
Comprehensive income (loss), after preferred
dividends of subsidiary												$	388		$	(151	)	$	237		$	(14	)	$	223
2016:	2016:
Net income		$	372	$	(36)	$	336	$	21	$	357
Net (loss) income												$	(89	)	$	106		$	17		$	10		$	27
Other comprehensive income (loss):	Other comprehensive income (loss):
Foreign currency translation adjustments	Foreign currency translation adjustments		79		―		79		5		84	11			—			11			—			11
Financial instruments	Financial instruments		(237)		110		(127)		(4)		(131)	(78		)	35			(43		)	1			(42		)
Pension and other postretirement benefits	Pension and other postretirement benefits		4		(2)		2		―		2	2			(1		)	1			—			1
Total other comprehensive (loss) income	Total other comprehensive (loss) income		(154)		108		(46)		1		(45)	(65		)	34			(31		)	1			(30		)
Comprehensive income			218		72		290		22		312
Comprehensive (loss) income												(154		)	140			(14		)	11			(3		)
Preferred dividends of subsidiary	Preferred dividends of subsidiary		(1)		―		(1)		―		(1)	(1		)	—			(1		)	—			(1		)
Comprehensive income, after preferred
Comprehensive (loss) income, after preferred
dividends of subsidiary	dividends of subsidiary	$	217	$	72	$	289	$	22	$	311	$	(155	)	$	140		$	(15	)	$	11		$	(4	)
2015:
Net income		$	994	$	(261)	$	733	$	45	$	778
Other comprehensive income (loss):
Foreign currency translation adjustments			(105)		―		(105)		(13)		(118)
Financial instruments			6		(2)		4		1		5
Pension and other postretirement benefits			4		(2)		2		―		2
Total other comprehensive loss			(95)		(4)		(99)		(12)		(111)
Comprehensive income			899		(265)		634		33		667
Preferred dividends of subsidiary			(1)		―		(1)		―		(1)
Comprehensive income, after preferred
dividends of subsidiary		$	898	$	(265)	$	633	$	33	$	666
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		June 30,		December 31,
		2016		2015(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	616	$	403
Restricted cash			17		27
Accounts receivable – trade, net			994		1,283
Accounts receivable – other			140		190
Due from unconsolidated affiliates			6		6
Income taxes receivable			36		30
Inventories			270		298
Regulatory balancing accounts – undercollected			336		307
Fixed-price contracts and other derivatives			65		80
Assets held for sale			654		―
Other			207		267
Total current assets			3,341		2,891

Other assets:
Restricted cash			18		20
Due from unconsolidated affiliates			192		186
Regulatory assets			3,353		3,273
Nuclear decommissioning trusts			1,103		1,063
Investments			2,267		2,905
Goodwill			786		819
Other intangible assets			399		404
Dedicated assets in support of certain benefit plans			436		464
Insurance receivable for Aliso Canyon costs			679		325
Sundry			806		761
Total other assets			10,039		10,220

Property, plant and equipment:
Property, plant and equipment			39,756		38,200
Less accumulated depreciation and amortization			(10,261)		(10,161)
Property, plant and equipment, net ($372 and $383 at June 30, 2016 and December 31, 2015, respectively, related to VIE)			29,495		28,039
Total assets		$	42,875	$	41,150
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Six months ended June 30,
	2016		2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	357	$	778
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		642		610
Deferred income taxes and investment tax credits		(42)		203
Gain on sale of assets		―		(62)
Plant closure adjustment		―		(21)
Equity earnings		(42)		(83)
Fixed-price contracts and other derivatives		41		―
Other		33		(8)
Net change in other working capital components		167		(116)
Insurance receivable for Aliso Canyon costs		(354)		―
Changes in other assets		(67)		(89)
Changes in other liabilities		147		7
Net cash provided by operating activities		882		1,219

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(2,006)		(1,466)
Expenditures for investments and acquisition of business		(46)		(161)
Proceeds from sale of assets		443		347
Distributions from investments		12		9
Purchases of nuclear decommissioning and other trust assets		(206)		(229)
Proceeds from sales by nuclear decommissioning and other trusts		204		221
Increases in restricted cash		(32)		(34)
Decreases in restricted cash		44		49
Advances to unconsolidated affiliates		(9)		(20)
Repayments of advances to unconsolidated affiliates		9		74
Other		(6)		9
Net cash used in investing activities		(1,593)		(1,201)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(335)		(308)
Preferred dividends paid by subsidiary		(1)		(1)
Issuances of common stock		29		31
Repurchases of common stock		(54)		(66)
Issuances of debt (maturities greater than 90 days)		1,384		1,547
Payments on debt (maturities greater than 90 days)		(986)		(846)
Increase (decrease) in short-term debt, net		865		(339)
Net distributions to noncontrolling interests		(10)		(14)
Tax benefit related to share-based compensation		34		52
Other		(10)		(6)
Net cash provided by financing activities		916		50

Effect of exchange rate changes on cash and cash equivalents		8		(2)

