XML 53 R22.htm IDEA: XBRL DOCUMENT v3.8.0.1
REGULATORY MATTERS
 12 Months Ended
Dec. 31, 2017
Regulated Operations [Abstract]  
Regulatory Matters
SAN ONOFRE NUCLEAR GENERATING STATION
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, 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 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 costs. 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 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 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 recovery of damages. The other SONGS co-owners, SDG&E and the City of Riverside, participated as claimants and respondents.
On March 13, 2017, the Tribunal overseeing the arbitration found MHI liable for breach of contract, subject to a contractual limitation of liability, and 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 costs, resulting in 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 discussed below, SDG&E recorded the 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
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, TURN, ORA and two other intervenors. The Amended Settlement Agreement does not affect ongoing or future proceedings before the NRC, or any 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 any 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 return on rate base)
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 December 2016, the CPUC 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 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 met to confer, engaged a mediator and held confidential mediation discussions in June, July and August of 2017.
In August 2017, the parties filed status reports providing their recommendations for resolving the OII given their unsuccessful efforts at reaching a settlement through mediation. SDG&E and Edison recommended that the Amended Settlement Agreement, as adopted by the CPUC, should be affirmed and the pending intervenor petitions dismissed. Intervening parties recommended various alternative courses of action, including modifying the Amended Settlement Agreement or rejecting it in favor of litigation. In October 2017, the CPUC issued a ruling establishing a process to bring the proceeding to a conclusion. This ruling establishes a status conference and includes a preliminary schedule for additional testimony, hearings and briefings.
On January 30, 2018, SDG&E, Edison, ORA, TURN and other intervenors entered into a settlement agreement (Revised Settlement Agreement). On the same date, a Joint Motion for Adoption of the Settlement Agreement was filed with the CPUC. If approved by the CPUC, the Revised Settlement Agreement will resolve all issues under consideration in the SONGS OII and will modify the Amended Settlement Agreement approved by the CPUC in November 2014. The Revised Settlement Agreement was the result of multiple mediation sessions in 2017 and January 2018 and was signed following a settlement conference in the SONGS OII, as required under CPUC rules. On February 1, 2018, the parties filed a motion to stay the proceedings in the OII pending the CPUC’s consideration of the Revised Settlement Agreement. On February 6, 2018, the CPUC granted the parties’ motion to stay the proceedings and established a tentative procedural schedule with public participation hearings in April and July, evidentiary hearings in April and May, and briefing in June of 2018.
The Revised Settlement Agreement is subject to CPUC approval. The parties to the Revised Settlement Agreement have agreed to exercise their best efforts to obtain CPUC approval. In the event that the CPUC fails to approve the Revised Settlement Agreement, the proceeding will remain open and subject to previous rulings in the SONGS OII, and the Amended Settlement Agreement will remain in effect, unless it is modified or set aside by the CPUC as a result of the OII proceeding.
In connection with the Revised Settlement Agreement, and in exchange for the release of certain SONGS-related claims, SDG&E and Edison entered into the Utility Shareholder Agreement, described below, in which Edison has agreed to pay for the amounts that SDG&E would have received in rates under the Amended Settlement Agreement but will not receive upon implementation of the Revised Settlement Agreement. The Utility Shareholder Agreement is not subject to the approval of the CPUC. However, it is not effective unless and until the CPUC approves the Revised Settlement Agreement.
The timing of a ruling by the CPUC on the Joint Motion for Adoption of the Settlement Agreement is unclear. There is no assurance that the Revised Settlement Agreement will be adopted or that the Amended Settlement Agreement will not be modified or set aside as a result of the OII proceeding, which could result in a substantial reduction in our expected recovery or in payments to customers. These outcomes could have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations, financial condition and cash flows.
Disallowances, Refunds and Recoveries
If the Revised Settlement Agreement is approved by the CPUC, SDG&E and Edison will cease rate recovery of SONGS costs as authorized under the Amended Settlement Agreement as of the date their combined remaining SONGS regulatory assets equal $775 million (the Cessation Date). Currently, the estimated Cessation Date is December 19, 2017. The Cessation Date is partly dependent on the outcome of Edison’s pending request to the CPUC, in a separate proceeding, for approval to apply certain proceeds received from the DOE to reduce Edison’s SONGS regulatory asset. If this request is rejected by the CPUC, then the estimated Cessation Date will be April 21, 2018. In either case, under the Utility Shareholder Agreement, Edison is obligated to pay SDG&E the full amount of SDG&E’s revenue requirement not recovered from ratepayers, as described below. SDG&E and Edison will refund to customers SONGS-related amounts recovered in rates after the Cessation Date.
