REGULATORY MATTERS

12 Months Ended

Dec. 31, 2016

Regulated Operations [Abstract]

Regulatory Matters

SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)

SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which ceased operations in June 2013. On June 6, 2013, after an extended outage beginning in 2012, Southern California Edison Company (Edison), the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the Nuclear Regulatory Commission (NRC) to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.

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

SONGS 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 concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. These issues with the steam generators ultimately resulted in Edison’s decision to permanently retire SONGS.

The replacement steam generators were designed and provided by Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013, Edison instituted arbitration proceedings against MHI seeking damages as well. SDG&E is participating in the arbitration as a claimant and respondent. The arbitration hearing concluded in April 2016, and a decision could be reached in the first half of 2017. We discuss these proceedings in Note 15.

Settlement Agreement to Resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS Outage (SONGS OII) 

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.

In November 2014, the CPUC issued a final decision approving an Amended and Restated Settlement Agreement (Amended Settlement Agreement) in the SONGS OII proceeding executed by SDG&E along with Edison, The Utility Reform Network (TURN), the CPUC Office of Ratepayer Advocates (ORA) and two other intervenors who joined an earlier settlement agreement. The Amended Settlement Agreement does not affect 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 addressed in the final decision) or proceedings addressing decommissioning activities and costs.

The Amended Settlement Agreement provides for various disallowances, refunds and rate recoveries, including authorizing SDG&E to recover in rates its remaining investment in SONGS, including base plant and construction work in progress, but excluding its investment in the SGRP, generally over a ten-year period commencing February 1, 2012, together with a return on investment at a reduced rate equal to:

▪ SDG&E’s weighted average return on debt, plus

▪ 50 percent of SDG&E’s weighted average return on preferred stock, as authorized in the CPUC’s Cost of Capital (discussed in Note 14) proceeding then in effect (collectively, SONGS rate of return or SONGS ROR)

This has resulted in a SONGS ROR of 2.35 percent for the period from January 1, 2013 through December 31, 2016, which rate will remain in effect through 2017. The SONGS ROR for future periods will fluctuate based on SDG&E’s authorized weighted average returns on debt and preferred stock in effect for those future periods.

In April 2015, a petition for modification 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.

In August 2015, ORA, also a party to the Amended Settlement Agreement, filed a petition for modification 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 disclosures concerning Edison ex parte communications with the CPUC.

In May 2016, the CPUC issued a 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 the CPUC in June 2016 on the Amended Settlement Agreement and the status of its implementation, and filed separate legal briefs in July 2016 asserting that the Amended Settlement Agreement is reasonable and in the public interest.

In December 2016, the CPUC issued a 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 CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated. The ruling directs the parties to consider various issues, including the division between ratepayers and shareholders of any future MHI arbitration award. If no agreement is reached by April 28, 2017, the CPUC will consider other options including entertaining additional testimony, hearings and briefs.

There is no assurance that the Amended Settlement Agreement will not be renegotiated, modified or set aside as a result of these proceedings, which could result in a substantial reduction in our expected recovery and 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, 2016, 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 based on the CPUC’s approval in March 2015 of SDG&E’s compliance filing and establishment of the SONGS settlement revenue requirement, and a reduction in the after-tax loss of $2 million based on a settlement with Nuclear Electric Insurance Limited in the fourth quarter of 2015, as we discuss below. In 2014, SDG&E recorded a $21 million after-tax increase to the loss, including $12 million based on a compliance filing regarding SDG&E’s annual revenue requirement and the timing of refunds to ratepayers.

The remaining regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is $183 million ($31 million current and $152 million long-term) at December 31, 2016. The amortization period prescribed for the regulatory asset is 10 years, which commenced in January 2015 following the CPUC’s final decision approving the Amended Settlement Agreement in November 2014.

A decision in the MHI arbitration could be reached in the first half of 2017. Under the Amended Settlement Agreement, SDG&E’s 20-percent share of any proceeds from the MHI arbitration, net of legal costs, must be equally divided between SDG&E shareholders and ratepayers. As we discuss above, there is no assurance that the Amended Settlement Agreement will not be modified as it pertains to the MHI arbitration proceedings by the ongoing CPUC OII proceeding. Accordingly, determination of the shareholder component of MHI arbitration proceeds, if any, may be suspended until resolution of the SONGS OII proceeding.

