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NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.
This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).
The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, environmental remediation liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that could have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations and cash flows during the period in which such change occurred.
Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in California that, in total, burned over 245,000 acres, resulted in 43 fatalities, and destroyed an estimated 8,900 structures. Subsequently, the number of fatalities increased to 44. The fires are being investigated by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. See “Northern California Wildfires” in Note 13 below.
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NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Regulation and Regulated Operations
The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility also records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.
Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements.
The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three or four years. The Utility’s ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.
The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income.
The FERC authorizes the Utility’s revenue requirements in periodic (often annual) TO rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of revenues subject to refund.
Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value.
Allowance for Doubtful Accounts Receivable
PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.
Property, Plant, and Equipment
Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
Estimated Useful |
| Balance at December 31, | |||||||
(in millions, except estimated useful lives) | Lives (years) |
| 2017 |
| 2016 | ||||
Electricity generating facilities (1) | 5 to 120 |
| $ | 11,843 |
| $ | 11,308 | ||
Electricity distribution facilities | 15 to 65 |
|
| 31,110 |
|
| 29,836 | ||
Electricity transmission facilities | 15 to 75 |
|
| 12,180 |
|
| 11,412 | ||
Natural gas distribution facilities | 5 to 60 |
|
| 12,312 |
|
| 11,362 | ||
Natural gas transmission and storage facilities | 5 to 62 |
|
| 7,329 |
|
| 6,491 | ||
Construction work in progress |
|
|
| 2,471 |
|
| 2,184 | ||
Total property, plant, and equipment |
|
|
| 77,245 |
|
| 72,593 | ||
Accumulated depreciation |
|
|
| (23,456) |
|
| (22,012) | ||
Net property, plant, and equipment |
|
| $ | 53,789 |
| $ | 50,581 | ||
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(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as used based on the amount of energy output. (See Note 13 below.)
The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.83% in 2017, 3.73% in 2016, and 3.80% in 2015. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $38 million and $89 million during 2017, $51 million and $112 million during 2016, and $48 million and $107 million during 2015.
The following table summarizes the changes in ARO liability during 2017 and 2016, including nuclear decommissioning obligations:
| 2017 |
|
| 2016 | |
ARO liability at beginning of year | $ | 4,684 |
| $ | 3,643 |
Revision in estimated cash flows |
| 128 |
|
| 968 |
Accretion |
| 207 |
|
| 194 |
Liabilities settled |
| (120) |
|
| (121) |
ARO liability at end of year | $ | 4,899 |
| $ | 4,684 |
The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to specified conditions under certain agreements.
Nuclear Decommissioning Obligation
Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for Diablo Canyon, representing 64% of the Utility’s request of $3.8 billion. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down.
PG&E Corporation and the Utility recorded an increase of $92 million to the ARO recognized on the Consolidated Balance Sheets, to align the decommissioning cost estimate with the CPUC’s final decision on the Utility’s application to retire Diablo Canyon Unit 1 by 2024 and Unit 2 by 2025.
The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued was $3.5 billion at both December 31, 2017 and 2016. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $4.1 billion at December 31, 2017 (or $7 billion in future dollars). These estimates are based on the 2017 decommissioning cost studies, prepared in accordance with CPUC requirements.
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. (See “Enforcement and Litigation Matters” in Note 13 below.)
Nuclear Decommissioning Trusts
The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.
The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.” Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.
A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.
Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2017, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2017, it did not consolidate any of them.
Other Accounting Policies
For other accounting policies impacting PG&E Corporation’s and the Utility’s consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in Note 13 herein.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
Pension |
| Other |
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(in millions, net of income tax) | Benefits |
| Benefits |
| Total | |||
Beginning balance | $ | (25) |
| $ | 16 |
| $ | (9) |
Other comprehensive income before reclassifications: |
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Unrecognized prior service cost |
|
|
|
|
|
|
|
|
(net of taxes of $4 and $0, respectively) |
| (6) |
|
| - |
|
| (6) |
Unrecognized net actuarial loss |
|
|
|
|
|
|
|
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(net of taxes of $229 and $97, respectively) |
| 333 |
|
| 141 |
|
| 474 |
Regulatory account transfer |
|
|
|
|
|
|
|
|
(net of taxes of $225 and $97, respectively) |
| (327) |
|
| (141) |
|
| (468) |
Amounts reclassified from other comprehensive income: |
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Amortization of prior service cost |
|
|
|
|
|
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|
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(net of taxes of $3 and $6, respectively) (1) |
| (4) |
|
| 9 |
|
| 5 |
Amortization of net actuarial loss |
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|
|
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(net of taxes of $9 and $2, respectively) (1) |
| 13 |
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| 2 |
|
| 15 |
Regulatory account transfer |
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|
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|
|
|
(net of taxes of $6 and $8, respectively) (1) |
| (9) |
|
| (10) |
|
| (19) |
Net current period other comprehensive loss |
| - |
|
| 1 |
|
| 1 |
Ending balance | $ | (25) |
| $ | 17 |
| $ | (8) |
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(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2016 consisted of the following:
Pension |
| Other |
|
|
| |||
(in millions, net of income tax) | Benefits |
| Benefits |
| Total | |||
Beginning balance | $ | (23) |
| $ | 16 |
| $ | (7) |
Other comprehensive income before reclassifications: |
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Unrecognized prior service cost |
|
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|
|
|
|
|
|
(net of taxes of $37 and $15, respectively) |
| 54 |
|
| (21) |
|
| 33 |
Unrecognized net actuarial loss |
|
|
|
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|
|
|
(net of taxes of $45 and $15, respectively) |
| (64) |
|
| 21 |
|
| (43) |
Regulatory account transfer |
|
|
|
|
|
|
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(net of taxes of $5 and $0, respectively) |
| 7 |
|
| - |
|
| 7 |
Amounts reclassified from other comprehensive income: |
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Amortization of prior service cost |
|
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|
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|
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(net of taxes of $3 and $6, respectively) (1) |
| 5 |
|
| 9 |
|
| 14 |
Amortization of net actuarial loss |
|
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|
(net of taxes of $10 and $2, respectively) (1) |
| 14 |
|
| 2 |
|
| 16 |
Regulatory account transfer |
|
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|
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|
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(net of taxes of $13 and $8, respectively) (1) |
| (18) |
|
| (11) |
|
| (29) |
Net current period other comprehensive loss |
| (2) |
|
| - |
|
| (2) |
Ending balance | $ | (25) |
| $ | 16 |
| $ | (9) |
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(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)
With the exception of other investments, there was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Accounting Standards Issued But Not Yet Adopted
Presentation of Net Periodic Pension Cost
In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuaries. The change in capitalization of retirement benefits will not have a material impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.
Recognition of Lease Assets and Liabilities
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. In November, 2017, the FASB tentatively decided to amend the new leasing guidance such that entities may elect not to restate their comparative periods in the period of adoption. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with early adoption permitted. PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility expect this standard to increase lease assets and lease liabilities on the Consolidated Balance Sheets and do not expect the guidance will have a material impact on the Consolidated Statements of Income, Statements of Cash Flows and lease disclosures.
Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends the existing guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts. These investments are classified as “available-for-sale” and gains or losses are refundable, or recoverable, from customers through rates. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and will not have a material impact on the Consolidated Financial Statements and related disclosures.
Revenue Recognition Standard
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends existing revenue recognition guidance. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018. This standard will be adopted for related disclosures in the first quarter of 2018 and will not have a material impact on the Consolidated Financial Statements. Upon adoption of ASU 2014-09, the Utility plans to disclose revenues from contracts with customers separately from regulatory balancing account revenue and disaggregate customer contract revenue by customer class.
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NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets
Current Regulatory Assets
At December 31, 2017 and 2016, the Utility had current regulatory assets of $615 million and $423 million, respectively. At December 31, 2017 and 2016, the current regulatory assets included $426 million and $223 million, respectively, of costs related to CEMA fire prevention and vegetation management. Current regulatory assets are included within the current assets in the Consolidated Balance Sheets.
Long-Term Regulatory Assets
Long-term regulatory assets are comprised of the following:
Balance at December 31, |
| Recovery | |||||||
(in millions) | 2017 |
| 2016 |
| Period | ||||
Pension benefits (1) | $ | 1,954 |
| $ | 2,429 |
| Indefinitely (3) | ||
Deferred income taxes (1)(4) |
| - |
|
| 3,859 |
|
| ||
Utility retained generation (2) |
| 319 |
|
| 364 |
| 9 years | ||
Environmental compliance costs (1) |
| 837 |
|
| 778 |
| 32 years | ||
Price risk management (1) |
| 65 |
|
| 92 |
| 10 years | ||
Unamortized loss, net of gain, on reacquired debt (1) |
| 79 |
|
| 76 |
| 25 years | ||
Other |
| 539 |
|
| 353 |
| Various | ||
Total long-term regulatory assets | $ | 3,793 |
| $ | 7,951 |
|
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(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP.
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
(3) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(4) The change in the balance from a regulatory asset as of December 31, 2016 to a regulatory liability as of December 31, 2017 reflects the impact of changes in net deferred tax liabilities associated with a lower federal income tax rate as a result of the Tax Act. (See “Regulatory Liabilities” below and Note 8.)
At December 31, 2017 and 2016, other long-term regulatory assets included $274 million and $70 million, respectively, of costs related to CEMA events from 2014 through 2017 that the Utility believes are recoverable based on historical experience in recovering costs for these types of events.
In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return only on its regulatory assets for retained generation, and unamortized loss, net of gain, on reacquired debt.
Regulatory Liabilities
Long-Term Regulatory Liabilities
Long-term regulatory liabilities are comprised of the following:
Balance at December 31, | |||||
(in millions) | 2017 |
| 2016 | ||
Cost of removal obligations (1) | $ | 5,547 |
| $ | 5,060 |
Deferred income taxes (2) |
| 1,021 |
|
| - |
Recoveries in excess of AROs (3) |
| 624 |
|
| 626 |
Public purpose programs (4) |
| 590 |
|
| 567 |
Other |
| 897 |
|
| 552 |
Total long-term regulatory liabilities | $ | 8,679 |
| $ | 6,805 |
|
|
|
|
|
|
(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.
(2) Represents the net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment. (See Note 8 below.)
(3) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 10 below.)
(4) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
Regulatory Balancing Accounts
The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.
Current regulatory balancing accounts receivable and payable are comprised of the following:
Receivable | |||||
| Balance at December 31, | ||||
(in millions) | 2017 |
| 2016 | ||
Electric distribution | $ | - |
| $ | 132 |
Electric transmission |
| 139 |
|
| 244 |
Utility generation |
| - |
|
| 48 |
Gas distribution and transmission |
| 486 |
|
| 541 |
Energy procurement |
| 71 |
|
| 132 |
Public purpose programs |
| 103 |
|
| 106 |
Other |
| 423 |
|
| 297 |
Total regulatory balancing accounts receivable | $ | 1,222 |
| $ | 1,500 |
Payable | |||||
| Balance at December 31, | ||||
(in millions) | 2017 |
| 2016 | ||
Electric distribution | $ | 72 |
| $ | - |
Electric transmission |
| 120 |
|
| 99 |
Utility generation |
| 14 |
|
| - |
Gas distribution and transmission |
| - |
|
| 48 |
Energy procurement |
| 149 |
|
| 13 |
Public purpose programs |
| 452 |
|
| 264 |
Other |
| 313 |
|
| 221 |
Total regulatory balancing accounts payable | $ | 1,120 |
| $ | 645 |
The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency.
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NOTE 4: DEBT
Long-Term Debt
The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:
|
| December 31, | |||||
(in millions) |
|
| 2017 |
| 2016 | ||
PG&E Corporation |
|
|
|
|
| ||
Senior notes: |
|
|
|
|
|
|
|
Maturity |
| Interest Rates |
|
|
|
|
|
2019 |
| 2.40% | $ | 350 |
| $ | 350 |
Unamortized discount, net of premium and debt issuance costs |
|
|
| - |
|
| (2) |
Total PG&E Corporation long-term debt |
|
|
| 350 |
|
| 348 |
Utility |
|
|
|
|
|
|
|
Senior notes: |
|
|
|
|
|
|
|
Maturity |
| Interest Rates |
|
|
|
|
|
2017 |
| 5.63% |
| - |
|
| 700 |
2018 |
| 8.25% |
| 400 |
|
| 800 |
2020 |
| 3.50% |
| 800 |
|
| 800 |
2021 |
| 3.25% to 4.25% |
| 550 |
|
| 550 |
2022 |
| 2.45% |
| 400 |
|
| 400 |
2023 through 2047 |
| 2.95% to 6.35% |
| 14,975 |
|
| 12,375 |
Less: current portion (1) |
|
|
| (400) |
|
| (700) |
Unamortized discount, net of premium and debt issuance costs |
|
|
| (185) |
|
| (161) |
Total senior notes, net of current portion |
|
|
| 16,540 |
|
| 14,764 |
Pollution control bonds: |
|
|
|
|
|
|
|
Maturity |
| Interest Rates |
|
|
|
|
|
Series 2004 A-D, due 2023(2) |
| 4.75% |
| - |
|
| 345 |
Series 2008 F and 2010 E, due 2026 (3) |
| 1.75% |
| 100 |
|
| - |
Series 2008 G, due 2018 (4) |
| 1.05% |
| 45 |
|
| - |
Series 2009 A-B, due 2026 (5) |
| 1.78% |
| 149 |
|
| 149 |
Series 1996 C, E, F, 1997 B due 2026 (6) |
| variable rate(7) |
| 614 |
|
| 614 |
Less: current portion |
|
|
| (45) |
|
| - |
Total pollution control bonds |
|
|
| 863 |
|
| 1,108 |
Total Utility long-term debt, net of current portion |
|
|
| 17,403 |
|
| 15,872 |
Total consolidated long-term debt, net of current portion |
|
| $ | 17,753 |
| $ | 16,220 |
|
|
|
|
|
|
|
|
(1) On January 19, 2018, the Utility sent a notice of redemption to redeem all $400 million aggregate principal amount of the 8.25% senior notes due October 15, 2018 on February 18, 2018. On January 31, 2018, the Utility deposited with the trustee funds sufficient to effect the early redemption of these bonds and satisfy and discharge its remaining obligation of $400 million.
(2) In June 2017, the Utility repurchased and retired $345 million principal amount of Pollution Control Bonds series 2004 A-D.
(3) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 30, 2022.
(4) Pollution Control Bonds series 2008G were remarketed and issued in June 2017 and mature on December 1, 2018.