In the event that the CPUC takes an action that has the effect of invalidating the Utility Shareholder Agreement, SDG&E may, in its discretion, withdraw from the Revised Settlement Agreement, in which case Edison shall remain a party to the Revised Settlement Agreement, but the Revised Settlement Agreement shall be terminated as to SDG&E. In such a scenario, SDG&E would return to its litigation position before the CPUC in the SONGS OII that existed prior to the Revised Settlement Agreement.
Pursuant to the CPUC’s rules, no settlement becomes binding unless the CPUC approves the settlement based on a finding that it is reasonable in light of the whole record, consistent with law, and in the public interest. The CPUC has discretion to approve or disapprove a settlement, or to condition its approval on changes to the settlement, which the parties may accept or reject, negotiating in good faith to seek a resolution acceptable to all parties. CPUC rules do not provide for any fixed time period for the CPUC to act on proposed settlements.
Utility Shareholder Agreement
On January 10, 2018, SDG&E and Edison entered into the Utility Shareholder Agreement. Under the terms of the Utility Shareholder Agreement, Edison has an obligation to compensate SDG&E for the revenue requirement amounts that SDG&E will no longer recover because of the Revised Settlement Agreement. In exchange for Edison’s reimbursement, the parties will mutually release each other from the “SONGS Issues,” a defined term that consists of 18 broad categories. The effect of the agreement is that SDG&E will release Edison from any and all claims that SDG&E had or could have asserted related to the steam generator replacement failure and its aftermath. The Utility Shareholder Agreement becomes effective only upon CPUC approval of the Revised Settlement Agreement. Edison’s payment obligation commences 30 days after the first fiscal quarter in which the CPUC approves the Revised Settlement Agreement, and amounts are due to SDG&E quarterly thereafter until April 2022, which approximates the amounts and timing of amounts of what would have been SDG&E’s recoveries from ratepayers contemplated under the Amended Settlement Agreement.
Accounting and Financial Impacts
As a result of the Revised Settlement Agreement by the settling parties and the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison totaling $152 million, $32 million classified as current and $120 million classified as noncurrent, as of December 31, 2017. This receivable reflects amounts Edison is obligated to pay to SDG&E in lieu of amounts SDG&E would have collected from ratepayers associated with the SONGS regulatory asset, which SDG&E believes is now no longer probable of recovery.
Assuming the Revised Settlement Agreement is approved, SDG&E and Sempra Energy do not expect that implementation of the Revised Settlement Agreement in combination with the Utility Shareholder Agreement will have a material adverse impact on either company. However, until the CPUC approves the Revised Settlement Agreement as proposed, there can be no assurance that the SONGS OII proceeding will conclude as contemplated by SDG&E in accordance with the Revised Settlement Agreement and the Utility Shareholder Agreement, or that the CPUC will not order refunds to customers above those contemplated by the Amended Settlement Agreement, or take other action that may be adverse to SDG&E and Sempra Energy. Such alternative outcomes could have a material adverse effect on SDG&E’s and Sempra Energy’s results of operations, financial condition and cash flows.
SETTLEMENT WITH NEIL
As we discuss below, 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 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 ERRA. 
NUCLEAR DECOMMISSIONING AND FUNDING
As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. 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 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 approximately 20 percent of the total contract price.
In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. 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 NDT are invested in accordance with CPUC regulations. The NDT assets are presented on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.
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. 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. SDG&E has received authorization from the CPUC to access NDT funds of up to $362 million for 2013 through 2018 (2018 forecasted) SONGS decommissioning costs. This includes up to $60 million authorized by the CPUC in January 2018 to be withdrawn from the NDT for forecasted 2018 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 clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust 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 awaiting the adoption of, or additional refinement to, the proposed regulations before determining whether 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 DOE’s responsibility for spent nuclear fuel below. The IRS held public hearings on the proposed regulations in October 2017. 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 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 noncurrent Regulatory Liabilities. 
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, 2017:
 