Increase in cash and cash equivalents		213		66
Cash and cash equivalents, January 1		403		570
Cash and cash equivalents, June 30	$	616	$	636
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(unaudited)

Operating revenues	$	617	$	780	$	1,650	$	1,828
Operating expenses
Cost of natural gas		147		196		400		463
Operation and maintenance		339		346		666		660
Depreciation and amortization		112		113		234		226
Franchise fees and other taxes		30		31		67		65
Total operating expenses		628		686		1,367		1,414
Operating (loss) income		(11)		94		283		414
Other income, net		6		9		16		17
Interest income		―		3		―		3
Interest expense		(24)		(19)		(46)		(38)
(Loss) income before income taxes		(29)		87		253		396
Income tax benefit (expense)		29		(16)		(58)		(111)
Net income		―		71		195		285
Preferred dividend requirements		(1)		(1)		(1)		(1)
(Losses) earnings attributable to common shares	$	(1)	$	70	$	194	$	284
See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pretax		Income tax		Net-of-tax
	amount		benefit (expense)		amount
	Three months ended June 30, 2016 and 2015
	(unaudited)
2016:
Net loss/Comprehensive loss	$	(29)	$	29	$	―
2015:
Net income/Comprehensive income	$	87	$	(16)	$	71

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS
(Dollars in millions)
		June 30,		December 31,
		2016		2015(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	211	$	58
Accounts receivable – trade, net			337		635
Accounts receivable – other			82		99
Due from unconsolidated affiliates			7		48
Income taxes receivable			6		―
Inventories			44		79
Regulatory assets			8		7
Other			35		40
Total current assets			730		966

Other assets:
Regulatory assets arising from pension obligations			732		699
Other regulatory assets			717		636
Insurance receivable for Aliso Canyon costs			679		325
Sundry			252		207
Total other assets			2,380		1,867

Property, plant and equipment:
Property, plant and equipment			14,910		14,171
Less accumulated depreciation and amortization			(4,934)		(4,900)
Property, plant and equipment, net			9,976		9,271
Total assets		$	13,086	$	12,104
(1)	Derived from audited financial statements.
See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
		June 30,		December 31,
		2016		2015(1)
		(unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable – trade		$	277	$	422
Accounts payable – other			63		76
Due to unconsolidated affiliate			25		―
Income taxes payable			―		3
Accrued compensation and benefits			123		160
Regulatory balancing accounts – net overcollected			120		34
Current portion of long-term debt			1		9
Customer deposits			72		76
Reserve for Aliso Canyon costs			117		274
Other			181		184
Total current liabilities			979		1,238
Long-term debt			2,981		2,481
Deferred credits and other liabilities:
Customer advances for construction			102		103
Pension obligation, net of plan assets			749		716
Deferred income taxes			1,637		1,532
Deferred investment tax credits			12		14
Regulatory liabilities arising from removal obligations			1,149		1,145
Asset retirement obligations			1,697		1,354
Deferred credits and other			437		372
Total deferred credits and other liabilities			5,783		5,236

Commitments and contingencies (Note 11)

Shareholders' equity:
Preferred stock			22		22
Common stock (100 million shares authorized; 91 million shares outstanding;
no par value)			866		866
Retained earnings			2,474		2,280
Accumulated other comprehensive income (loss)			(19)		(19)
Total shareholders' equity			3,343		3,149
Total liabilities and shareholders' equity		$	13,086	$	12,104
(1)	Derived from audited financial statements.
See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Six months ended June 30,
	2016		2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	195	$	285
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		234		226
Deferred income taxes and investment tax credits		32		76
Other		7		(15)
Net change in other working capital components		190		(58)
Insurance receivable for Aliso Canyon costs		(354)		―
Changes in other assets		(54)		(30)
Changes in other liabilities		12		(1)
Net cash provided by operating activities		262		483

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(650)		(603)
Decrease (increase) in loans to affiliate, net		50		(279)
Net cash used in investing activities		(600)		(882)

CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends paid		(1)		(1)
Issuances of long-term debt		499		599
Payments on long-term debt		(3)		―
Decrease in short-term debt, net		―		(50)
Other		(4)		(3)
Net cash provided by financing activities		491		545

Increase in cash and cash equivalents		153		146
Cash and cash equivalents, January 1		58		85
Cash and cash equivalents, June 30	$	211	$	231

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	43	$	36
Income tax payments, net		35		14

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY
Accrued capital expenditures	$	140	$	143
See Notes to Condensed Financial Statements.