(5) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.
(6) Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
(7) At December 31, 2017, the interest rate on these bonds ranged from 1.45% - 1.70%.
Pollution Control Bonds
The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant. In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sales agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding. Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.
Repayment Schedule
PG&E Corporation’s and the Utility’s combined long-term debt principal repayment amounts at December 31, 2017 are reflected in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
except interest rates) | 2018 |
| 2019 |
| 2020 |
| 2021 |
|
| 2022 |
| Thereafter |
| Total | ||||||||||||||||||||||||||
PG&E Corporation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Average fixed interest rate |
| - |
|
|
| 2.40% |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 2.40% | ||||||||||||||
Fixed rate obligations | $ | - |
|
| $ | 350 |
|
| $ | - |
|
| $ | - |
|
| $ | - |
|
| $ | - |
|
| $ | 350 | ||||||||||||||
Utility |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||
Average fixed interest rate |
| 7.52% |
|
|
| - |
|
|
| 3.50% |
|
|
| 3.80% |
|
|
| 2.31% |
|
|
| 4.68% |
|
|
| 4.61% | ||||||||||||||
Fixed rate obligations | $ | 445 |
|
| $ | - |
|
| $ | 800 |
|
| $ | 550 |
|
| $ | 500 (2) |
|
| $ | 14,975 |
|
| $ | 17,270 | ||||||||||||||
Variable interest rate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||
as of December 31, 2017 |
| - |
|
|
| 1.78% |
|
|
| 1.59% |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 1.63% | ||||||||||||||
Variable rate obligations (1) | $ | - |
|
| $ | 149 |
|
| $ | 614 |
|
| $ | - |
|
| $ | - |
|
| $ | - |
|
| $ | 763 | ||||||||||||||
Total consolidated debt | $ | 445 |
|
| $ | 499 |
|
| $ | 1,414 |
|
| $ | 550 |
|
| $ | 500 |
|
| $ | 14,975 |
|
| $ | 18,383 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||
(1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020.
(2) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 30, 2022.
Short-term Borrowings
|
| Credit |
| Letters of |
| Commercial |
|
|
| ||||||||||||
| Termination |
| Facility |
| Credit |
| Paper |
| Facility | ||||||||||||
(in millions) | Date |
| Limit |
| Outstanding |
| Outstanding |
| Availability | ||||||||||||
PG&E Corporation | April 2022 |
| $ | 300 | (1) |
| $ | - |
| $ | 132 |
| $ | 168 | |||||||
Utility | April 2022 |
|
| 3,000 | (2) |
|
| 49 |
|
| 50 |
|
| 2,901 | |||||||
Total revolving credit facilities |
|
| $ | 3,300 |
|
| $ | 49 |
| $ | 182 |
| $ | 3,069 | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
(1) Includes a $50 million lender commitment to the letter of credit sublimit and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.
(2) Includes a $500 million lender commitment to the letter of credit sublimit and a $75 million commitment for swingline loans.
For the year ended December 31, 2017, PG&E Corporation’s average outstanding commercial paper balance was $81 million and the maximum outstanding balance during the year was $161 million. For 2017, the Utility’s average outstanding commercial paper balance was $469 million and the maximum outstanding balance during the year was $1.1 billion. There were no bank borrowings for PG&E Corporation or the Utility in 2017.
Revolving Credit Facilities
In May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2021 to April 27, 2022. PG&E Corporation's and the Utility's revolving credit facilities may be used for working capital, the repayment of commercial paper, and other corporate purposes.
Borrowings under each credit agreement (other than swingline loans) will bear interest based on the borrower’s credit rating and on each borrower’s election of either (1) a London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent’s announced base rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The borrower’s credit rating at the time of borrowing will determine the applicable rate within the following ranges. The applicable margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’s credit agreement and between 0.8% and 1.275% under the Utility’s credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s credit agreement and between 0% and 0.275% under the Utility’s credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, respectively.
PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes. In addition, the respective revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. PG&E Corporation’s revolving credit facility agreement also requires that PG&E Corporation owns, directly or indirectly, at least 80% of the outstanding common stock and at least 70% of the outstanding voting capital stock of the Utility.
Commercial Paper Programs
The borrowings from PG&E Corporation’s and the Utility’s commercial paper programs are used primarily to fund temporary financing needs. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities. The commercial paper may have maturities up to 365 days and ranks equally with PG&E Corporation’s and the Utility’s other unsubordinated and unsecured indebtedness. Commercial paper notes are sold at an interest rate dictated by the market at the time of issuance. For 2017, the average yield on outstanding PG&E Corporation and Utility commercial paper was 1.29% and 1.11%, respectively.
Other Short-term Borrowings
In February 2017, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016, matured and was repaid. Additionally, in February 2017, the Utility entered into a $250 million floating rate unsecured term loan maturing on February 22, 2018. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.
In November 2017, the Utility issued $500 million in unsecured floating rate senior notes that mature on November 28, 2018. The proceeds were used towards repayment of the $250 million unsecured floating rate senior notes due November 30, 2017 and the balance was used to support the Northern California wildfire response efforts.
|
NOTE 6: PREFERRED STOCK
PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock. PG&E Corporation does not have any preferred stock outstanding.
The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock. At December 31, 2017 and December 31, 2016, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. All outstanding preferred stock has a $25 par value.
At December 31, 2017, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share. The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2017, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.
On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility determined to suspend quarterly cash dividends on the Utility’s preferred stock, beginning with the three-month period ending January 31, 2018, due to uncertainty related to causes and potential liabilities associated with the October 2017 Northern California wildfires. See “Northern California Wildfires” in Note 13 below.)
Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid $14 million of dividends on preferred stock in each of 2017, 2016, and 2015.
|
NOTE 8: INCOME TAXES
PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes. The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities. Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.
PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit.
Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.
PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.
The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:
PG&E Corporation |
| Utility | |||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||
(in millions) | 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | ||||||||||||||||||
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Federal | $ | (10) |
| $ | (105) |
| $ | (89) |
| $ | 61 |
| $ | (105) |
| $ | (88) | ||||||||||||
State |
| 48 |
|
| (70) |
|
| 11 |
|
| 50 |
|
| (66) |
|
| 6 | ||||||||||||
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Federal |
| 481 |
|
| 218 |
|
| 131 |
|
| 326 |
|
| 229 |
|
| 136 | ||||||||||||
State |
| 6 |
|
| 16 |
|
| (76) |
|
| 4 |
|
| 16 |
|
| (69) | ||||||||||||
Tax credits |
| (14) |
|
| (4) |
|
| (4) |
|
| (14) |
|
| (4) |
|
| (4) | ||||||||||||
Income tax provision (benefit) | $ | 511 |
| $ | 55 |
| $ | (27) |
| $ | 427 |
| $ | 70 |
| $ | (19) | ||||||||||||
The following table describes net deferred income tax liabilities:
PG&E Corporation |
| Utility | |||||||||||
| Year Ended December 31, | ||||||||||||
(in millions) | 2017 |
| 2016 |
| 2017 |
| 2016 | ||||||
Deferred income tax assets: |
|
|
|
|
|
|
|
|
|
|
| ||
Tax carryforwards |
| 830 |
|
| 1,851 |
|
| 736 |
|
| 1,596 | ||
Compensation |
| 274 |
|
| 277 |
|
| 205 |
|
| 199 | ||
Income tax regulatory liability (1) |
| 286 |
|
| - |
|
| 286 |
|
| - | ||
Other (2) |
| 185 |
|
| 186 |
|
| 194 |
|
| 203 | ||
Total deferred income tax assets | $ | 1,575 |
| $ | 2,314 |
| $ | 1,421 |
| $ | 1,998 | ||
Deferred income tax liabilities: |
|
|
|
|
|
|
|
|
|
|
| ||
Property related basis differences |
| 7,269 |
|
| 10,429 |
|
| 7,256 |
|
| 10,411 | ||
Income tax regulatory asset (1) |
| - |
|
| 1,572 |
|
| - |
|
| 1,572 | ||
Other (3) |
| 128 |
|
| 526 |
|
| 128 |
|
| 525 | ||
Total deferred income tax liabilities | $ | 7,397 |
| $ | 12,527 |
| $ | 7,384 |
| $ | 12,508 | ||
Total net deferred income tax liabilities | $ | 5,822 |
| $ | 10,213 |
| $ | 5,963 |
| $ | 10,510 | ||
|
|
|
|
|
|
|
|
|
|
|
| ||
(1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (For more information see Note 3 above and “Tax Cuts and Jobs Act of 2017” below.)
(2) Amounts include benefits, environmental reserve, and customer advances for construction.
(3) Amounts primarily relate to regulatory balancing accounts.
The following table reconciles income tax expense at the federal statutory rate to the income tax provision:
PG&E Corporation |
| Utility | |||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||
| 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | ||||||||||||||||
Federal statutory income tax rate | 35.0 | % |
| 35.0 | % |
| 35.0 | % |
| 35.0 | % |
| 35.0 | % |
| 35.0 | % | ||||||||||
Increase (decrease) in income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
tax rate resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
State income tax (net of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
federal benefit) (1) | 1.5 |
|
| (2.5) |
|
| (4.9) |
|
| 1.6 |
|
| (2.2) |
|
| (4.8) |
| ||||||||||
Effect of regulatory treatment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
of fixed asset differences (2) | (16.5) |
|
| (23.7) |
|
| (33.6) |
|
| (16.8) |
|
| (23.4) |
|
| (33.7) |
| ||||||||||
Tax credits | (1.1) |
|
| (0.8) |
|
| (1.3) |
|
| (1.1) |
|
| (0.8) |
|
| (1.3) |
| ||||||||||
Benefit of loss carryback | - |
|
| (1.1) |
|
| (1.5) |
|
| - |
|
| (1.1) |
|
| (1.5) |
| ||||||||||
Non deductible penalties (3) | 0.4 |
|
| 0.8 |
|
| 4.3 |
|
| 0.4 |
|
| 0.8 |
|
| 4.3 |
| ||||||||||
Tax Reform Adjustment (4) | 6.8 |
|
| - |
|
| - |
|
| 3.0 |
|
| - |
|
| - |
| ||||||||||
Other, net (5) | (2.5) |
|
| (3.9) |
|
| (1.1) |
|
| (2.0) |
|
| (3.5) |
|
| (0.2) |
| ||||||||||
Effective tax rate | 23.6 | % |
| 3.8 | % |
| (3.1) | % |
| 20.1 | % |
| 4.8 | % |
| (2.2) | % | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
(1) Includes the effect of state flow-through ratemaking treatment. In 2016 and 2015, amounts reflect an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions. The 2017 amount reflects an agreement with the IRS on a 2013 audit related to generation repairs deductions.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacted 2016 and 2017. All amounts are impacted by the level of income before income taxes. The 2014 GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.
(3) Primarily represents the effects of a non-tax deductible penalty associated with the Butte fire for 2017, non-tax deductible fines and penalties associated with the natural gas distribution facilities record-keeping decision for 2016 and the effects of the San Bruno Penalty Decision for 2015.
(4) Represents the required adjustment to deferred tax balances, due to the federal income tax rate being lowered from 35% to 21% beginning in 2018 as a result of the enactment of the Tax Act.
(5) These amounts primarily represent the impact of tax audit settlements.
Unrecognized Tax Benefits
The following table reconciles the changes in unrecognized tax benefits:
PG&E Corporation |
| Utility | |||||||||||||||
(in millions) | 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | ||||||
Balance at beginning of year | $ | 388 |
| $ | 468 |
| $ | 713 |
| $ | 382 |
| $ | 462 |
| $ | 707 |
Additions for tax position taken |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
during a prior year |
| - |
|
| - |
|
| 40 |
|
| - |
|
| - |
|
| 40 |
Reductions for tax position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
taken during a prior year |
| (71) |
|
| (77) |
|
| (349) |
|
| (71) |
|
| (77) |
|
| (349) |
Additions for tax position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
taken during the current year |
| 48 |
|
| 56 |
|
| 64 |
|
| 48 |
|
| 56 |
|
| 64 |
Settlements |
| (14) |
|
| (59) |
|
| - |
|
| (8) |
|
| (59) |
|
| - |
Expiration of statute |
| (3) |
|
| - |
|
| - |
|
| (3) |
|
| - |
|
| - |
Balance at end of year | $ | 349 |
| $ | 388 |
| $ | 468 |
| $ | 349 |
| $ | 382 |
| $ | 462 |
The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2017 for PG&E Corporation and the Utility was $21 million.
PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of several matters, including audits. As of December 31, 2017, it is reasonably possible that unrecognized tax benefits will decrease by approximately $20 million within the next 12 months.
Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2017, 2016, and 2015, these amounts were immaterial.
Tax Cuts and Jobs Act of 2017
On December 22, 2017, the U.S. government enacted expansive tax legislation commonly referred to as the Tax Act. Among other provisions, the Tax Act reduces the federal income tax rate from 35 percent to 21 percent beginning on January 1, 2018 and eliminated bonus depreciation for utilities. The Tax Act required PG&E Corporation and the Utility to re-measure all existing deferred income tax assets and liabilities to reflect the reduction in the federal tax rate. PG&E Corporation and the Utility have made reasonable estimates to reflect the impacts of the Tax Act and recorded provisional amounts, in accordance with rules issued by the SEC in Staff Accounting Bulletin No. 118, for the re-measurement of deferred tax balances as of December 31, 2017.
During the three months and year ended December 31, 2017, PG&E Corporation, on a consolidated basis, recorded a one-time provisional tax expense of $147 million to reflect the transitional impacts of the Tax Act. Of this amount, $83 million is attributable to the re-measurement of PG&E Corporation’s net deferred tax asset comprised primarily of net operating loss carry-forwards and compensation-related items. The remaining $64 million is related to the re-measurement of the Utility’s deferred taxes not reflected in authorized revenue requirements, such as of disallowed plant. The Utility also recorded a provisional $5.7 billion re-measurement of its deferred tax balances (related to flow-through and normalized timing differences for plant-related items) which was offset by a change from a net deferred income tax regulatory asset to a net regulatory liability. The deferred income tax regulatory liability will be refunded to customers over the regulatory lives of the related assets.
The final transition impacts of the Tax Act may differ from the above recorded amounts, possibly materially, due to, among other things, regulatory decisions from the CPUC that could differ from the Utility’s determination of how the impacts of the Tax Act are allocated between customers and shareholders. In addition, while PG&E Corporation and the Utility were able to make reasonable estimates of the impact of the reduction in federal tax rate and the elimination of bonus depreciation due to the enactment of the Tax Act; changes in interpretations, guidance on legislative intent, and any changes in accounting standards for income taxes in response to the Tax Act could impact the recorded amounts. PG&E Corporation and the Utility will finalize and record any adjustments related to the Tax Act within the one year measurement period provided under Staff Accounting Bulletin No. 118.