 
 
 
 
 
 
Debt securities:
 
 
 
 
 
 
 
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)
$
54

 
$
—

 
$
—

 
$
54

Municipal bonds(1)
245

 
7

 
(2
)
 
250

Other securities(2)
215

 
3

 
(1
)
 
217

Total debt securities
514

 
10

 
(3
)
 
521

Equity securities
171

 
326

 
(1
)
 
496

Cash and cash equivalents
16

 
—

 
—

 
16

Total
$
701

 
$
336

 
$
(4
)
 
$
1,033

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

(1) 
Maturity dates are 2018-2048.
(2) 
Maturity dates are 2018-2064.

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,
 
2017
 
2016
 
2015
Proceeds from sales(1)
$
1,314

 
$
1,134

 
$
577

Gross realized gains
157

 
111

 
29

Gross realized losses
(14
)
 
(29
)
 
(15
)
(1) 
Excludes securities that are held to maturity.

Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities 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 2017 and 2016, sale and purchase activities in our NDT increased significantly compared to 2015 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.
ASSET RETIREMENT OBLIGATION AND SPENT NUCLEAR FUEL
SDG&E’s asset retirement obligation related to decommissioning costs for the SONGS units was $607 million at December 31, 2017. 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, 2017 for Unit 1 is based on a cost study prepared in 2016 that is pending CPUC approval. The asset retirement obligation at December 31, 2017 for Units 2 and 3 is based on a CPUC-approved cost study prepared in 2014 that reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. SDG&E’s share of total decommissioning costs in 2017 dollars is approximately $1 billion. 
U.S. Department of Energy Nuclear Fuel Disposal
Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC or temporarily in spent fuel pools. In October 2015, the CCC approved Edison’s application for the proposed expansion of the ISFSI at SONGS. The ISFSI expansion began construction in 2016 and is expected to be fully loaded with spent fuel by 2019 and 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. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.
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. In April 2016, Edison executed a spent fuel settlement agreement with the DOE for $162 million covering damages incurred from 2006 through 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 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 2017, Edison filed claims with the DOE for $58 million in spent fuel management costs incurred in 2016 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. SDG&E’s respective share of the claim is $12 million. It is unclear whether the claim will be resolved through settlement or arbitration, when resolution is expected, and whether Edison will receive an award for the full claim amount.
The 2016 spent fuel settlement agreement governs the submission of claims for costs incurred through December 31, 2016. It is unclear whether Edison will enter into a new settlement with the DOE or pursue litigation claims for spent fuel management costs incurred on or after January 1, 2017.
NUCLEAR INSURANCE
Edison requested and was granted approval in January 2018 by the NRC to reduce the nuclear liability and property damage insurance requirement, as described below. However, these changes in SONGS nuclear insurance levels require approval from all SONGS owners, which has not yet been obtained. We expect a decision in the first quarter of 2018.
SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $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 billion of SFP. If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $450 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. In such case, SDG&E’s contribution would be up to $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. Effective January 5, 2018, the NRC approved Edison’s request to reduce the nuclear liability insurance requirement from $450 million to $100 million and withdraw from participation in the SFP for SONGS.
The SONGS owners, including SDG&E, also maintain nuclear property damage insurance that exceeds the minimum federal requirements of $1.06 billion. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $10.4 million of retrospective premiums based on overall member claims. All of SONGS’ insurance claims arising out of the failures of the MHI replacement steam generators have been settled with NEIL, as we discuss above. Effective January 10, 2018, the NRC approved Edison’s request to reduce its property damage insurance requirement for SONGS from $1.06 billion to $50 million.
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.
REGULATORY MATTERS
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,
 