▪	Sempra Infrastructure, which includes our Sempra ~~South American Utilities and Sempra~~ Mexico, ~~reportable segments; and~~



IMPACT FROM ADOPTION OF ASU 2016-09
(Dollars in millions, except per share amounts)
	Six months ended June 30, 2016
	As previously reported			Effect of adoption		As adjusted
Sempra Energy Consolidated:
Condensed Consolidated Statement of Operations:
Income tax expense	$	(36	)	$	34	$	(2	)
Net income	357			34		391
Earnings	335			34		369

Basic earnings per common share	$	1.34		$	0.14	$	1.48
Diluted earnings per common share	$	1.33		$	0.14	$	1.47
Weighted-average number of shares outstanding, diluted (thousands)(1)	251,686			89		251,775

Condensed Consolidated Statement of Comprehensive Income (Loss):
Net income	$	357		$	34	$	391
Comprehensive income	312			34		346
Comprehensive income, after preferred dividends of subsidiary	311			34		345




Condensed Consolidated Statement of Cash Flows:
Cash flows from operating activities:
Net income	$	357		$	34		$	391
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes and investment tax credits	(42		)	(34		)	(76		)
Other(2)	11			34			45
Net cash provided by operating activities	882			34			916
Cash flows from financing activities:
Tax benefit related to share-based compensation	34			(34		)	—
Net cash provided by financing activities	916			(34		)	882
SDG&E:
Condensed Consolidated Statement of Operations:
Income tax expense	$	(120	)	$	7		$	(113	)
Net income	217			7			224
Earnings attributable to common shares	229			7			236

Condensed Consolidated Statement of Comprehensive Income (Loss):
Net income	$	217		$	7		$	224
Comprehensive income	216			7			223

Condensed Consolidated Statement of Cash Flows:
Cash flows from operating activities:
Net income	$	217		$	7		$	224
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes and investment tax credits	26			(7		)	19
SoCalGas:
Condensed Statement of Operations:
Income tax expense	$	(58	)	$	4		$	(54	)
Net income	195			4			199
Earnings attributable to common shares	194			4			198

Condensed Statement of Comprehensive Income (Loss):
Net income/Comprehensive income	$	195		$	4		$	199

Condensed Statement of Cash Flows:
Cash flows from operating activities:
Net income	$	195		$	4		$	199
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes and investment tax credits	32			(4		)	28


(1)	For the three months ended June 30, 2016, we previously reported 251,938 shares; the effect of adoption of the ASU resulted in an “as adjusted” 252,036 shares.


(2)	For the six months ended June 30, 2016, we previously reported $33 million in Other, which was reduced to $11 million, as $22 million was reclassified to Impairment Losses to conform to current year presentation.

ASSETS HELD FOR SALE AT JUNE 30, 2016
(Dollars in millions)
	Termoeléctrica de Mexicali		EnergySouth Inc.
	Termoeléctrica de Mexicali		EnergySouth Inc.
Cash and cash equivalents	$	1	$	1
Inventories		8		3
Other current assets		21		13
Regulatory assets		―		12
Goodwill		―		72
Other assets		17		53
Property, plant and equipment, net		250		203
Total assets held for sale	$	297	$	357

Accounts payable	$	1	$	9
Other current liabilities		6		12
Long-term debt		―		67
Deferred income taxes		13		38
Regulatory liabilities		―		22
Asset retirement obligations		4		12
Other liabilities		19		19
Total liabilities held for sale	$	43	$	179

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
		Amounts reclassified
Details about accumulated		from accumulated other				Affected line item on Condensed
other comprehensive income (loss) components		comprehensive income (loss)				Consolidated Statements of Operations
		Three months ended June 30,
		2016		2015
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments		$	3	$	3	Interest Expense
Interest rate instruments			2		3	Equity Earnings (Losses), Before Income Tax
Interest rate and foreign exchange instruments			5		―	Equity Earnings, Net of Income Tax
Total before income tax			10		6
			(1)		(1)	Income Tax Expense
Net of income tax			9		5
			(4)		(3)	Earnings Attributable to Noncontrolling Interests
		$	5	$	2

Pension and other postretirement benefits:
Amortization of actuarial loss		$	2	$	2	See note (1) below
			(1)		(1)	Income Tax Expense
Net of income tax		$	1	$	1

Total reclassifications for the period, net of tax		$	6	$	3
SDG&E:
Financial instruments:
Interest rate instruments		$	3	$	3	Interest Expense
			(3)		(3)	Losses (Earnings) Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax		$	―	$	―
(1)	Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
		Amount reclassified
Details about accumulated		from accumulated other				Affected line item on Condensed
other comprehensive income (loss) components		comprehensive income (loss)				Consolidated Statements of Operations
		Six months ended June 30,
		2016		2015
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments		$	7	$	9	Interest Expense
Interest rate instruments			5		6	Equity Earnings (Losses), Before Income Tax
Interest rate and foreign exchange instruments			6		―	Equity Earnings, Net of Income Tax
Commodity contracts not subject to
	rate recovery		(7)		(7)	Revenues: Energy-Related Businesses
Total before income tax			11		8
			(1)		―	Income Tax Expense
Net of income tax			10		8
			(7)		(7)	Earnings Attributable to Noncontrolling Interests
		$	3	$	1

Pension and other postretirement benefits:
Amortization of actuarial loss		$	4	$	4	See note (1) below
			(2)		(2)	Income Tax Expense
Net of income tax		$	2	$	2

Total reclassifications for the period, net of tax		$	5	$	3
SDG&E:
Financial instruments:
Interest rate instruments		$	6	$	6	Interest Expense
			(6)		(6)	Losses (Earnings) Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax		$	―	$	―
(1)	Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).