Settlement with Nuclear Electric Insurance Limited (NEIL)

As we discuss in Note 15, 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 was $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 the Energy Resource Recovery Account. 

NRC Proceedings 

In December 2013, Edison received a final NRC Inspection Report that identified a violation for the failure to verify the adequacy of the thermal-hydraulic and flow-induced vibration design of the Unit 3 replacement steam generator. In January 2014, Edison provided a response to the NRC Inspection Report stating that MHI, as contracted by Edison to prepare the SONGS replacement steam generator design, was the party responsible for validating the design of the steam generators. 

In addition, the NRC issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of the replacement steam generators. 

Because SONGS has ceased operation, NRC inspection oversight of SONGS will now be continued through the NRC’s Decommissioning Power Reactor Inspection Program to verify that decommissioning activities are being conducted safely, that spent fuel is safely stored onsite or transferred to another licensed location, and that the site operations and licensee termination activities conform to applicable regulatory requirements, licensee commitments and management controls.

Nuclear Decommissioning and Funding 

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison has begun the decommissioning phase of the plant. The process of decommissioning a nuclear power plant is governed by the regulations of various governmental and other agencies, including but not limited to, those of the NRC, the U.S. Department of the Navy (the land owner) and the CPUC. The NRC regulations generally categorize the decommissioning activities into three phases: initial activities, major decommissioning and storage activities, and license termination. Initial activities include providing notice of permanent cessation of operations and notice of permanent removal of fuel from the reactor vessels, which were provided by Edison in 2013. Within two years after the cessation of operations, the licensee (Edison) must submit a post-shutdown decommissioning activities report, an irradiated fuel management plan and a site-specific decommissioning cost estimate. Edison submitted each of these items to the NRC in September 2014. 

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 general contractor to complete the dismantlement of SONGS. The majority of the dismantlement work is expected to take 10 years. SDG&E is responsible for 20 percent of the total contract price.

In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trusts (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be done once Units 2 and 3 are dismantled. At December 31, 2016, the fair value of SDG&E’s NDT assets was $1.0 billion. Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3.

In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 of $4.4 billion (in 2014 dollars), 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. To the extent actual expenses are consistent with forecasts, this arrangement will generally result in the utilization of nuclear decommissioning trust funds to support decommissioning, reducing the need to temporarily fund such costs with working capital. Certain spent fuel management costs, described below, continue to be temporarily funded with working capital. 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 funds for SONGS decommissioning costs of up to$218 millionfor 2013 through 2016. The$218 million includes $37 million related to spent fuel management costs. In April 2016, Edison, acting for itself and on behalf of SDG&E, entered into a settlement agreement with the U.S. Department of Energy (DOE) to resolve the claims against the DOE related to the spent fuel management costs incurred through 2013. The settlement agreement sets forth an administrative procedure for the submission of claims for costs incurred from 2014 through 2016, which provides for arbitration if the settlement process is unsuccessful. Edison, acting for itself and SDG&E, submitted claims for spent fuel management costs incurred during 2014 and 2015 in September 2016. Claims for spent fuel management costs incurred during 2016 must be submitted by September 30, 2017. SDG&E is not guaranteed recovery of its claims for 2014-2016; however, SDG&E anticipates that the claims for costs incurred in 2014 and 2015 will be resolved during 2017, and the claims for costs incurred in 2016 will be resolved during 2018.

In December 2016, the IRS and the U.S. Department of the Treasury issued proposed regulations that 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 management installations are included in the definition of “nuclear decommissioning costs.” The proposed regulations will be 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 working with outside counsel to clarify with the IRS some of the provisions in the proposed regulations so as to confirm that the proposed regulations will allow SDG&E to access the trust funds for reimbursement or payment of the spent fuel management costs that were or will be incurred in 2016 and subsequent years.

In December 2016, SDG&E filed an advice letter with the CPUC requesting authority to withdraw up to $84 million for 2017 SONGS Units 2 and 3 costs (forecasted). The CPUC approved SDG&E’s request in February 2017, which allows SDG&E to withdraw from the funds as decommissioning costs are incurred.