Tax Settlements
PG&E Corporation’s tax returns have been accepted through 2015 except for a few matters, the most significant of which relates to deductible repair costs for gas transmission and distribution lines of business. In February 2017, the Joint Committee of Taxation approved PG&E Corporation’s settlement with the IRS related to deductible electric transmission and distribution repairs for the 2011 and 2012 tax years. The agreement provided that the methodology used in determining the deductible amount should be followed for all subsequent periods, absent any material change in facts. In November 2017, PG&E Corporation reached an agreement with the IRS on deductible generation repairs for the 2013 and 2014 tax years. The IRS may issue guidance in 2018 that clarifies which repair costs are deductible for the natural gas transmission and distribution lines of business.
Tax years after 2008 remain subject to examination by the state of California.
2015 Gas Transmission and Storage Rate Case
The final phase two decision reduced rate base by the full amount of the disallowed capital expenditures but did not remove the associated deferred taxes, which the Utility believes constitutes a normalization violation. In the final decision, the CPUC authorized the Utility to establish a Tax Normalization Memorandum Account to track relevant costs and clarified that it is the CPUC’s intention that the Utility comply with normalization rules and avoid the potential adverse consequences of a normalization violation. The CPUC allowed the Utility to seek a ruling from the IRS and the Utility filed the ruling request with the IRS on April 10, 2017. On October 5, 2017, the IRS issued a private letter ruling indicating the final decision rate base reduction was inconsistent with the IRS tax normalization requirements. As a result of the IRS private letter ruling, the Utility filed an advice letter with the CPUC on December 11, 2017, requesting a rate base adjustment of $7 million, $28 million, $49 million, and $61 million, in 2015, 2016, 2017, and 2018, respectively.
Carryforwards
The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:
December 31, |
| Expiration | ||
(in millions) | 2017 |
| Year | |
Federal: |
|
|
|
|
Net operating loss carryforward | $ | 4,233 |
| 2031 - 2036 |
Tax credit carryforward |
| 103 |
| 2029 - 2036 |
Charitable contribution loss carryforward |
| 93 |
| 2019 - 2021 |
|
|
|
|
|
State: |
|
|
|
|
Net operating loss carryforward | $ | - |
| N/A |
Tax credit carryforward |
| 13 |
| Various |
Charitable contribution loss carryforward |
| 24 |
| 2020 - 2021 |
PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2017 for these tax attributes.
|
NOTE 9: DERIVATIVES
Use of Derivative Instruments
The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs.
Derivatives are presented in the Utility’s Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.
Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.
The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Consolidated Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting.
Volume of Derivative Activity
At December 31, 2017 and 2016, respectively, the volumes of the Utility’s outstanding derivatives were as follows:
|
|
| Contract Volume | |||
Underlying Product |
| Instruments |
| 2017 |
| 2016 |
Natural Gas(1) (MMBtus(2)) |
| Forwards and Swaps |
| 228,768,745 |
| 323,301,331 |
|
| Options |
| 60,736,806 |
| 96,602,785 |
Electricity (Megawatt-hours) |
| Forwards and Swaps |
| 2,872,013 |
| 3,287,397 |
|
| Congestion Revenue Rights(3) |
| 312,272,177 |
| 278,143,281 |
|
|
|
|
|
|
|
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.
Presentation of Derivative Instruments in the Financial Statements
At December 31, 2017, the Utility’s outstanding derivative balances were as follows:
Commodity Risk | |||||||||||
| Gross Derivative |
|
|
|
|
| Total Derivative | ||||
(in millions) | Balance |
| Netting |
| Cash Collateral |
| Balance | ||||
Current assets – other | $ | 30 |
| $ | (3) |
| $ | 10 |
| $ | 37 |
Other noncurrent assets – other |
| 103 |
|
| (1) |
|
| - |
|
| 102 |
Current liabilities – other |
| (47) |
|
| 3 |
|
| 13 |
|
| (31) |
Noncurrent liabilities – other |
| (66) |
|
| 1 |
|
| 8 |
|
| (57) |
Total commodity risk | $ | 20 |
| $ | - |
| $ | 31 |
| $ | 51 |
At December 31, 2016, the Utility’s outstanding derivative balances were as follows:
Commodity Risk | |||||||||||
| Gross Derivative |
|
|
|
|
| Total Derivative | ||||
(in millions) | Balance |
| Netting |
| Cash Collateral |
| Balance | ||||
Current assets – other | $ | 91 |
| $ | (10) |
| $ | 1 |
| $ | 82 |
Other noncurrent assets – other |
| 149 |
|
| (9) |
|
| - |
|
| 140 |
Current liabilities – other |
| (48) |
|
| 10 |
|
| - |
|
| (38) |
Noncurrent liabilities – other |
| (101) |
|
| 9 |
|
| 3 |
|
| (89) |
Total commodity risk | $ | 91 |
| $ | - |
| $ | 4 |
| $ | 95 |
Gains and losses associated with price risk management activities were recorded as follows:
Commodity Risk | ||||||||
| For the year ended December 31, | |||||||
(in millions) | 2017 |
| 2016 |
| 2015 | |||
Unrealized gain/(loss) - regulatory assets and liabilities(1) | $ | (71) |
| $ | 64 |
| $ | (6) |
Realized loss - cost of electricity(2) |
| (27) |
|
| (53) |
|
| (14) |
Realized loss - cost of natural gas(2) |
| (5) |
|
| (18) |
|
| (10) |
Total commodity risk | $ | (103) |
| $ | (7) |
| $ | (30) |
|
|
|
|
|
|
|
|
|
(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.
Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows.
The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At December 31, 2017, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.
The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:
Balance at December 31, | |||||
(in millions) | 2017 |
| 2016 | ||
Derivatives in a liability position with credit risk-related |
|
|
|
|
|
contingencies that are not fully collateralized | $ | (1) |
| $ | (24) |
Related derivatives in an asset position |
| - |
|
| 19 |
Collateral posting in the normal course of business related to |
|
|
|
|
|
these derivatives |
| - |
|
| 4 |
Net position of derivative contracts/additional collateral |
|
|
|
|
|
posting requirements(1) | $ | (1) |
| $ | (1) |
|
|
|
|
|
|
(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies.
|
NOTE 10: FAIR VALUE MEASUREMENTS
PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:
The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.
Fair Value Measurements | ||||||||||||||
| At December 31, 2017 | |||||||||||||
(in millions) | Level 1 |
| Level 2 |
| Level 3 |
| Netting (1) |
| Total | |||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments | $ | 385 |
| $ | - |
| $ | - |
| $ | - |
| $ | 385 |
Nuclear decommissioning trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
| 23 |
|
| - |
|
| - |
|
| - |
|
| 23 |
Global equity securities |
| 1,967 |
|
| - |
|
| - |
|
| - |
|
| 1,967 |
Fixed-income securities |
| 733 |
|
| 562 |
|
| - |
|
| - |
|
| 1,295 |
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| - |
|
| 18 |
Total nuclear decommissioning trusts (2) |
| 2,723 |
|
| 562 |
|
| - |
|
| - |
|
| 3,303 |
Price risk management instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity |
| - |
|
| 3 |
|
| 129 |
|
| 6 |
|
| 138 |
Gas |
| - |
|
| 1 |
|
| - |
|
| - |
|
| 1 |
Total price risk management |
| - |
|
| 4 |
|
| 129 |
|
| 6 |
|
| 139 |
instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rabbi trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-income securities |
| - |
|
| 72 |
|
| - |
|
| - |
|
| 72 |
Life insurance contracts |
| - |
|
| 71 |
|
| - |
|
| - |
|
| 71 |
Total rabbi trusts |
| - |
|
| 143 |
|
| - |
|
| - |
|
| 143 |
Long-term disability trust |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
| 8 |
|
| - |
|
| - |
|
| - |
|
| 8 |
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| - |
|
| 167 |
Total long-term disability trust |
| 8 |
|
| - |
|
| - |
|
| - |
|
| 175 |
TOTAL ASSETS | $ | 3,116 |
| $ | 709 |
| $ | 129 |
| $ | 6 |
| $ | 4,145 |
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price risk management instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity | $ | 10 |
| $ | 15 |
| $ | 87 |
| $ | (25) |
| $ | 87 |
Gas |
| - |
|
| 1 |
|
| - |
|
| - |
|
| 1 |
TOTAL LIABILITIES | $ | 10 |
| $ | 16 |
| $ | 87 |
| $ | (25) |
| $ | 88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $440 million, primarily related to deferred taxes on appreciation of investment value.
Fair Value Measurements | ||||||||||||||
| At December 31, 2016 | |||||||||||||
(in millions) | Level 1 |
| Level 2 |
| Level 3 |
| Netting (1) |
| Total | |||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments | $ | 105 |
| $ | - |
| $ | - |
| $ | - |
| $ | 105 |
Nuclear decommissioning trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
| 9 |
|
| - |
|
| - |
|
| - |
|
| 9 |
Global equity securities |
| 1,724 |
|
| - |
|
| - |
|
| - |
|
| 1,724 |
Fixed-income securities |
| 665 |
|
| 527 |
|
| - |
|
| - |
|
| 1,192 |
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| - |
|
| 14 |
Total nuclear decommissioning trusts (2) |
| 2,398 |
|
| 527 |
|
| - |
|
| - |
|
| 2,939 |
Price risk management instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity |
| 30 |
|
| 18 |
|
| 181 |
|
| (18) |
|
| 211 |
Gas |
| - |
|
| 11 |
|
| - |
|
| - |
|
| 11 |
Total price risk management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
instruments |
| 30 |
|
| 29 |
|
| 181 |
|
| (18) |
|
| 222 |
Rabbi trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-income securities |
| - |
|
| 61 |
|
| - |
|
| - |
|
| 61 |
Life insurance contracts |
| - |
|
| 70 |
|
| - |
|
| - |
|
| 70 |
Total rabbi trusts |
| - |
|
| 131 |
|
| - |
|
| - |
|
| 131 |
Long-term disability trust |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
| 8 |
|
| - |
|
| - |
|
| - |
|
| 8 |
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| - |
|
| 170 |
Total long-term disability trust |
| 8 |
|
| - |
|
| - |
|
| - |
|
| 178 |
TOTAL ASSETS | $ | 2,541 |
| $ | 687 |
| $ | 181 |
| $ | (18) |
| $ | 3,575 |
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price risk management instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity | $ | 9 |
| $ | 12 |
| $ | 126 |
| $ | (21) |
| $ | 126 |
Gas |
| - |
|
| 2 |
|
| - |
|
| (1) |
|
| 1 |
TOTAL LIABILITIES | $ | 9 |
| $ | 14 |
| $ | 126 |
| $ | (22) |
| $ | 127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.
Valuation Techniques
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed.
Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the years ended December 31, 2017 and 2016.
Trust Assets
Assets Measured at Fair Value
In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.
Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.
Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.
Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.
Assets Measured at NAV Using Practical Expedient
Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.
Price Risk Management Instruments
Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.
Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded and over-the-counter options are valued using observable market data and market-corroborated data and are classified as Level 2.
Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.
The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.
Level 3 Measurements and Sensitivity Analysis
The Utility’s market and credit risk management function, which reports to the Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.
Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 9 above.)
| Fair Value at |
|
|
|
|
|
|
| |||||||||||||
(in millions) |
| At December 31, 2017 |
| Valuation |
| Unobservable |
|
|
| ||||||||||||
Fair Value Measurement |
| Assets |
| Liabilities |
| Technique |
| Input |
| Range (1) | |||||||||||
Congestion revenue rights |
| $ | 129 |
| $ | 24 |
| Market approach |
| CRR auction prices |
| $ | (16.03) - 11.99 | ||||||||
Power purchase agreements |
| $ | - |
| $ | 63 |
| Discounted cash flow |
| Forward prices |
| $ | 18.81 - 38.80 | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
| Fair Value at |
|
|
|
|
|
|
| |||||
(in millions) |
| At December 31, 2016 |
| Valuation |
| Unobservable |
|
|
| ||||
Fair Value Measurement |
| Assets |
| Liabilities |
| Technique |
| Input |
| Range (1) | |||
Congestion revenue rights |
| $ | 181 |
| $ | 35 |
| Market approach |
| CRR auction prices |
| $ | (11.88) - 6.93 |
Power purchase agreements |
| $ | - |
| $ | 91 |
| Discounted cash flow |
| Forward prices |
| $ | 18.07 - 38.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Represents price per megawatt-hour
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2017 and 2016, respectively:
Price Risk Management Instruments | |||||||
(in millions) | 2017 |
| 2016 | ||||
Asset (liability) balance as of January 1 | $ | 55 |
| $ | 89 | ||
Net realized and unrealized gains: |
|
|
|
|
| ||
Included in regulatory assets and liabilities or balancing accounts (1) |
| (13) |
|
| (34) | ||
Asset (liability) balance as of December 31 | $ | 42 |
| $ | 55 | ||
|
|
|
|
|
| ||
(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
Financial Instruments
PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:
The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
At December 31, | |||||||||||||
| 2017 |
| 2016 | ||||||||||
(in millions) | Carrying Amount |
| Level 2 Fair Value |
| Carrying Amount |
| Level 2 Fair Value | ||||||
Debt (Note 4) |
|
|
|
|
|
|
|
|
|
|
| ||
PG&E Corporation | $ | 350 |
| $ | 350 |
| $ | 348 |
| $ | 352 | ||
Utility |
| 17,090 |
|
| 19,128 |
|
| 15,813 |
|
| 17,790 | ||
Available for Sale Investments
The following table provides a summary of available-for-sale investments:
|
|
| Total |
|
| Total |
|
|
| ||
| Amortized |
|
| Unrealized |
|
| Unrealized |
|
| Total Fair | |
(in millions) | Cost |
|
| Gains |
|
| Losses |
|
| Value | |
As of December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts |
|
|
|
|
|
|
|
|
|
|
|
Short-term investments | $ | 23 |
| $ | - |
| $ | - |
| $ | 23 |
Global equity securities |
| 524 |
|
| 1,463 |
|
| (2) |
|
| 1,985 |
Fixed-income securities |
| 1,252 |
|
| 51 |
|
| (8) |
|
| 1,295 |
Total (1) | $ | 1,799 |
| $ | 1,514 |
| $ | (10) |
| $ | 3,303 |
As of December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts |
|
|
|
|
|
|
|
|
|
|
|
Short-term investments | $ | 9 |
| $ | - |
| $ | - |
| $ | 9 |
Global equity securities |
| 584 |
|
| 1,157 |
|
| (3) |
|
| 1,738 |
Fixed-income securities |
| 1,156 |
|
| 48 |
|
| (12) |
|
| 1,192 |
Total (1) | $ | 1,749 |
| $ | 1,205 |
| $ | (15) |
| $ | 2,939 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) Represents amounts before deducting $440 million and $333 million at December 31, 2017 and 2016, respectively, primarily related to deferred taxes on appreciation of investment value.