2017
 
2016
SDG&E:
 
 
 
Fixed-price contracts and other derivatives
$
96

 
$
141

Costs related to SONGS plant closure(1)
—

 
183

Costs related to wildfire litigation
—

 
353

Deferred income taxes (refundable) recoverable in rates
(281
)
 
1,014

Pension and other postretirement benefit plan obligations
153

 
210

Removal obligations
(1,846
)
 
(1,725
)
Unamortized loss on reacquired debt
9

 
12

Environmental costs
29

 
48

Legacy meters(1)
—

 
16

Sunrise Powerlink fire mitigation
119

 
118

Regulatory balancing accounts(2)
 
 
 
Commodity – electric
82

 
35

Gas transportation
22

 
61

Safety and reliability
48

 
20

Public purpose programs
(70
)
 
(106
)
Other balancing accounts
233

 
249

Other regulatory liabilities
(70
)
 
(2
)
Total SDG&E
(1,476
)
 
627

SoCalGas:
 

 
 

Pension and other postretirement benefit plan obligations
513

 
563

Employee benefit costs
45

 
45

Removal obligations
(924
)
 
(972
)
Deferred income taxes (refundable) recoverable in rates
(437
)
 
417

Unamortized loss on reacquired debt
8

 
10

Environmental costs
22

 
22

Workers’ compensation
12

 
10

Regulatory balancing accounts(2)
 
 
 
Commodity – gas, including transportation
151

 
207

Safety and reliability
266

 
230

Public purpose programs
(274
)
 
(270
)
Other balancing accounts
(114
)
 
(204
)
Other regulatory (liabilities) assets
(64
)
 
8

Total SoCalGas
(796
)
 
66

Sempra Mexico:
 
 
 
Deferred income taxes recoverable in rates
83

 
71

Total Sempra Energy Consolidated
$
(2,189
)
 
$
764

(1) 
Regulatory assets earning a rate of return.
(2) 
At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million. At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million, respectively. 