Nuclear Decommissioning Trusts

The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are shown on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from Removal Obligations. 

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 10.

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At December 31, 2016:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies(1)	$	52	$	—	$	—		$	52
Municipal bonds(2)	203		4		(1		)	206
Other securities(3)	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
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 2017-2047.

(2) Maturity dates are 2017-2115.

(3) Maturity dates are 2017-2111.

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)
	Years ended December 31,
	2016			2015			2014
Proceeds from sales(1)	$	1,134		$	577		$	601
Gross realized gains	111			29			11
Gross realized losses	(29		)	(15		)	(11		)

(1) Excludes securities that are held to maturity.

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification. In 2016, sale and purchase activities in our NDT increased significantly compared to prior years as a result of a change to our asset allocation 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, as we are in the decommissioning stage at the plant.

Asset Retirement Obligation and Spent Nuclear Fuel

SDG&E’s asset retirement obligation related to decommissioning costs for the SONGS units was $637 million at December 31, 2016. That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete the decommissioning of Unit 1, which is substantially complete. The asset retirement obligation at December 31, 2016 is based on a CPUC-approved cost study prepared in 2014 that reflects the acceleration of the start of decommissioning Units 2 and 3 as a result of the early closure of the plant. An updated cost study for Unit 1 is pending approval by the CPUC. SDG&E’s share of total decommissioning costs in 2016 dollars is approximately $989 million. 

Spent nuclear fuel from SONGS is stored on-site in an Independent Spent Fuel Storage Installation (ISFSI) licensed by the NRC or temporarily in spent fuel pools. The ISFSI will be decommissioned after a spent fuel storage facility becomes available and the DOE removes the spent fuel from the site. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.

REGULATORY MATTERS

REGULATORY BALANCING ACCOUNTS

SDG&E and SoCalGas maintain regulatory balancing accounts. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, including commodity costs. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. Balancing account treatment eliminates the impact on earnings from variances in the covered costs from authorized amounts. Absent balancing account treatment, variations in the cost of fuel supply and certain operating and maintenance costs from amounts approved by the CPUC would increase volatility in utility earnings.

The following table summarizes our regulatory balancing accounts at December 31.

SUMMARY OF REGULATORY BALANCING ACCOUNTS AT DECEMBER 31
(Dollars in millions)
	Sempra Energy Consolidated						SDG&E						SoCalGas
	2016			2015			2016			2015			2016			2015
Current:
Overcollected	$	(804	)	$	(789	)	$	(301	)	$	(345	)	$	(503	)	$	(444	)
Undercollected	941			1,062			560			652			381			410
Net current receivable (payable)(1)	137			273			259			307			(122		)	(34		)
Noncurrent:
Undercollected(2)	85			215			—			—			85			215
Net noncurrent receivable (payable)(1)	85			215			—			—			85			215
Total net receivable (payable)	$	222		$	488		$	259		$	307		$	(37	)	$	181

(1) At both December 31, 2016 and 2015, the net receivable at SDG&E and the net payable at SoCalGas are shown separately on Sempra Energy’s Consolidated Balance Sheets.

(2) Long-term undercollected balance is included in Regulatory Assets (long-term) on Sempra Energy’s Consolidated Balance Sheets and in Other Regulatory Assets (long-term) on SoCalGas’ Consolidated Balance Sheets.

REGULATORY ASSETS AND LIABILITIES

We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below.

REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	December 31,
	2016			2015
SDG&E:
Fixed-price contracts and other derivatives	$	141		$	99
Costs related to SONGS plant closure(1)	183			257
Costs related to wildfire litigation	353			362
Deferred taxes recoverable in rates	1,014			914
Pension and other postretirement benefit plan obligations	210			180
Removal obligations(2)	(1,725		)	(1,629		)
Unamortized loss on reacquired debt	12			12
Environmental costs	48			16
Legacy meters(1)	16			32
Sunrise Powerlink fire mitigation	118			117
Other	(2		)	9
Total SDG&E	368			369
SoCalGas:
Pension and other postretirement benefit plan obligations	563			629
Employee benefit costs	45			51
Removal obligations(2)	(972		)	(1,145		)
Deferred taxes recoverable in rates	417			330
Unamortized loss on reacquired debt	10			11
Environmental costs	22			22
Workers’ compensation	10			13
Other	8			—
Total SoCalGas	103			(89		)
Other Sempra Energy:
Sempra LNG & Midstream	—			(7		)
Sempra Mexico	71			33
Total Other Sempra Energy	71			26
Total Sempra Energy Consolidated	$	542		$	306

(1) Regulatory assets earning a rate of return.