The fair value of fixed-income securities by contractual maturity is as follows:
As of | ||
(in millions) | December 31, 2017 | |
Less than 1 year | $ | 41 |
1–5 years |
| 414 |
5–10 years |
| 352 |
More than 10 years |
| 488 |
Total maturities of fixed-income securities | $ | 1,295 |
The following table provides a summary of activity for the fixed-income and equity securities:
2017 |
| 2016 |
| 2015 | ||||
(in millions) |
|
|
|
|
|
|
|
|
Proceeds from sales and maturities of nuclear decommissioning |
|
|
|
|
|
|
|
|
investments | $ | 1,291 |
| $ | 1,295 |
| $ | 1,268 |
Gross realized gains on securities held as available-for-sale |
| 53 |
|
| 18 |
|
| 55 |
Gross realized losses on securities held as available-for-sale |
| (11) |
|
| (26) |
|
| (37) |
|
NOTE 11: EMPLOYEE BENEFIT PLANS
Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”). The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. Based upon current assumptions and available information, the Utility’s minimum funding requirements related to its pension plans is zero.
PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.
Change in Plan Assets, Benefit Obligations, and Funded Status
The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2017 and 2016:
2017 |
| 2016 | |||||
Change in plan assets: |
|
|
| ||||
Fair value of plan assets at beginning of year | $ | 14,729 |
| $ | 13,745 | ||
Actual return on plan assets |
| 2,380 |
|
| 1,358 | ||
Company contributions |
| 335 |
|
| 334 | ||
Benefits and expenses paid |
| (792) |
|
| (708) | ||
Fair value of plan assets at end of year | $ | 16,652 |
| $ | 14,729 | ||
|
|
|
|
|
| ||
Change in benefit obligation: |
|
|
|
|
| ||
Benefit obligation at beginning of year | $ | 17,305 |
| $ | 16,299 | ||
Service cost for benefits earned |
| 472 |
|
| 453 | ||
Interest cost |
| 714 |
|
| 715 | ||
Actuarial (gain) loss |
| 1,048 |
|
| 637 | ||
Plan amendments |
| 10 |
|
| (91) | ||
Benefits and expenses paid |
| (792) |
|
| (708) | ||
Benefit obligation at end of year (1) | $ | 18,757 |
| $ | 17,305 | ||
|
|
|
|
|
| ||
Funded Status: |
|
|
|
|
| ||
Current liability | $ | (7) |
| $ | (7) | ||
Noncurrent liability |
| (2,098) |
|
| (2,569) | ||
Net liability at end of year | $ | (2,105) |
| $ | (2,576) | ||
|
|
|
|
|
| ||
(1) PG&E Corporation’s accumulated benefit obligation was $16.8 billion and $15.6 billion at December 31, 2017 and 2016, respectively.
Postretirement Benefits Other than Pensions
2017 |
| 2016 | |||||
Change in plan assets: |
|
|
|
|
| ||
Fair value of plan assets at beginning of year | $ | 2,173 |
| $ | 2,035 | ||
Actual return on plan assets |
| 298 |
|
| 167 | ||
Company contributions |
| 33 |
|
| 52 | ||
Plan participant contribution |
| 87 |
|
| 85 | ||
Benefits and expenses paid |
| (171) |
|
| (166) | ||
Fair value of plan assets at end of year | $ | 2,420 |
| $ | 2,173 | ||
|
|
|
|
|
| ||
Change in benefit obligation: |
|
|
|
|
| ||
Benefit obligation at beginning of year | $ | 1,877 |
| $ | 1,766 | ||
Service cost for benefits earned |
| 59 |
|
| 52 | ||
Interest cost |
| 77 |
|
| 76 | ||
Actuarial (gain) loss |
| (49) |
|
| 11 | ||
Plan amendments |
| - |
|
| 37 | ||
Benefits and expenses paid |
| (157) |
|
| (153) | ||
Federal subsidy on benefits paid |
| 3 |
|
| 3 | ||
Plan participant contributions |
| 87 |
|
| 85 | ||
Benefit obligation at end of year | $ | 1,897 |
| $ | 1,877 | ||
|
|
|
|
|
| ||
Funded Status: (1) |
|
|
|
|
| ||
Noncurrent asset | $ | 553 |
| $ | 368 | ||
Noncurrent liability |
| (30) |
|
| (72) | ||
Net asset at end of year | $ | 523 |
| $ | 296 | ||
|
|
|
|
|
| ||
(1) At December 31, 2017 and 2016, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Components of Net Periodic Benefit Cost
Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:
2017 |
| 2016 |
| 2015 | ||||||||
Service cost | $ | 472 |
| $ | 453 |
| $ | 479 | ||||
Interest cost |
| 714 |
|
| 715 |
|
| 673 | ||||
Expected return on plan assets |
| (770) |
|
| (828) |
|
| (873) | ||||
Amortization of prior service cost |
| (7) |
|
| 8 |
|
| 15 | ||||
Amortization of net actuarial loss |
| 22 |
|
| 24 |
|
| 10 | ||||
Net periodic benefit cost |
| 431 |
|
| 372 |
|
| 304 | ||||
Less: transfer to regulatory account (1) |
| (92) |
|
| (34) |
|
| 34 | ||||
Total expense recognized | $ | 339 |
| $ | 338 |
| $ | 338 | ||||
|
|
|
|
|
|
|
|
| ||||
(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.
Postretirement Benefits Other than Pensions
2017 |
| 2016 |
| 2015 | ||||||||
Service cost | $ | 59 |
| $ | 52 |
| $ | 55 | ||||
Interest cost |
| 77 |
|
| 76 |
|
| 71 | ||||
Expected return on plan assets |
| (97) |
|
| (107) |
|
| (112) | ||||
Amortization of prior service cost |
| 15 |
|
| 15 |
|
| 19 | ||||
Amortization of net actuarial loss |
| 4 |
|
| 4 |
|
| 4 | ||||
Net periodic benefit cost | $ | 58 |
| $ | 40 |
| $ | 37 | ||||
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Components of Accumulated Other Comprehensive Income
PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).
The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2018 are as follows:
|
|
| |||
Pension Plan |
| PBOP Plans | |||
Unrecognized prior service cost | $ | (6) |
| $ | 14 |
Unrecognized net loss |
| 5 |
|
| (5) |
Total | $ | (1) |
| $ | 9 |
There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility.
Valuation Assumptions
The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs. The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit cost.
Pension Plan |
| PBOP Plans | |||||||||||||||
| December 31, |
| December 31, | ||||||||||||||
| 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | ||||||
Discount rate | 3.64 | % |
| 4.11 | % |
| 4.37 | % |
| 3.60- 3.67 | % |
| 4.05 - 4.19 | % |
| 4.27 - 4.48 | % |
Rate of future compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
increases | 3.90 | % |
| 4.00 | % |
| 4.00 | % |
| - |
|
| - |
|
| - |
|
Expected return on plan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
assets | 6.20 | % |
| 5.30 | % |
| 6.10 | % |
| 3.30 - 7.10 | % |
| 2.80 - 6.00 | % |
| 3.20 - 6.60 | % |
One-Percentage-Point |
| One-Percentage-Point | |||
(in millions) | Increase |
| Decrease | ||
Effect on postretirement benefit obligation | $ | 128 |
| $ | (129) |
Effect on service and interest cost |
| 9 |
|
| (10) |
Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 6.2% compares to a ten-year actual return of 7.8%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 623 Aa-grade non-callable bonds at December 31, 2017. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.
Investment Policies and Strategies
The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.
The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return. Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include commodities futures, global REITS, and global listed infrastructure equities. Absolute return investments include hedge fund portfolios.
Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments.
The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
Pension Plan |
| PBOP Plans | |||||||||||||||||||||||||
| 2018 |
| 2017 |
| 2016 |
| 2018 |
| 2017 |
| 2016 | ||||||||||||||||
Global equity | 29 | % |
| 27 | % |
| 25 | % |
| 33 | % |
| 32 | % |
| 32 | % | ||||||||||
Absolute return | 5 | % |
| 5 | % |
| 5 | % |
| 3 | % |
| 3 | % |
| 3 | % | ||||||||||
Real assets | 8 | % |
| 10 | % |
| 10 | % |
| 6 | % |
| 7 | % |
| 7 | % | ||||||||||
Fixed income | 58 | % |
| 58 | % |
| 60 | % |
| 58 | % |
| 58 | % |
| 58 | % | ||||||||||
Total | 100 | % |
| 100 | % |
| 100 | % |
| 100 | % |
| 100 | % |
| 100 | % | ||||||||||
PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.
Fair Value Measurements
The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2017 and 2016.
Fair Value Measurements | |||||||||||||||||||||||||||||||||||||||
| At December 31, | ||||||||||||||||||||||||||||||||||||||
| 2017 |
| 2016 | ||||||||||||||||||||||||||||||||||||
(in millions) | Level 1 |
| Level 2 |
| Level 3 |
| Total |
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||||||||||||||||||||||
Pension Plan: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Short-term investments | $ | 287 |
| $ | 424 |
| $ | - |
| $ | 711 |
| $ | 364 |
| $ | 369 |
| $ | - |
| $ | 733 | ||||||||||||||||
Global equity |
| 1,292 |
|
| - |
|
| - |
|
| 1,292 |
|
| 996 |
|
| - |
|
| - |
|
| 996 | ||||||||||||||||
Real assets |
| 499 |
|
| - |
|
| - |
|
| 499 |
|
| 610 |
|
| - |
|
| - |
|
| 610 | ||||||||||||||||
Fixed-income |
| 1,916 |
|
| 5,520 |
|
| 4 |
|
| 7,440 |
|
| 1,754 |
|
| 4,774 |
|
| 5 |
|
| 6,533 | ||||||||||||||||
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| 6,818 |
|
| - |
|
| - |
|
| - |
|
| 5,950 | ||||||||||||||||
Total | $ | 3,994 |
| $ | 5,944 |
| $ | 4 |
| $ | 16,760 |
| $ | 3,724 |
| $ | 5,143 |
| $ | 5 |
| $ | 14,822 | ||||||||||||||||
PBOP Plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Short-term investments | $ | 31 |
| $ | - |
| $ | - |
| $ | 31 |
| $ | 33 |
| $ | - |
| $ | - |
| $ | 33 | ||||||||||||||||
Global equity |
| 141 |
|
| - |
|
| - |
|
| 141 |
|
| 115 |
|
| - |
|
| - |
|
| 115 | ||||||||||||||||
Real assets |
| 55 |
|
| - |
|
| - |
|
| 55 |
|
| 70 |
|
| - |
|
| - |
|
| 70 | ||||||||||||||||
Fixed-income |
| 163 |
|
| 757 |
|
| - |
|
| 920 |
|
| 150 |
|
| 656 |
|
| - |
|
| 806 | ||||||||||||||||
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| 1,281 |
|
| - |
|
| - |
|
| - |
|
| 1,153 | ||||||||||||||||
Total | $ | 390 |
| $ | 757 |
| $ | - |
| $ | 2,428 |
| $ | 368 |
| $ | 656 |
| $ | - |
| $ | 2,177 | ||||||||||||||||
Total plan assets at fair value |
|
|
|
|
|
|
|
|
| $ | 19,188 |
|
|
|
|
|
|
|
|
|
| $ | 16,999 | ||||||||||||||||
In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $116 million and $97 million at December 31, 2017 and 2016, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable.
Valuation Techniques
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above. All investments that are valued using a NAV per share can be redeemed quarterly with a notice not to exceed 90 days.
Short-Term Investments
Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.
Global Equity
The global equity category includes investments in common stock and equity-index futures. Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted prices in active markets for identical securities. Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.
Real Assets
The real asset category includes portfolios of commodity futures, global REITS and global listed infrastructure equities. The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.
Fixed-Income
Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.
Assets Measured at NAV Using Practical Expedient
Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which the investments may be redeemed.
Transfers Between Levels
Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. No material transfers between levels occurred in the years ended December 31, 2017 and 2016.
Level 3 Reconciliation
| ||
(in millions) | Fixed- | |
For the year ended December 31, 2017 | Income | |
Balance at beginning of year | $ | 5 |
Actual return on plan assets: |
|
|
Relating to assets still held at the reporting date |
| (1) |
Relating to assets sold during the period |
| - |
Purchases, issuances, sales, and settlements: |
|
|
Purchases |
| 3 |
Settlements |
| (3) |
Balance at end of year | $ | 4 |
|
|
|
|
| |
(in millions) | Fixed- | |
For the year ended December 31, 2016 | Income | |
Balance at beginning of year | $ | 3 |
Actual return on plan assets: |
|
|
Relating to assets still held at the reporting date |
| 3 |
Relating to assets sold during the period |
| - |
Purchases, issuances, sales, and settlements: |
|
|
Purchases |
| - |
Settlements |
| (1) |
Balance at end of year | $ | 5 |
There were no material transfers out of Level 3 in 2017 and 2016.
Cash Flow Information
Employer Contributions
PG&E Corporation and the Utility contributed $335 million to the pension benefit plans and $33 million to the other benefit plans in 2017. These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2017. The Utility’s pension benefits met all the funding requirements under the Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $24 million to the pension plan and other postretirement benefit plans, respectively, for 2018.
Benefits Payments and Receipts
As of December 31, 2017, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
Pension |
| PBOP |
| Federal | ||||||||
(in millions) | Plan |
| Plans |
| Subsidy | |||||||
2018 | $ | 712 |
| $ | 83 |
| $ | (8) | ||||
2019 |
| 811 |
|
| 87 |
|
| (9) | ||||
2020 |
| 850 |
|
| 91 |
|
| (9) | ||||
2021 |
| 886 |
|
| 95 |
|
| (10) | ||||
2022 |
| 920 |
|
| 100 |
|
| (3) | ||||
Thereafter in the succeeding five years |
| 5,002 |
|
| 508 |
|
| (15) | ||||
There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above. There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.