In the table 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. We discuss these fixed-price contracts and other derivatives further in Note 9.
▪
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. Pursuant to the Revised Settlement Agreement, rate recovery of SONGS costs remaining as a regulatory asset as of the Cessation Date will cease. Under the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison in lieu of amounts SDG&E would have collected from ratepayers. We discuss these matters further in Note 13.
▪
Regulatory assets for CPUC-related costs for wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties. In December 2017, the CPUC issued a final decision, denying SDG&E’s request to recover these costs. In 2017, SDG&E wrote off the wildfire regulatory asset resulting in a charge of $351 million, as we discuss in Note 15 in “SDG&E – 2007 Wildfire Litigation and Net Cost Recovery Status.”
▪
Deferred income taxes refundable/recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to refund/recover net regulatory liabilities/assets related to deferred income taxes over the lives of the assets that give rise to the related accumulated deferred income tax balances. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further below. In 2017, as a result of the TCJA, lowering the U.S. statutory corporate federal income tax from 35 percent to 21 percent resulted in excess deferred income tax balances that we expect to refund to ratepayers in accordance with the IRS normalization rules and as determined by the CPUC and the FERC. We discuss the TCJA and the impacts on Sempra Energy, SDG&E and SoCalGas in more detail in Note 6.
▪
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.
▪
The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.
▪
Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs.
▪
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 10 years for SDG&E and from 3 years to 8 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 has fully recovered this asset 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 52-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.
▪
Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, including commodity costs. Depreciation and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. Absent balancing account treatment, variations in covered costs, such as the cost of fuel supply and certain O&M costs, from amounts approved by the CPUC would increase volatility in utility earnings. Balancing account treatment eliminates the volatility in earnings that would otherwise result from variances in the covered costs compared to the authorized amounts.
Amortization expense on regulatory assets for the years ended December 31, 2017, 2016 and 2015 was $50 million, $65 million and $62 million, respectively, at Sempra Energy Consolidated, $49 million, $63 million and $60 million, respectively, at SDG&E, and $1 million, $2 million and $2 million, respectively at SoCalGas.
CALIFORNIA UTILITIES MATTERS
CPUC General Rate Case
The CPUC uses a GRC proceeding to set sufficient rates to allow the California Utilities to recover their reasonable cost of O&M and to provide the opportunity to realize their authorized rates of return on their investment.
2019 General Rate Case
On October 6, 2017, SDG&E and SoCalGas filed their 2019 GRC applications requesting CPUC approval of test year revenue requirements for 2019 and attrition year adjustments for 2020 through 2022. SDG&E and SoCalGas requested revenue requirements for 2019 of $2.199 billion and $2.989 billion, respectively, which is an increase of $217 million and $533 million over their respective 2018 revenue requirements (the 2018 revenue requirements reflect the impact of updated testimony filed in January 2018). The California Utilities are proposing post-test year revenue requirement changes using various adjustment factors which are estimated to result in annual increases of approximately 5 percent to 7 percent at SDG&E and approximately 6 percent to 8 percent at SoCalGas. Our 2019 GRC applications do not reflect the impact of the TCJA, which we discuss in Note 6. In April 2018, SDG&E and SoCalGas will be updating their applications to reflect the impact of the TCJA. We are assessing the impact of the new tax law on our 2018 operations and have a tax tracking mechanism for net tax benefits that will flow to ratepayers. We intend to work with the CPUC to determine the mechanism for passing on the savings to ratepayers.
As part of the 2019 GRC, the CPUC will review the California Utilities’ interim accountability reports, which compare the authorized and actual spending for certain safety-related activities for 2014 through 2016. 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 was provided with the 2019 GRC filings in a second interim accountability report. The stated purpose of the interim accountability reports is to provide data and metrics for key safety and risk mitigation areas that will be considered in the 2019 GRC.
The results of the rate case may materially and adversely differ from what is contained in the GRC applications.
Risk Assessment Mitigation Phase Reporting and Impact on the 2019 GRC Filings
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 discussed above, 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 CPUC to establish guidelines and standards for these models.
In 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.
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 the California Utilities presented in the report. The new GRC framework does not require the CPUC to adopt the RAMP report. However, SDG&E and SoCalGas included funding requests in their respective 2019 GRC filings for proposed projects or activities outlined in their RAMP reports.
Senate Bill 549. In September 2017, SB 549 was signed into law, requiring that SDG&E and SoCalGas (as electric and gas corporations) annually notify the CPUC when revenue authorized by the CPUC for maintenance, safety or reliability is redirected to other purposes. This requirement is effective beginning January 1, 2018. The form of this reporting is not yet defined by the CPUC, though it could be incorporated into an ongoing proceeding or report otherwise required to be submitted to the CPUC.
2016 General Rate Case
In June 2016, the CPUC issued a final decision in the 2016 GRC. The 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 was effective retroactive to January 1, 2016, and the California Utilities recorded the retroactive impacts in the second quarter of 2016. 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 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 reallocated 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 were tracked in memorandum accounts, were 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 were $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 did not result in an impairment of any of our reported assets, but have impacted 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 the 2016 earnings impacts from the 2016 GRC FD:
EARNINGS IMPACTS IN 2016 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
)