(2) Represents cumulative amounts collected in rates for future nonlegal asset removal costs.

NET REGULATORY ASSETS (LIABILITIES) AS PRESENTED ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,
	2016									2015
	Sempra Energy Consolidated			SDG&E			SoCalGas			Sempra Energy Consolidated			SDG&E			SoCalGas
Current regulatory assets(1)	$	89		$	81		$	8		$	115		$	107		$	7
Noncurrent regulatory assets(2)	3,329			2,012			1,246			3,058			1,891			1,120
Current regulatory liabilities(3)	—			—			—			(2		)	—			—
Noncurrent regulatory liabilities(4)	(2,876		)	(1,725		)	(1,151		)	(2,865		)	(1,629		)	(1,216		)
Total	$	542		$	368		$	103		$	306		$	369		$	(89	)

(1) At Sempra Energy Consolidated, included in Other Current Assets.

(2) Excludes long-term undercollected balancing accounts at December 31, 2016 and 2015 of $85 million and $215 million, respectively, recorded at Sempra Energy Consolidated as Regulatory Assets (long-term) and at SoCalGas as Other Regulatory Assets (long-term).

(3) Included in Other Current Liabilities.

(4) At December 31, 2016 and 2015, $179 million and $72 million, respectively, at Sempra Energy Consolidated and $179 million and $71 million, respectively, at SoCalGas are included in Deferred Credits and Other.

In the tables above:

▪ Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts.

▪ Regulatory assets arising from the SONGS plant closure are associated with SDG&E’s investment in SONGS as of the plant closure date and the cost of operations since Units 2 and 3 were taken offline, as we discuss further in Note 13.

▪ Regulatory assets recorded to the Wildfire Expense Memorandum Account (WEMA) arising from CPUC-related costs for wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties, and are subject to CPUC review for reasonableness and assessment of SDG&E’s prudence surrounding the settlement of claims in connection with the 2007 wildfires. We discuss the 2007 wildfires in Note 15 in “SDG&E – 2007 Wildfire Litigation.”

▪ Deferred taxes recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to recover net regulatory assets related to deferred income taxes over the lives of the assets that give rise to the accumulated deferred income tax liabilities. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further below.

▪ Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded.

▪ Regulatory assets related to unamortized losses on reacquired debt are recovered over the remaining amortization periods of the losses on reacquired debt. These periods range from 1 year to 11 years for SDG&E and from 5 years to 9 years for SoCalGas.

▪ Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made. We discuss environmental issues further in Note 15.

▪ The regulatory asset related to the legacy meters removed from service and replaced under the Smart Meter Program is their undepreciated value. SDG&E is recovering this asset over a remaining 1-year period in rate base.

▪ The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 53-year period. We discuss the trust further in Note 15.

▪ The regulatory asset related to workers’ compensation represents accrued costs for future claims that will be recovered from customers in future rates as expenditures are made.

▪ Amortization expense on regulatory assets for the years ended December 31, 2016, 2015 and 2014 was $65 million, $62 million and $20 million, respectively, at Sempra Energy Consolidated, $63 million, $60 million and $18 million, respectively, at SDG&E, and $2 million in each year at SoCalGas.

CALIFORNIA UTILITIES MATTERS

CPUC General Rate Case (GRC)

The CPUC uses a general rate case proceeding to set sufficient rates to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment.

In 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 until the next general rate case proceeding.

In June 2016, the CPUC issued a final decision in the 2016 GRC. The final decision (2016 GRC FD) adopted a 2016 revenue requirement of $2.204 billion for SoCalGas and $1.791 billion for SDG&E. The 2016 GRC FD also required certain refunds to be paid to customers and establishes a two-way income tax expense memorandum account, each discussed below.

The 2016 GRC FD also adopted 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 denied a separate request for a four-year GRC period and instead adopted a three-year GRC period (through 2018).