Retirement Savings Plan
PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants. Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $103 million, $97 million, and $89 million in 2017, 2016, and 2015, respectively.
There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.
|
NOTE 12: RELATED PARTY AGREEMENTS AND TRANSACTIONS
The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.
The Utility’s significant related party transactions were:
Year Ended December 31, | ||||||||
(in millions) | 2017 |
| 2016 |
| 2015 | |||
Utility revenues from: |
|
|
|
|
| |||
Administrative services provided to PG&E Corporation | $ | 8 |
| $ | 7 |
| $ | 6 |
Utility expenses from: |
|
|
|
|
|
|
|
|
Administrative services received from PG&E Corporation | $ | 65 |
| $ | 74 |
| $ | 53 |
Utility employee benefit due to PG&E Corporation |
| 73 |
|
| 91 |
|
| 82 |
At December 31, 2017 and 2016, the Utility had receivables of $20 million and $18 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $22 million and $22 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.
|
NOTE 13: CONTINGENCIES AND COMMITMENTS
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation has financial commitments described in “Other Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.
Enforcement and Litigation Matters
Northern California Wildfires
Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City. According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in California that, in total, burned over 245,000 acres, resulted in 43 fatalities, and destroyed an estimated 8,900 structures. Subsequently, the number of fatalities increased to 44.
The Utility incurred $219 million in costs for service restoration and repair to the Utility’s facilities (including $97 million in capital expenditures) through December 31, 2017 in connection with these fires. While the Utility believes that such costs are recoverable through CEMA, its CEMA requests are subject to CPUC approval. The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to recover such costs.
The fires are being investigated by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the ways that they progressed. The CPUC’s SED also is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities, including fire departments, may also be investigating certain of the fires. (For example, on February 3, 2018, it was reported that investigators with the Santa Rosa Fire Department had completed their investigation of two small fires that reportedly destroyed two homes and damaged one outbuilding and had concluded that the Utility’s facilities, along with high wind and other factors, contributed to those fires.) It is uncertain when the investigations will be complete and whether Cal Fire will release any preliminary findings before its investigation is complete.
As of January 31, 2018, the Utility had submitted 22 electric incident reports to the CPUC associated with the Northern California wildfires where Cal Fire has identified a site as potentially involving the Utility’s facilities in its investigation and the property damage associated with each incident exceeded $50,000. The information contained in these reports is factual and preliminary, and does not reflect a determination of the causes of the fires. The investigations into the fires are ongoing.
If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefitted from such undertaking and based on the assumption that utilities have the ability to recover these costs from their customers. Further, courts could determine that the doctrine of inverse condemnation applies even in the absence of an open CPUC proceeding for cost recovery, or before a potential cost recovery decision is issued by the CPUC. There is no guarantee that the CPUC would authorize cost recovery even if a court decision were to determine that the doctrine of inverse condemnation applies. In addition to such claims for property damage, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, and other damages under other theories of liability, including if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. Further, the Utility could be subject to material fines or penalties if the CPUC or any other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations.
Given the preliminary stages of investigations and the uncertainty as to the causes of the fires, PG&E Corporation and the Utility do not believe a loss is probable at this time. However, it is reasonably possible that facts could emerge through the course of the various investigations that lead PG&E Corporation and the Utility to believe that a loss is probable, resulting in an accrued liability in the future, the amount of which could be material. PG&E Corporation and the Utility currently are unable to reasonably estimate the amount of losses (or range of amounts) that they could incur given the preliminary stages of the investigations and the uncertainty regarding the extent and magnitude of potential damages. On January 31, 2018, the California Department of Insurance issued a press release announcing an update on property losses in connection with the October and December wildfires in California, stating that, as of such date, “insurers have received nearly 45,000 insurance claims totaling more than $11.79 billion in losses,” of which approximately $10 billion relates to statewide claims from the October 2017 wildfires. The remaining amount relates to claims from the Southern California December 2017 wildfires. According to the California Department of Insurance, as of the date of the press release, more than 21,000 homes, 3,200 businesses, and more than 6,100 vehicles, watercraft, farm vehicles, and other equipment were damaged or destroyed by the October 2017 wildfires. PG&E Corporation and the Utility have not independently verified these estimates. The California Department of Insurance did not state in its press release whether it intends to provide updated estimates of losses in the future.
If the Utility’s facilities are determined to be the cause of one or more of the Northern California wildfires, PG&E Corporation and the Utility could be liable for the related property losses and other damages. The California Department of Insurance January 31, 2018 press release reflects insured property losses only. The press release does not account for uninsured losses, interest, attorneys’ fees, fire suppression costs, evacuation costs, medical expenses, personal injury and wrongful death damages or other costs. If the Utility were to be found liable for certain or all of such other costs and expenses, the amount of PG&E Corporation’s and the Utility’s liability could be higher than the approximately $10 billion estimated in respect of the wildfires that occurred in October 2017, depending on the extent of the damage in connection with such fire or fires. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
As of January 31, 2018, PG&E Corporation and the Utility are aware of 111 lawsuits, six of which seek to be certified as class actions, that have been filed against PG&E Corporation and the Utility in the Sonoma, Napa and San Francisco Counties Superior Courts. The lawsuits allege, among other things, negligence, inverse condemnation, trespass, and private nuisance. They principally assert that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the fires. The plaintiffs seek damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees, and other damages. In addition, insurance carriers who have made payments to their insureds for property damage arising out of the fires have filed three subrogation complaints in the San Francisco County Superior Court. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. On October 31, 2017, a group of plaintiffs submitted a petition for coordination to the Chair of the Judicial Council of California and requested coordination of the litigation in the San Francisco Superior Court. On November 9, 2017, PG&E Corporation and the Utility submitted a petition for coordination to the Chair of the Judicial Council of California, and requested separate coordination in the counties in which the fires occurred. On January 4, 2018, the coordination motion judge of the San Francisco Superior Court entered an order granting coordination of the litigation in connection with the Northern California wildfires and recommending that the coordinated proceeding take place in the San Francisco Superior Court. On January 12, 2018, the Judicial Council of California accepted the coordination motion judge’s recommendation and assigned the coordinated proceeding to San Francisco. The first case management conference is scheduled for February 27, 2018.
In addition, two derivative lawsuits for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively. The first lawsuit is filed against the members of the Board of Directors and certain officers of PG&E Corporation. PG&E Corporation is identified as a nominal defendant in that action. The second lawsuit is filed against the members of the Board of Directors, certain former members of the Board of Directors, and certain officers of both PG&E Corporation and the Utility. PG&E Corporation and the Utility are identified as nominal defendants in that action. Motions to consolidate the two lawsuits, appoint lead plaintiffs’ counsel, and enter a case schedule are currently pending.
PG&E Corporation and the Utility expect to be the subject of additional lawsuits in connection with the Northern California wildfires. The wildfire litigation could take a number of years to be resolved because of the complexity of the matters, including the ongoing investigation into the causes of the fires and the growing number of parties and claims involved. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Northern California wildfires in an aggregate amount of approximately $800 million. If the Utility were to be found liable for one or more fires, the Utility’s insurance could be insufficient to cover that liability, depending on the extent of the damage in connection with such fire or fires. Following the Northern California wildfires, PG&E Corporation reinstated its liability insurance in the amount of approximately $630 million for any potential future event.
In addition, it could take a number of years before the Utility’s final liability is known and the Utility could apply for cost recovery. The Utility may be unable to recover costs in excess of insurance through regulatory mechanisms and, even if such recovery is possible, it could take a number of years to resolve and a number of years thereafter to collect. Further, SB 819, introduced in the California Senate in January 2018, if it becomes law, would prohibit utilities from recovering costs in excess of insurance resulting from damages caused by such utilities’ facilities, if the CPUC determines that the utility did not reasonably construct, maintain, manage, control, or operate the facilities. PG&E Corporation and the Utility have considered certain actions that might be taken to attempt to address liquidity needs of the business in such circumstances, but the inability to recover costs in excess of insurance through increases in rates and by collecting such rates in a timely manner, or any negative assessment by the Utility of the likelihood or timeliness of such recovery and collection, could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Litigation and Regulatory Citations in Connection with the Butte Fire
In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.
Third-Party Claims
On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of December 31, 2017, 77 known complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador. The complaints involve approximately 3,770 individual plaintiffs representing approximately 2,030 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. Plaintiffs seek to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability. Plaintiffs also seek punitive damages. As of December 31, 2017, several plaintiffs have dismissed the Utility’s two vegetation management contractors. The number of individual complaints and plaintiffs may still increase in the future, because the statute of limitations for property damages in connection with the Butte fire has not yet expired. (The statute of limitations for personal injury in connection with the Butte fire has expired.) The Utility continues mediating and settling cases.
In addition, on April 13, 2017, Cal Fire filed a complaint with the Superior Court of the State of California, County of Calaveras, seeking to recover $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims. On July 31, 2017, Cal Fire dismissed its complaint against Tree’s, Inc., one of the Utility’s vegetation contractors. The Utility and Cal Fire are currently engaged in a mediation process.
Further, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the Butte fire. Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include costs that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire.
On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. On August 10, 2017, the Court denied the Utility’s motion on the grounds that plaintiffs might be able to show conscious disregard for public safety based on the fact that the Utility relied on contractors to fulfill their contractual obligation to hire and train qualified employees. On August 16, 2017, the Utility filed a writ with the Court of Appeals challenging what the Utility believes is a novel theory of punitive damages liability. The Court of Appeals accepted the writ on September 15, 2017 and ordered the trial court and plaintiffs to show cause why the relief requested by the Utility should not be granted. Briefing on the writ was completed as of January 2, 2018. The Utility is seeking expedited review of the motion.
On June 22, 2017, the Superior Court for the County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applies to the Utility with respect to the Butte fire. The court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding, others could file lawsuits and make similar claims. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases. The motion is set for hearing on March 15, 2018.
Estimated Losses from Third-Party Claims
In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation.
In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent. While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility.
The Utility currently believes that it is probable that it will incur a loss of at least $1.1 billion, increased from the $750 million previously estimated as of December 31, 2016, in connection with the Butte fire. The Utility’s updated estimate resulted primarily from an increase in the number of claims filed against the Utility and experience to date in resolving claims. This amount is based on updated assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages, but does not include punitive damages for which the Utility could be liable. In addition, while this amount includes the Utility’s assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any significant portion of the estimated claims from the OES and the County of Calaveras. The Utility still does not have sufficient information to reasonably estimate the probable loss it may have for these additional claims.
The Utility currently is unable to reasonably estimate the upper end of the range of losses due to the uncertainty of pending legal motions related to the applicability of inverse condemnation and punitive damages and because it has insufficient information on the claims of over 1,000 households and the claims from the OES and the County of Calaveras. The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs, results from the ongoing mediation and settlement process, review of potential claims from the OES and the County of Calaveras, outcomes of future court or jury decisions, and information about damages, including punitive damages, that the Utility could be liable for, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued.
The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
|
| |
Balance at December 31, 2015 | $ | - |
Accrued losses |
| 750 |
Payments(1) |
| (60) |
Balance at December 31, 2016 |
| 690 |
Accrued losses |
| 350 |
Payments(1) |
| (479) |
Balance at December 31, 2017 | $ | 561 |
|
|
|
(1) As of December 31, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $624 million of which
$539 million has been paid by the Utility.
In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $87 million in connection with the Butte fire. For the year ended December 31, 2017, the Utility has incurred legal expenses in connection with the Butte fire of $60 million.
Loss Recoveries
The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of $922 million. The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range. Through December 31, 2017, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, in the year ended December 31, 2017, the Utility received $53 million of reimbursements from the insurance policies of one of its vegetation management contractors (excluded from the table below). Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain.
The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
|
| |
Balance at December 31, 2015 | $ | - |
Accrued insurance recoveries |
| 625 |
Reimbursements |
| (50) |
Balance at December 31, 2016 |
| 575 |
Accrued insurance recoveries |
| 297 |
Reimbursements |
| (276) |
Balance at December 31, 2017 | $ | 596 |
|
|
|
In January 2018, the Utility received another $75 million in insurance reimbursements.
If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals.
Regulatory Citations
On April 25, 2017, the SED issued two citations to the Utility in connection with the Butte fire, totaling $8.3 million. The SED’s investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent the gray pine from leaning and contacting the Utility’s electric line, which created an unsafe and dangerous condition that resulted in that tree leaning and making contact with the electric line, thus causing a fire. The Utility paid the citations in June 2017.
Enforcement Matters
In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. It is uncertain whether any charges will be brought against the Utility as a result of these investigations.
CPUC Matters
Order Instituting an Investigation into Compliance with Ex Parte Communication Rules
During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have occurred or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker or a commissioner’s advisor and interested persons concerning substantive issues in certain formal proceedings. Certain communications are prohibited and others are permissible with proper noticing and reporting.
On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC. The OII cites some of the communications the Utility reported to the CPUC. The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.
On March, 28, 2017, the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility jointly submitted to the CPUC a settlement agreement in connection with the OII into the Utility’s compliance with the CPUC’s ex parte communication rules. On September 1, 2017, the assigned administrative law judge issued a PD in this proceeding adopting, with one modification, the settlement agreement jointly submitted to the CPUC on March 28, 2017, by the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, and TURN.
If adopted, the PD would increase the payment to the California General Fund, relative to the settlement agreement, from $1 million to $12 million resulting in a total penalty of $97.5 million comprised of: (1) a $12 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over the Utility’s next GRC cycle (i.e., the GRC following the 2017 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above.
On September 21, 2017, the Utility submitted a motion to the CPUC accepting the proposed modification of the settlement agreement to increase the Utility’s payment to the California General Fund from $1 million to $12 million. Further, the Utility also reported that it has identified several communications that appear to raise issues similar to other communications that are part of this proceeding.
On November 1, 2017, the Utility filed a status report advising the CPUC that the Utility and the non-Utility parties to the settlement agreement were unable to reach an agreement with respect to how to proceed regarding the communications that the Utility reported to the CPUC on September 21, 2017. Also on November 1, 2017, the non-Utility parties to the settlement requested that the CPUC approve the settlement, as modified by the PD, and open a second phase of the OII to investigate and consider appropriate sanctions for the new communications reported by the Utility on September 21, 2017, and others that may be discovered.
On November 30, 2017, the CPUC issued a decision extending the statutory deadline to June 29, 2018 to resolve the proceeding. The CPUC stated that an extension of the statutory deadline was necessary to allow the assigned administrative law judge time to prepare the revised decision and to open and resolve a second phase of this proceeding.