As discussed above, the 2016 GRC FD required the establishment of two-way income tax expense memorandum accounts to track any revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred by SoCalGas and SDG&E 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.
Starting in the second quarter of 2016, SoCalGas and SDG&E began tracking the differences in the income tax expense forecasted in the GRC proceedings and the income tax expense incurred. At December 31, 2017, the recorded regulatory liability associated with these tracked amounts totaled $69 million and $65 million for SoCalGas and SDG&E, respectively. The recorded liability is primarily related to lower income tax expense incurred than was forecasted in the GRC relating to tax repairs deductions, self-developed software deductions and certain book-over-tax depreciation. We are currently assessing the impact of federal tax reform on 2018 operations and will track such impacts in the tracking accounts. The tracking accounts will remain open, and we expect they will be reviewed in the 2019 GRC proceedings. Federal tax reform, which we discuss in Note 6, could result in significant amounts recorded in these tracking accounts beginning in 2018.
CPUC Cost of Capital
In July 2017, the CPUC issued a final decision adopting, with certain modifications, the joint petition filed in February 2017 by SDG&E, SoCalGas, PG&E and Edison, along with ORA and TURN. The final decision provides a two-year extension for each of the utilities to file its next respective cost of capital application, extending the filing date to April 2019 for a 2020 test year. The final decision also reduces 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 current levels until modified, if at all, by a future cost of capital decision by the CPUC. In September 2017, SDG&E and SoCalGas filed advice letters to update their cost of capital for the actual cost of long-term debt through August 2017 and forecasted cost through 2018. SDG&E and SoCalGas did not file for changes to preferred stock costs, because no issuances of preferred stock through 2018 are anticipated.
In October 2017, the CPUC approved the embedded cost of debt presented in the filed advice letters, resulting in a revised return on rate base for SDG&E from 7.79 percent to 7.55 percent and for SoCalGas from 8.02 percent to 7.34 percent, effective January 1, 2018, as depicted in the table below:
AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE – CPUC
 
 
 
 
 
 
 
 
 
 
 
 
 
SDG&E
 
SoCalGas
Authorized weighting
Return on
rate base
Weighted
return on
rate base
 
Authorized weighting
Return on
rate base
Weighted
return on
rate base
45.25
%
4.59
%
2.08
%
Long-Term Debt
45.60
%
4.33
%
1.97
%
2.75
 
6.22
 
0.17
 
Preferred Stock
2.40
 
6.00
 
0.14
 
52.00
 
10.20
 
5.30
 
Common Equity
52.00
 
10.05
 
5.23
 
100.00
%
 
 
7.55
%
 
100.00
%
 
 
7.34
%


As a result of the updates included in the filed advice letters, the impact of the changes to the embedded cost of debt and return on rate base is summarized below:
IMPACT OF THE EMBEDDED COST OF DEBT
 
 
 
 
SDG&E
 
SoCalGas
 
Cost of
debt
Return on
rate base
 
Cost of
debt
Return on
rate base
Current
5.00

%
7.79

%
 
5.77

%
8.02

%
Authorized, effective January 1, 2018
4.59

%
7.55

%
 
4.33

%
7.34

%
Differences
(41
)
bps
(24
)
bps
 
(144
)
bps
(68
)
bps

The automatic 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 the new ROEs will remain in effect through December 31, 2019. The cost of capital changes will also apply to capital expenditures in 2018 and 2019 for incremental projects not funded through the GRC revenue requirement.
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.
SDG&E’s current estimated FERC return on rate base under the TO4 formula rate request filing is 7.51 percent based on its capital structure as follows:
SDG&E COST OF CAPITAL AND RATE STRUCTURE – FERC
 
 
 
Weighting
 
 
Return on rate base
 
 
Weighted return on rate base
 
Long-Term Debt
 
43.44
%
 
4.21
%
 
1.83
%
Common Equity
 
56.56
 
 
10.05
 
 
5.68
 
 
 
100.00
%
 
 
 
 
7.51
%

SDG&E expects to file its TO5 formula rate request with the FERC by June 2018, to be effective January 1, 2019.