The 2016 GRC FD is effective retroactive to January 1, 2016, and the California Utilities recorded the retroactive impacts in the second 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 through December 2017. At December 31, 2016, balancing accounts related to the adoption of the revenue requirements were $20 million and $47 million, at SDG&E and SoCalGas, respectively.

The 2016 GRC FD results in certain accounting impacts associated with flow-through income tax repairs deductions. 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 estimated amounts in the memorandum accounts totaled $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 million, respectively, in the second quarter of 2016 (summarized below). In addition, 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 provided to the shareholders for the period 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.

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 SoCalGas and SDG&E. 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). In the third quarter of 2016, SoCalGas and SDG&E completed their 2015 calendar year tax returns, and final tax deductions associated with tax repair benefits to be refunded to ratepayers associated with the 2015 memo account were lower than the amounts estimated in 2015. Accordingly, the amounts to be refunded decreased by $19 million for SoCalGas and $5 million for SDG&E. In October 2016, SoCalGas and SDG&E filed a regulatory account update with the CPUC to reflect their final total 2015 repair allowance deductions of $53 million and $32 million, respectively. After recording the related income tax effect and corresponding regulatory revenue adjustments for income tax purposes, there was no net impact to earnings from the adjustments to the 2015 tax repairs deductions recorded in the third quarter of 2016. Accordingly, the earnings impacts in the table below are also the earnings impacts for the year ended December 31, 2016.

Following is a summary of immediate earnings impacts from the 2016 GRC FD:

EARNINGS IMPACTS FROM THE 2016 GRC FD
(Dollars in millions)
	SoCalGas						SDG&E
	Pretax earnings (charge)			After-tax earnings (charge)			Pretax earnings (charge)			After-tax earnings (charge)
Adjustments to revenue related to tax
repairs deductions:
2015 memorandum account balance	$	(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 the establishment of a two-way income tax expense memorandum account to track any revenue differences resulting from differences between the income tax expense forecasted in the GRC and the income tax expense incurred by the California Utilities from 2016 through 2018. The differences tracked are to specifically 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. 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 SoCalGas and SDG&E and the income tax expense incurred by them during the GRC period. Starting in the second quarter of 2016, SoCalGas and SDG&E are recording liabilities associated with tracking the differences in the income tax expense forecasted in the GRC proceedings and the income tax expense incurred, which for the year ended December 31, 2016 resulted in after-tax charges to earnings of $16 million ($27 million pretax) and $3 million ($5 million pretax), for SoCalGas and SDG&E, respectively.

CPUC Cost of Capital

A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE), weighted on a basis consistent with the authorized capital structure. The authorized ROR is the rate that the California Utilities are authorized to use in establishing rates to recover the cost of debt and equity used to finance their investment in CPUC-regulated electric distribution and generation as well as natural gas distribution, transmission and storage assets.

A cost of capital proceeding also addresses the automatic cost of capital adjustment mechanism (CCM), which applies market-based benchmarks to determine whether an adjustment to the authorized ROR is required during the interim years between cost of capital proceedings. The market-based benchmark for SDG&E’s and SoCalGas’ CCM is the 12-month average monthly A-rated utility bond index, as published by Moody’s for the 12-month period of October 1st through September 30th (CCM Period) of each calculation year. In the last cost of capital proceeding, SDG&E’s and SoCalGas’ CCM benchmark rate was set at 4.24 percent. If at the end of the CCM Period the monthly average benchmark rate falls outside of the established range of 3.24 percent to 5.24 percent, SDG&E’s and SoCalGas’ authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the benchmark rate. In addition, the authorized recovery rate for SDG&E’s and SoCalGas’ cost of debt and preferred stock would be adjusted to their respective actual weighted average costs, with no change to the authorized capital structure. All three adjustments with the new rate would become effective on January 1st of the following year in which the benchmark range was exceeded. For the twelve-month period ended September 30, 2016, the 12-month average of monthly Moody’s A-rated utility bond index was 4.01 percent, which is within the established range of 3.24 percent and 5.24 percent.

The CCM only applies during the intervening years between scheduled cost of capital proceedings. In the year the cost of capital proceeding is scheduled, the cost of capital proceeding takes precedence over the CCM and will set new rates for the following year.