The Utility is unable to predict the outcome of this proceeding.
At December 31, 2017, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $24 million accrual for the amounts payable to the California General Fund and the Cities of San Bruno and San Carlos. In accordance with accounting rules, adjustments related to revenue requirements would be recorded in the periods in which they are incurred.
Natural Gas Transmission Pipeline Rights-of-Way
In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.
Potential Safety Citations
The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations identified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, on which the SED has yet to act. Under both the gas and electric programs, the SED has discretion whether to issue a penalty for each violation.
The SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED also has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The SED also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. Historically, the SED has exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. In the past, the SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The CPUC can also open an OII and levy additional fines even after the SED has issued a citation.
The Utility is unable to reasonably estimate the amount or range of future charges as a result of SED investigations or any proceedings that could be commenced in connection with potential violations of electric and natural gas laws and regulations.
Other Contingencies
PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $86 million at December 31, 2017 and $45 million at December 31, 2016. These amounts are included in Other current liabilities in the Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.
Disallowance of Plant Costs
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred for recently completed plant will not be recoverable through rates and the amount of disallowance can be reasonably estimated. Capital disallowances are reflected in operating and maintenance expenses in the Consolidated Statements of Income. Disallowances as a result of the CPUC’s June 2016 final phase one decision and December 2016 final phase two decision in the Utility’s 2015 GT&S rate case, the Utility’s Pipeline Safety Enhancement Plan, and CPUC’s final decision on the closure of Diablo Canyon are discussed below.
2015 GT&S Rate Case Disallowance of Capital Expenditures
On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The decision also established various cost caps that will increase the risk of overspend over the current rate case cycle including new one-way balancing accounts. As a result, in 2016, the Utility incurred charges of $219 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $134 million for 2011 through 2014 capital expenditures in excess of adopted amounts and $85 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending.
Capital Expenditures Relating to Pipeline Safety Enhancement Plan
The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs. As of December 31, 2017, the Utility has spent $1.38 billion on PSEP-related capital costs, of which $665 million was expensed in previous years for costs that are expected to exceed the authorized amount. The Utility expects the remaining PSEP work to continue throughout 2018. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.
Capital Expenditures Relating to the Diablo Canyon Power Plant
On January 11, 2018, the CPUC issued a final decision adopting the settlement agreement jointly submitted to the CPUC in May 2017 related to the recovery of license renewal costs and cancelled project costs within the Utility’s application to retire Diablo Canyon. The final decision allows for recovery from customers of $18.6 million of the total license renewal project cost of $53 million evenly over an 8-year period beginning January 1, 2018. Related to cancelled project costs, the decision allows for recovery from customers of 100% of the direct costs incurred prior to June 30, 2016 and 25% recovery of direct costs incurred after June 30, 2016. During the year ended December 31, 2017, the Utility incurred charges of $47 million related to the Diablo Canyon capital expenditures settlement agreement, of which $24 million is for cancelled projects and $23 million is for disallowed license renewal costs. The Utility does not expect to incur additional charges as a result of the CPUC’s final decision, other than additional project cancellation costs that the Utility does not expect to be material.
Environmental Remediation Contingencies
Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is composed of the following:
Balance at | |||||
| December 31 |
| December 31, | ||
(in millions) | 2017 |
| 2016 | ||
Topock natural gas compressor station | $ | 334 |
| $ | 299 |
Hinkley natural gas compressor station |
| 147 |
|
| 135 |
Former manufactured gas plant sites owned by the Utility or third parties(1) |
| 320 |
|
| 285 |
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites(2) |
| 115 |
|
| 131 |
Fossil fuel-fired generation facilities and sites(3) |
| 123 |
|
| 108 |
Total environmental remediation liability | $ | 1,039 |
| $ | 958 |
|
|
|
|
|
|
(1) Primarily driven by the following sites: Vallejo, SF East Harbor, Napa, and SF North Beach
(2) Primarily driven by the Shell Pond site
(3) Primarily driven by the SF Potrero Power Plant site
The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the state and federal regulatory agencies under the federal Resource Conservation and Recovery Act and/or other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.
The Utility’s environmental remediation liability at December 31, 2017 reflects its best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the extent of work to implement final remediation plans and the Utility’s required time frame for remediation. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition and cash flows during the period in which they are recorded. At December 31, 2017, the Utility expected to recover $725 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC.
Natural Gas Compressor Station Sites
The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.
Topock Site
The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the DOI. In November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. On December 21, 2017 the DTSC issued its final environmental impact report. The environmental impact report includes requirements related to conditions of work that have been anticipated or previously required and are accounted for in the current environmental remediation liability. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $289 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered through the HSM, where 90% of the costs are recovered in rates.
Hinkley Site
The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. The background study is expected to be finalized in 2019. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $145 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.
Former Manufactured Gas Plants (“MGPs”)
Former manufactured gas plants used coal and oil to produce gas for use by the Utility’s customers in the past. The by-products and residues of this process were often disposed at the manufactured gas plants themselves. The Utility has undertaken a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $343 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.
Utility-Owned Generation Facilities and Third-Party Disposal Sites
Utility-owned generation facilities and third-party disposal sites are long-term projects that are undergoing a remediation process. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $145 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.
Fossil Fuel-Fired Generation Sites
In 1998 the Utility divested its generation power plant business as part of generation deregulation. Although the Utility has sold its fossil-fueled power plants, the Utility has retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $106 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.
Nuclear Insurance
The Utility is a member of NEIL, which is a mutual insurer owned by utilities with nuclear facilities. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.6 billion per non-nuclear incident for Diablo Canyon. Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages.
NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Certain acts of terrorism may be “certified” by the Secretary of the Treasury. If damages are caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss. In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.
In addition to the nuclear insurance the Utility maintains through the NEIL, the Utility also is a member of the EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon.
If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, as of December 31, 2017, the current maximum aggregate annual retrospective premium obligation for the Utility would be approximately $57 million. EMANI provides $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $3 million, as of December 31, 2017.
Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $13.5 billion. The Utility purchased the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.5 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $255 million per nuclear incident under this program, with payments in each year limited to a maximum of $38 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before September 10, 2018.
The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the liability insurance.
Resolution of Remaining Chapter 11 Disputed Claims
Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility has entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.
At December 31, 2017 and December 31, 2016, respectively, the Consolidated Balance Sheets reflected $243 million and $236 million in net claims within Disputed claims and customer refunds. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved.
Purchase Commitments
The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2017:
Power Purchase Agreements |
|
|
|
|
|
|
| |||||||||||||||||
| Renewable |
| Conventional |
|
|
| Natural |
| Nuclear |
|
|
| ||||||||||||
(in millions) | Energy |
| Energy |
| Other |
| Gas |
| Fuel |
| Total | |||||||||||||
2018 | $ | 2,150 |
| $ | 718 |
| $ | 280 |
| $ | 388 |
| $ | 96 |
| $ | 3,632 | |||||||
2019 |
| 2,193 |
|
| 706 |
|
| 221 |
|
| 167 |
|
| 102 |
|
| 3,389 | |||||||
2020 |
| 2,188 |
|
| 686 |
|
| 175 |
|
| 148 |
|
| 143 |
|
| 3,340 | |||||||
2021 |
| 2,168 |
|
| 588 |
|
| 153 |
|
| 93 |
|
| 70 |
|
| 3,072 | |||||||
2022 |
| 1,975 |
|
| 512 |
|
| 143 |
|
| 93 |
|
| 60 |
|
| 2,783 | |||||||
Thereafter |
| 26,005 |
|
| 657 |
|
| 526 |
|
| 357 |
|
| 151 |
|
| 27,696 | |||||||
Total purchase |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
commitments | $ | 36,679 |
| $ | 3,867 |
| $ | 1,498 |
| $ | 1,246 |
| $ | 622 |
| $ | 43,912 | |||||||
Third-Party Power Purchase Agreements
In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.
Renewable Energy Power Purchase Agreements. In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate. The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow. As of December 31, 2017, renewable energy contracts expire at various dates between 2018 and 2043.
Conventional Energy Power Purchase Agreements. The Utility has entered into power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. As of December 31, 2017, these power purchase agreements expire at various dates between 2018 and 2033.
Other Power Purchase Agreements. The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. Several of these agreements are treated as capital leases. At December 31, 2017 and 2016, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $18 million and $35 million including accumulated amortization of $143 million and $148 million, respectively. The present value of the future minimum lease payments due under these agreements included $11 million and $17 million in Current Liabilities and $7 million and $18 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively. As of December 31, 2017, QF contracts in operation expire at various dates between 2018 and 2028. In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.
The costs incurred for all power purchases and electric capacity amounted to $3.3 billion in 2017, $3.5 billion in 2016, and $3.5 billion in 2015.
Natural Gas Supply, Transportation, and Storage Commitments
The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements expire at various dates between 2018 and 2026. In addition, the Utility has contracted for natural gas storage services in northern California in order to more reliably meet customers’ loads.
Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.9 billion in 2017, $0.7 billion in 2016, and $0.9 billion in 2015.
Nuclear Fuel Agreements
The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2018 and 2025 and are intended to ensure long-term nuclear fuel supply. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.
Payments for nuclear fuel amounted to $83 million in 2017, $100 million in 2016, and $128 million in 2015.
Other Commitments
PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2018 and 2052. At December 31, 2017, the future minimum payments related to these commitments were as follows:
Operating Leases | ||
2018 | $ | 44 |
2019 |
| 41 |
2020 |
| 40 |
2021 |
| 36 |
2022 |
| 27 |
Thereafter |
| 138 |
Total minimum lease payments | $ | 326 |
Payments for other commitments related to operating leases amounted to $45 million in 2017, $43 million in 2016, and $41 million in 2015. Certain leases on office facilities contain escalation clauses requiring annual increases in rent. The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index. Most leases contain extension operations ranging between one and five years.
|
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
| Years Ended December 31, | |||||||
(in millions, except per share amounts) |
| 2017 |
|
| 2016 |
|
| 2015 |
Administrative service revenue | $ | 63 |
| $ | 70 |
| $ | 51 |
Operating expenses |
| (5) |
|
| (73) |
|
| (53) |
Interest income |
| 1 |
|
| 1 |
|
| 1 |
Interest expense |
| (11) |
|
| (10) |
|
| (10) |
Other income |
| 4 |
|
| 2 |
|
| 30 |
Equity in earnings of subsidiaries |
| 1,667 |
|
| 1,388 |
|
| 852 |
Income before income taxes |
| 1,719 |
|
| 1,378 |
|
| 871 |
Income tax provision (benefit) |
| 73 |
|
| (15) |
|
| (3) |
Net income | $ | 1,646 |
| $ | 1,393 |
| $ | 874 |
Other Comprehensive Income |
|
|
|
|
|
|
|
|
Pension and other postretirement benefit plans obligations (net of taxes of $0, |
|
|
|
|
|
|
|
|
$1, and $0, at respective dates) | $ | 1 |
| $ | (2) |
| $ | (1) |
Net change in investments (net of taxes of $0, $0, and $12, at respective dates) |
| - |
|
| - |
|
| (17) |
Total other comprehensive income (loss) |
| 1 |
|
| (2) |
|
| (18) |
Comprehensive Income | $ | 1,647 |
| $ | 1,391 |
| $ | 856 |
Weighted Average Common Shares Outstanding, Basic |
| 512 |
|
| 499 |
|
| 484 |
Weighted Average Common Shares Outstanding, Diluted |
| 513 |
|
| 501 |
|
| 487 |
Net earnings per common share, basic | $ | 3.21 |
| $ | 2.79 |
| $ | 1.81 |
Net earnings per common share, diluted | $ | 3.21 |
| $ | 2.78 |
| $ | 1.79 |
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED BALANCE SHEETS
Balance at December 31, | |||||||
(in millions) | 2017 |
| 2016 | ||||
ASSETS |
|
|
|
|
| ||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents | $ | 2 |
| $ | 106 | ||
Advances to affiliates |
| 24 |
|
| 24 | ||
Income taxes receivable |
| 27 |
|
| 25 | ||
Total current assets |
| 53 |
|
| 155 | ||
Noncurrent Assets |
|
|
|
|
| ||
Equipment |
| 3 |
|
| 2 | ||
Accumulated depreciation |
| (3) |
|
| (2) | ||
Net equipment |
| - |
|
| - | ||
Investments in subsidiaries |
| 19,514 |
|
| 18,172 | ||
Other investments |
| 144 |
|
| 133 | ||
Intercompany receivable |
| 72 |
|
| - | ||
Deferred income taxes |
| 123 |
|
| 267 | ||
Total noncurrent assets |
| 19,853 |
|
| 18,572 | ||
Total Assets | $ | 19,906 |
| $ | 18,727 | ||
|
|
|
|
|
| ||
LIABILITIES AND SHAREHOLDERS’ EQUITY |
|
|
|
|
| ||
Current Liabilities |
|
|
|
|
| ||
Short-term borrowings | $ | 132 |
| $ | - | ||
Accounts payable – other |
| 6 |
|
| 7 | ||
Other |
| 23 |
|
| 274 | ||
Total current liabilities |
| 161 |
|
| 281 | ||
Noncurrent Liabilities |
|
|
|
|
| ||
Long-term debt |
| 350 |
|
| 348 | ||
Other |
| 175 |
|
| 158 | ||
Total noncurrent liabilities |
| 525 |
|
| 506 | ||
Common Shareholders’ Equity |
|
|
|
|
| ||
Common stock |
| 12,632 |
|
| 12,198 | ||
Reinvested earnings |
| 6,596 |
|
| 5,751 | ||
Accumulated other comprehensive income (loss) |
| (8) |
|
| (9) | ||
Total common shareholders’ equity |
| 19,220 |
|
| 17,940 | ||
Total Liabilities and Shareholders’ Equity | $ | 19,906 |
| $ | 18,727 | ||
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
Year ended December 31, | ||||||||
| 2017 |
| 2016 |
| 2015 | |||
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
Net income | $ | 1,646 |
| $ | 1,393 |
| $ | 874 |
Adjustments to reconcile net income to net cash provided by |
|
|
|
|
|
|
|
|
operating activities: |
|
|
|
|
|
|
|
|
Stock-based compensation amortization |
| 20 |
|
| 74 |
|
| 66 |
Equity in earnings of subsidiaries |
| (1,667) |
|
| (1,388) |
|
| (852) |
Deferred income taxes and tax credits-net |
| 139 |
|
| 11 |
|
| 10 |
Current income taxes receivable/payable |
| (2) |
|
| (1) |
|
| 5 |
Other |
| (75) |
|
| (24) |
|
| (70) |
Net cash provided by operating activities |
| 61 |
|
| 65 |
|
| 33 |
Cash Flows From Investing Activities: |
|
|
|
|
|
|
|
|
Investment in subsidiaries |
| (455) |
|
| (835) |
|
| (705) |
Dividends received from subsidiaries (1) |
| 784 |
|
| 911 |
|
| 716 |
Net cash provided by (used in) investing activities |
| 329 |
|
| 76 |
|
| 11 |
Cash Flows From Financing Activities: |
|
|
|
|
|
|
|
|
Borrowings (repayments) under revolving credit facilities |
| 132 |
|
| - |
|
| - |
Common stock issued |
| 395 |
|
| 822 |
|
| 780 |
Common stock dividends paid (2) |
| (1,021) |
|
| (921) |
|
| (856) |
Net cash provided by (used in) financing activities |
| (494) |
|
| (99) |
|
| (76) |
Net change in cash and cash equivalents |
| (104) |
|
| 42 |
|
| (32) |
Cash and cash equivalents at January 1 |
| 106 |
|
| 64 |
|
| 96 |
Cash and cash equivalents at December 31 | $ | 2 |
| $ | 106 |
| $ | 64 |
Supplemental disclosure of cash flow information |
|
|
|
|
|
|
|
|
Cash received (paid) for: |
|
|
|
|
|
|
|
|
Interest, net of amounts capitalized | $ | (9) |
| $ | (9) |
| $ | (9) |
Income taxes, net |
| - |
|
| (13) |
|
| - |
Supplemental disclosure of noncash investing and financing activities |
|
|
|
|
|
|
|
|
Noncash common stock issuances | $ | 21 |
| $ | 20 |
| $ | 21 |
Common stock dividends declared but not yet paid |
| - |
|
| 248 |
|
| 224 |
|
|
|
|
|
|
|
|
|
(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow.
(2) In July and October of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.53 per share.
In July and October of 2016 and January and April of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share.
In January, April, July, and October of 2015 and January and April of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
|
PG&E Corporation
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2017, 2016, and 2015
|
|
| Additions |
|
|
|
|
|
| |||||
Description |
| Balance at Beginning of Period |
|
| Charged to Costs and Expenses |
|
| Charged to Other Accounts |
|
| Deductions (2) |
|
| Balance at End of Period |
Valuation and qualifying accounts deducted from assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for uncollectible accounts (1) | $ | 58 |
| $ | 55 |
| $ | - |
| $ | 49 |
| $ | 64 |
2016: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for uncollectible accounts (1) | $ | 54 |
| $ | 50 |
| $ | - |
| $ | 46 |
| $ | 58 |
2015: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for uncollectible accounts (1) | $ | 66 |
| $ | 43 |
| $ | - |
| $ | 55 |
| $ | 54 |
|
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|
|
|
|
|
|
|
|
|
|
|
|
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
Pacific Gas and Electric Company
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2017, 2016, and 2015
|
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| Additions |
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| |||||||||||
Description |
| Balance at Beginning of Period |
|
| Charged to Costs and Expenses |
|
| Charged to Other Accounts |
|
| Deductions (2) |
|
| Balance at End of Period | ||||||
Valuation and qualifying accounts deducted from assets: |
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| ||||||
2017: |
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|
|
|
|
|
| ||||||
Allowance for uncollectible accounts (1) | $ | 58 |
| $ | 55 |
| $ | - |
| $ | 49 |
| $ | 64 | ||||||
2016: |
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|
|
|
|
| ||||||
Allowance for uncollectible accounts (1) | $ | 54 |
| $ | 50 |
| $ | - |
| $ | 46 |
| $ | 58 | ||||||
2015: |
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| ||||||
Allowance for uncollectible accounts (1) | $ | 66 |
| $ | 43 |
| $ | - |
| $ | 55 |
| $ | 54 | ||||||
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| ||||||
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off
|
Regulation and Regulated Operations
The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility also records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.
Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
Revenue Recognition
The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements.
The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three or four years. The Utility’s ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.
The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income.
The FERC authorizes the Utility’s revenue requirements in periodic (often annual) TO rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of revenues subject to refund.
Cash and Cash Equivalents
Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value.
Allowance for Doubtful Accounts Receivable
PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
Inventories
Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
Emission Allowances
The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.
Property, Plant, and Equipment
Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
Estimated Useful |
| Balance at December 31, | |||||||
(in millions, except estimated useful lives) | Lives (years) |
| 2017 |
| 2016 | ||||
Electricity generating facilities (1) | 5 to 120 |
| $ | 11,843 |
| $ | 11,308 | ||
Electricity distribution facilities | 15 to 65 |
|
| 31,110 |
|
| 29,836 | ||
Electricity transmission facilities | 15 to 75 |
|
| 12,180 |
|
| 11,412 | ||
Natural gas distribution facilities | 5 to 60 |
|
| 12,312 |
|
| 11,362 | ||
Natural gas transmission and storage facilities | 5 to 62 |
|
| 7,329 |
|
| 6,491 | ||
Construction work in progress |
|
|
| 2,471 |
|
| 2,184 | ||
Total property, plant, and equipment |
|
|
| 77,245 |
|
| 72,593 | ||
Accumulated depreciation |
|
|
| (23,456) |
|
| (22,012) | ||
Net property, plant, and equipment |
|
| $ | 53,789 |
| $ | 50,581 | ||
|
|
|
|
|
|
|
| ||
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as used based on the amount of energy output. (See Note 13 below.)
The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.83% in 2017, 3.73% in 2016, and 3.80% in 2015. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
AFUDC
AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $38 million and $89 million during 2017, $51 million and $112 million during 2016, and $48 million and $107 million during 2015.
Asset Retirement Obligations
The following table summarizes the changes in ARO liability during 2017 and 2016, including nuclear decommissioning obligations:
| 2017 |
|
| 2016 | |
ARO liability at beginning of year | $ | 4,684 |
| $ | 3,643 |
Revision in estimated cash flows |
| 128 |
|
| 968 |
Accretion |
| 207 |
|
| 194 |
Liabilities settled |
| (120) |
|
| (121) |
ARO liability at end of year | $ | 4,899 |
| $ | 4,684 |
The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to specified conditions under certain agreements.
Nuclear Decommissioning Obligation
Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for Diablo Canyon, representing 64% of the Utility’s request of $3.8 billion. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down.
PG&E Corporation and the Utility recorded an increase of $92 million to the ARO recognized on the Consolidated Balance Sheets, to align the decommissioning cost estimate with the CPUC’s final decision on the Utility’s application to retire Diablo Canyon Unit 1 by 2024 and Unit 2 by 2025.
The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued was $3.5 billion at both December 31, 2017 and 2016. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $4.1 billion at December 31, 2017 (or $7 billion in future dollars). These estimates are based on the 2017 decommissioning cost studies, prepared in accordance with CPUC requirements.
Disallowance of Plant Costs
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. (See “Enforcement and Litigation Matters” in Note 13 below.)
Nuclear Decommissioning Trusts
The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.
The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.” Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.
Variable Interest Entities
A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.
Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2017, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2017, it did not consolidate any of them.
Accounting Standards Issued But Not Yet Adopted
Presentation of Net Periodic Pension Cost
In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuaries. The change in capitalization of retirement benefits will not have a material impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.
Recognition of Lease Assets and Liabilities
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. In November, 2017, the FASB tentatively decided to amend the new leasing guidance such that entities may elect not to restate their comparative periods in the period of adoption. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with early adoption permitted. PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility expect this standard to increase lease assets and lease liabilities on the Consolidated Balance Sheets and do not expect the guidance will have a material impact on the Consolidated Statements of Income, Statements of Cash Flows and lease disclosures.
Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends the existing guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts. These investments are classified as “available-for-sale” and gains or losses are refundable, or recoverable, from customers through rates. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and will not have a material impact on the Consolidated Financial Statements and related disclosures.
Revenue Recognition Standard
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends existing revenue recognition guidance. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018. This standard will be adopted for related disclosures in the first quarter of 2018 and will not have a material impact on the Consolidated Financial Statements. Upon adoption of ASU 2014-09, the Utility plans to disclose revenues from contracts with customers separately from regulatory balancing account revenue and disaggregate customer contract revenue by customer class.
|
| Estimated Useful |
| Balance at December 31, | ||||||
(in millions, except estimated useful lives) | Lives (years) |
| 2017 |
| 2016 | ||||
Electricity generating facilities (1) | 5 to 120 |
| $ | 11,843 |
| $ | 11,308 | ||
Electricity distribution facilities | 15 to 65 |
|
| 31,110 |
|
| 29,836 | ||
Electricity transmission facilities | 15 to 75 |
|
| 12,180 |
|
| 11,412 | ||
Natural gas distribution facilities | 5 to 60 |
|
| 12,312 |
|
| 11,362 | ||
Natural gas transmission and storage facilities | 5 to 62 |
|
| 7,329 |
|
| 6,491 | ||
Construction work in progress |
|
|
| 2,471 |
|
| 2,184 | ||
Total property, plant, and equipment |
|
|
| 77,245 |
|
| 72,593 | ||
Accumulated depreciation |
|
|
| (23,456) |
|
| (22,012) | ||
Net property, plant, and equipment |
|
| $ | 53,789 |
| $ | 50,581 | ||
|
|
|
|
|
|
|
| ||
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as used based on the amount of energy output. (See Note 13 below.)
(in millions) |
| 2017 |
|
| 2016 |
ARO liability at beginning of year | $ | 4,684 |
| $ | 3,643 |
Revision in estimated cash flows |
| 128 |
|
| 968 |
Accretion |
| 207 |
|
| 194 |
Liabilities settled |
| (120) |
|
| (121) |
ARO liability at end of year | $ | 4,899 |
| $ | 4,684 |
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2017 consisted of the following:
Pension |
| Other |
|
|
| |||
(in millions, net of income tax) | Benefits |
| Benefits |
| Total | |||
Beginning balance | $ | (25) |
| $ | 16 |
| $ | (9) |
Other comprehensive income before reclassifications: |
|
|
|
|
|
|
|
|
Unrecognized prior service cost |
|
|
|
|
|
|
|
|
(net of taxes of $4 and $0, respectively) |
| (6) |
|
| - |
|
| (6) |
Unrecognized net actuarial loss |
|
|
|
|
|
|
|
|
(net of taxes of $229 and $97, respectively) |
| 333 |
|
| 141 |
|
| 474 |
Regulatory account transfer |
|
|
|
|
|
|
|
|
(net of taxes of $225 and $97, respectively) |
| (327) |
|
| (141) |
|
| (468) |
Amounts reclassified from other comprehensive income: |
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
|
|
|
|
|
|
(net of taxes of $3 and $6, respectively) (1) |
| (4) |
|
| 9 |
|
| 5 |
Amortization of net actuarial loss |
|
|
|
|
|
|
|
|
(net of taxes of $9 and $2, respectively) (1) |
| 13 |
|
| 2 |
|
| 15 |
Regulatory account transfer |
|
|
|
|
|
|
|
|
(net of taxes of $6 and $8, respectively) (1) |
| (9) |
|
| (10) |
|
| (19) |
Net current period other comprehensive loss |
| - |
|
| 1 |
|
| 1 |
Ending balance | $ | (25) |
| $ | 17 |
| $ | (8) |
|
|
|
|
|
|
|
|
|
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2016 consisted of the following:
Pension |
| Other |
|
|
| |||
(in millions, net of income tax) | Benefits |
| Benefits |
| Total | |||
Beginning balance | $ | (23) |
| $ | 16 |
| $ | (7) |
Other comprehensive income before reclassifications: |
|
|
|
|
|
|
|
|
Unrecognized prior service cost |
|
|
|
|
|
|
|
|
(net of taxes of $37 and $15, respectively) |
| 54 |
|
| (21) |
|
| 33 |
Unrecognized net actuarial loss |
|
|
|
|
|
|
|
|
(net of taxes of $45 and $15, respectively) |
| (64) |
|
| 21 |
|
| (43) |
Regulatory account transfer |
|
|
|
|
|
|
|
|
(net of taxes of $5 and $0, respectively) |
| 7 |
|
| - |
|
| 7 |
Amounts reclassified from other comprehensive income: |
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
|
|
|
|
|
|
(net of taxes of $3 and $6, respectively) (1) |
| 5 |
|
| 9 |
|
| 14 |
Amortization of net actuarial loss |
|
|
|
|
|
|
|
|
(net of taxes of $10 and $2, respectively) (1) |
| 14 |
|
| 2 |
|
| 16 |
Regulatory account transfer |
|
|
|
|
|
|
|
|
(net of taxes of $13 and $8, respectively) (1) |
| (18) |
|
| (11) |
|
| (29) |
Net current period other comprehensive loss |
| (2) |
|
| - |
|
| (2) |
Ending balance | $ | (25) |
| $ | 16 |
| $ | (9) |
|
|
|
|
|
|
|
|
|
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)
|
Long-term regulatory assets are comprised of the following:
Balance at December 31, |
| Recovery | |||||||
(in millions) | 2017 |
| 2016 |
| Period | ||||
Pension benefits (1) | $ | 1,954 |
| $ | 2,429 |
| Indefinitely (3) | ||
Deferred income taxes (1)(4) |
| - |
|
| 3,859 |
|
| ||
Utility retained generation (2) |
| 319 |
|
| 364 |
| 9 years | ||
Environmental compliance costs (1) |
| 837 |
|
| 778 |
| 32 years | ||
Price risk management (1) |
| 65 |
|
| 92 |
| 10 years | ||
Unamortized loss, net of gain, on reacquired debt (1) |
| 79 |
|
| 76 |
| 25 years | ||
Other |
| 539 |
|
| 353 |
| Various | ||
Total long-term regulatory assets | $ | 3,793 |
| $ | 7,951 |
|
| ||
|
|
|
|
|
|
|
| ||
(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP.
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
(3) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(4) The change in the balance from a regulatory asset as of December 31, 2016 to a regulatory liability as of December 31, 2017 reflects the impact of changes in net deferred tax liabilities associated with a lower federal income tax rate as a result of the Tax Act. (See “Regulatory Liabilities” below and Note 8.)