SDG&E’s current CPUC-authorized ROR is 7.79 percent and SoCalGas’ current CPUC-authorized ROR is 8.02 percent based on their authorized capital structures as follows:

COST OF CAPITAL AND AUTHORIZED RATE STRUCTURE – CPUC
SDG&E							SoCalGas
Authorized weighting		Authorized rate of recovery		Weighted authorized ROR			Authorized weighting		Authorized rate of recovery		Weighted authorized ROR
45.25	%	5.00	%	2.26	%	Long-Term Debt	45.60	%	5.77	%	2.63	%
2.75	%	6.22	%	0.17	%	Preferred Stock	2.40	%	6.00	%	0.14	%
52.00	%	10.30	%	5.36	%	Common Equity	52.00	%	10.10	%	5.25	%
100.00	%			7.79	%		100.00	%			8.02	%

Under an agreement approved in 2016, the CPUC granted SDG&E and SoCalGas an extension of their cost of capital filing deadlines to April 2017 and extended the current CCM until the April 2017 filing date. However, in the event the adjustment mechanism is triggered, the utilities agreed that no changes to the current cost of capital would be made under the mechanism.

On February 7, 2017, SDG&E, SoCalGas, Pacific Gas and Electric Company (PG&E) and Edison (collectively, the Joint Investor-Owned Utilities or Joint IOUs), along with the ORA and TURN, entered into a memorandum of understanding and filed a joint petition for modification (PFM) with the CPUC seeking a two-year extension for each of the Joint IOUs to file its next respective cost of capital application, extending the date to file the next cost of capital application from April 2017 to April 2019 for a 2020 test year. In addition to the two-year extension of the deadline to file the next cost of capital application, the memorandum of understanding contains provisions to reduce the ROE for SDG&E from 10.30 percent to 10.20 percent and for SoCalGas from 10.10 percent to 10.05 percent, effective from January 1, 2018 through December 31, 2019. SDG&E’s and SoCalGas’ ratemaking capital structures will remain at the levels shown above until modified, if at all, by a future cost of capital decision by the CPUC. Also, the Joint IOUs will update their cost of capital for actual cost of long-term debt through August 2017 and forecasted cost through 2018, and update preferred stock costs for anticipated issuances (if any) through 2018. The CCM will be in effect to adjust 2019 cost of capital, if necessary. Unless changed by the operation of the CCM, the updated costs of long-term debt and preferred stock (if applicable) and new ROEs will remain in effect through December 31, 2019. The PFM is subject to final approval by the CPUC.

SDG&E MATTERS

FERC Rate Matters and Cost of Capital

SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets. The Electric Transmission Formula Rate (TO4) settlement agreement, approved by the FERC in May 2014 and in effect through December 31, 2018, established a 10.05 percent ROE. The settlement also established 1) a process whereby rates are determined using a base period of historical costs and a forecast of capital investments and 2) a true-up period similar to balancing account treatment that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment. SDG&E will make annual information filings on December 1 of a given year to update rates for the following calendar year. SDG&E also has the right to file for any ROE incentives that might apply under FERC rules. SDG&E’s debt to equity ratio will be set annually based on the actual ratio at the end of each year.

SDG&E’s current estimated FERC ROR is 7.51 percent based on its capital structure as follows:

SDG&E COST OF CAPITAL AND RATE STRUCTURE – FERC
	Weighting		Rate of recovery		Weighted ROR
Long-Term Debt	43.48	%	4.21	%	1.83	%
Common Equity	56.52	%	10.05	%	5.68	%
	100.00	%			7.51	%

In September 2015, the presiding judge assigned by the FERC to SDG&E’s annual TO4 Formula Cycle 2 filing issued an initial decision and an order on summary judgment that authorized SDG&E to recover all of the costs incurred and allocated to SDG&E’s FERC-regulated operations, including $23 million of costs associated with the 2007 wildfires, discussed in Note 15. 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. In April 2016, the FERC affirmed its finding in the September 2015 order and denied the CPUC’s request for rehearing. The FERC decision finalizes SDG&E’s base transmission revenue requirement and the recovery of $23 million of wildfire damage expenses allocated to SDG&E’s FERC-regulated operations.