Long-term regulatory liabilities are comprised of the following:
Balance at December 31, | |||||
(in millions) | 2017 |
| 2016 | ||
Cost of removal obligations (1) | $ | 5,547 |
| $ | 5,060 |
Deferred income taxes (2) |
| 1,021 |
|
| - |
Recoveries in excess of AROs (3) |
| 624 |
|
| 626 |
Public purpose programs (4) |
| 590 |
|
| 567 |
Other |
| 897 |
|
| 552 |
Total long-term regulatory liabilities | $ | 8,679 |
| $ | 6,805 |
|
|
|
|
|
|
(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.
(2) Represents the net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment. (See Note 8 below.)
(3) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 10 below.)
(4) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
| Receivable | ||||
| Balance at December 31, | ||||
(in millions) | 2017 |
| 2016 | ||
Electric distribution | $ | - |
| $ | 132 |
Electric transmission |
| 139 |
|
| 244 |
Utility generation |
| - |
|
| 48 |
Gas distribution and transmission |
| 486 |
|
| 541 |
Energy procurement |
| 71 |
|
| 132 |
Public purpose programs |
| 103 |
|
| 106 |
Other |
| 423 |
|
| 297 |
Total regulatory balancing accounts receivable | $ | 1,222 |
| $ | 1,500 |
| Payable | ||||
| Balance at December 31, | ||||
(in millions) | 2017 |
| 2016 | ||
Electric distribution | $ | 72 |
| $ | - |
Electric transmission |
| 120 |
|
| 99 |
Utility generation |
| 14 |
|
| - |
Gas distribution and transmission |
| - |
|
| 48 |
Energy procurement |
| 149 |
|
| 13 |
Public purpose programs |
| 452 |
|
| 264 |
Other |
| 313 |
|
| 221 |
Total regulatory balancing accounts payable | $ | 1,120 |
| $ | 645 |
|
|
|
| December 31, | ||||
(in millions) |
|
| 2017 |
| 2016 | ||
PG&E Corporation |
|
|
|
|
| ||
Senior notes: |
|
|
|
|
|
|
|
Maturity |
| Interest Rates |
|
|
|
|
|
2019 |
| 2.40% | $ | 350 |
| $ | 350 |
Unamortized discount, net of premium and debt issuance costs |
|
|
| - |
|
| (2) |
Total PG&E Corporation long-term debt |
|
|
| 350 |
|
| 348 |
Utility |
|
|
|
|
|
|
|
Senior notes: |
|
|
|
|
|
|
|
Maturity |
| Interest Rates |
|
|
|
|
|
2017 |
| 5.63% |
| - |
|
| 700 |
2018 |
| 8.25% |
| 400 |
|
| 800 |
2020 |
| 3.50% |
| 800 |
|
| 800 |
2021 |
| 3.25% to 4.25% |
| 550 |
|
| 550 |
2022 |
| 2.45% |
| 400 |
|
| 400 |
2023 through 2047 |
| 2.95% to 6.35% |
| 14,975 |
|
| 12,375 |
Less: current portion (1) |
|
|
| (400) |
|
| (700) |
Unamortized discount, net of premium and debt issuance costs |
|
|
| (185) |
|
| (161) |
Total senior notes, net of current portion |
|
|
| 16,540 |
|
| 14,764 |
Pollution control bonds: |
|
|
|
|
|
|
|
Maturity |
| Interest Rates |
|
|
|
|
|
Series 2004 A-D, due 2023(2) |
| 4.75% |
| - |
|
| 345 |
Series 2008 F and 2010 E, due 2026 (3) |
| 1.75% |
| 100 |
|
| - |
Series 2008 G, due 2018 (4) |
| 1.05% |
| 45 |
|
| - |
Series 2009 A-B, due 2026 (5) |
| 1.78% |
| 149 |
|
| 149 |
Series 1996 C, E, F, 1997 B due 2026 (6) |
| variable rate(7) |
| 614 |
|
| 614 |
Less: current portion |
|
|
| (45) |
|
| - |
Total pollution control bonds |
|
|
| 863 |
|
| 1,108 |
Total Utility long-term debt, net of current portion |
|
|
| 17,403 |
|
| 15,872 |
Total consolidated long-term debt, net of current portion |
|
| $ | 17,753 |
| $ | 16,220 |
|
|
|
|
|
|
|
|
(1) On January 19, 2018, the Utility sent a notice of redemption to redeem all $400 million aggregate principal amount of the 8.25% senior notes due October 15, 2018 on February 18, 2018. On January 31, 2018, the Utility deposited with the trustee funds sufficient to effect the early redemption of these bonds and satisfy and discharge its remaining obligation of $400 million.
(2) In June 2017, the Utility repurchased and retired $345 million principal amount of Pollution Control Bonds series 2004 A-D.
(3) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 30, 2022.
(4) Pollution Control Bonds series 2008G were remarketed and issued in June 2017 and mature on December 1, 2018.
(5) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.
(6) Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
(7) At December 31, 2017, the interest rate on these bonds ranged from 1.45% - 1.70%.
(in millions, |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||
except interest rates) | 2018 |
| 2019 |
| 2020 |
| 2021 |
|
| 2022 |
| Thereafter |
| Total | ||||||||||||||||||||||||||
PG&E Corporation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Average fixed interest rate |
| - |
|
|
| 2.40% |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 2.40% | ||||||||||||||
Fixed rate obligations | $ | - |
|
| $ | 350 |
|
| $ | - |
|
| $ | - |
|
| $ | - |
|
| $ | - |
|
| $ | 350 | ||||||||||||||
Utility |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||
Average fixed interest rate |
| 7.52% |
|
|
| - |
|
|
| 3.50% |
|
|
| 3.80% |
|
|
| 2.31% |
|
|
| 4.68% |
|
|
| 4.61% | ||||||||||||||
Fixed rate obligations | $ | 445 |
|
| $ | - |
|
| $ | 800 |
|
| $ | 550 |
|
| $ | 500 (2) |
|
| $ | 14,975 |
|
| $ | 17,270 | ||||||||||||||
Variable interest rate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||
as of December 31, 2017 |
| - |
|
|
| 1.78% |
|
|
| 1.59% |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 1.63% | ||||||||||||||
Variable rate obligations (1) | $ | - |
|
| $ | 149 |
|
| $ | 614 |
|
| $ | - |
|
| $ | - |
|
| $ | - |
|
| $ | 763 | ||||||||||||||
Total consolidated debt | $ | 445 |
|
| $ | 499 |
|
| $ | 1,414 |
|
| $ | 550 |
|
| $ | 500 |
|
| $ | 14,975 |
|
| $ | 18,383 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||
(1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020.
(2) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 30, 2022.
The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at December 31, 2017:
|
| Credit |
| Letters of |
| Commercial |
|
|
| ||||||||||||
| Termination |
| Facility |
| Credit |
| Paper |
| Facility | ||||||||||||
(in millions) | Date |
| Limit |
| Outstanding |
| Outstanding |
| Availability | ||||||||||||
PG&E Corporation | April 2022 |
| $ | 300 | (1) |
| $ | - |
| $ | 132 |
| $ | 168 | |||||||
Utility | April 2022 |
|
| 3,000 | (2) |
|
| 49 |
|
| 50 |
|
| 2,901 | |||||||
Total revolving credit facilities |
|
| $ | 3,300 |
|
| $ | 49 |
| $ | 182 |
| $ | 3,069 | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
(1) Includes a $50 million lender commitment to the letter of credit sublimit and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.
(2) Includes a $500 million lender commitment to the letter of credit sublimit and a $75 million commitment for swingline loans.
|
| PG&E Corporation |
| Utility | ||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||
(in millions) | 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | ||||||||||||||||||
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Federal | $ | (10) |
| $ | (105) |
| $ | (89) |
| $ | 61 |
| $ | (105) |
| $ | (88) | ||||||||||||
State |
| 48 |
|
| (70) |
|
| 11 |
|
| 50 |
|
| (66) |
|
| 6 | ||||||||||||
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Federal |
| 481 |
|
| 218 |
|
| 131 |
|
| 326 |
|
| 229 |
|
| 136 | ||||||||||||
State |
| 6 |
|
| 16 |
|
| (76) |
|
| 4 |
|
| 16 |
|
| (69) | ||||||||||||
Tax credits |
| (14) |
|
| (4) |
|
| (4) |
|
| (14) |
|
| (4) |
|
| (4) | ||||||||||||
Income tax provision (benefit) | $ | 511 |
| $ | 55 |
| $ | (27) |
| $ | 427 |
| $ | 70 |
| $ | (19) | ||||||||||||
| PG&E Corporation |
| Utility | ||||||||||
| Year Ended December 31, | ||||||||||||
(in millions) | 2017 |
| 2016 |
| 2017 |
| 2016 | ||||||
Deferred income tax assets: |
|
|
|
|
|
|
|
|
|
|
| ||
Tax carryforwards |
| 830 |
|
| 1,851 |
|
| 736 |
|
| 1,596 | ||
Compensation |
| 274 |
|
| 277 |
|
| 205 |
|
| 199 | ||
Income tax regulatory liability (1) |
| 286 |
|
| - |
|
| 286 |
|
| - | ||
Other (2) |
| 185 |
|
| 186 |
|
| 194 |
|
| 203 | ||
Total deferred income tax assets | $ | 1,575 |
| $ | 2,314 |
| $ | 1,421 |
| $ | 1,998 | ||
Deferred income tax liabilities: |
|
|
|
|
|
|
|
|
|
|
| ||
Property related basis differences |
| 7,269 |
|
| 10,429 |
|
| 7,256 |
|
| 10,411 | ||
Income tax regulatory asset (1) |
| - |
|
| 1,572 |
|
| - |
|
| 1,572 | ||
Other (3) |
| 128 |
|
| 526 |
|
| 128 |
|
| 525 | ||
Total deferred income tax liabilities | $ | 7,397 |
| $ | 12,527 |
| $ | 7,384 |
| $ | 12,508 | ||
Total net deferred income tax liabilities | $ | 5,822 |
| $ | 10,213 |
| $ | 5,963 |
| $ | 10,510 | ||
|
|
|
|
|
|
|
|
|
|
|
| ||
(1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (For more information see Note 3 above and “Tax Cuts and Jobs Act of 2017” below.)
(2) Amounts include benefits, environmental reserve, and customer advances for construction.
(3) Amounts primarily relate to regulatory balancing accounts.
| PG&E Corporation |
| Utility | ||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||
| 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | ||||||||||||||||
Federal statutory income tax rate | 35.0 | % |
| 35.0 | % |
| 35.0 | % |
| 35.0 | % |
| 35.0 | % |
| 35.0 | % | ||||||||||
Increase (decrease) in income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
tax rate resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
State income tax (net of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
federal benefit) (1) | 1.5 |
|
| (2.5) |
|
| (4.9) |
|
| 1.6 |
|
| (2.2) |
|
| (4.8) |
| ||||||||||
Effect of regulatory treatment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
of fixed asset differences (2) | (16.5) |
|
| (23.7) |
|
| (33.6) |
|
| (16.8) |
|
| (23.4) |
|
| (33.7) |
| ||||||||||
Tax credits | (1.1) |
|
| (0.8) |
|
| (1.3) |
|
| (1.1) |
|
| (0.8) |
|
| (1.3) |
| ||||||||||
Benefit of loss carryback | - |
|
| (1.1) |
|
| (1.5) |
|
| - |
|
| (1.1) |
|
| (1.5) |
| ||||||||||
Non deductible penalties (3) | 0.4 |
|
| 0.8 |
|
| 4.3 |
|
| 0.4 |
|
| 0.8 |
|
| 4.3 |
| ||||||||||
Tax Reform Adjustment (4) | 6.8 |
|
| - |
|
| - |
|
| 3.0 |
|
| - |
|
| - |
| ||||||||||
Other, net (5) | (2.5) |
|
| (3.9) |
|
| (1.1) |
|
| (2.0) |
|
| (3.5) |
|
| (0.2) |
| ||||||||||
Effective tax rate | 23.6 | % |
| 3.8 | % |
| (3.1) | % |
| 20.1 | % |
| 4.8 | % |
| (2.2) | % | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
(1) Includes the effect of state flow-through ratemaking treatment. In 2016 and 2015, amounts reflect an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions. The 2017 amount reflects an agreement with the IRS on a 2013 audit related to generation repairs deductions.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacted 2016 and 2017. All amounts are impacted by the level of income before income taxes. The 2014 GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.
(3) Primarily represents the effects of a non-tax deductible penalty associated with the Butte fire for 2017, non-tax deductible fines and penalties associated with the natural gas distribution facilities record-keeping decision for 2016 and the effects of the San Bruno Penalty Decision for 2015.
(4) Represents the required adjustment to deferred tax balances, due to the federal income tax rate being lowered from 35% to 21% beginning in 2018 as a result of the enactment of the Tax Act.
(5) These amounts primarily represent the impact of tax audit settlements.
PG&E Corporation |
| Utility | |||||||||||||||
(in millions) | 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | ||||||
Balance at beginning of year | $ | 388 |
| $ | 468 |
| $ | 713 |
| $ | 382 |
| $ | 462 |
| $ | 707 |
Additions for tax position taken |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
during a prior year |
| - |
|
| - |
|
| 40 |
|
| - |
|
| - |
|
| 40 |
Reductions for tax position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
taken during a prior year |
| (71) |
|
| (77) |
|
| (349) |
|
| (71) |
|
| (77) |
|
| (349) |
Additions for tax position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
taken during the current year |
| 48 |
|
| 56 |
|
| 64 |
|
| 48 |
|
| 56 |
|
| 64 |
Settlements |
| (14) |
|
| (59) |
|
| - |
|
| (8) |
|
| (59) |
|
| - |
Expiration of statute |
| (3) |
|
| - |
|
| - |
|
| (3) |
|
| - |
|
| - |
Balance at end of year | $ | 349 |
| $ | 388 |
| $ | 468 |
| $ | 349 |
| $ | 382 |
| $ | 462 |
| December 31, |
| Expiration | |
(in millions) | 2017 |
| Year | |
Federal: |
|
|
|
|
Net operating loss carryforward | $ | 4,233 |
| 2031 - 2036 |
Tax credit carryforward |
| 103 |
| 2029 - 2036 |
Charitable contribution loss carryforward |
| 93 |
| 2019 - 2021 |
|
|
|
|
|
State: |
|
|
|
|
Net operating loss carryforward | $ | - |
| N/A |
Tax credit carryforward |
| 13 |
| Various |
Charitable contribution loss carryforward |
| 24 |
| 2020 - 2021 |
|
|
|
|
| Contract Volume | ||
Underlying Product |
| Instruments |
| 2017 |
| 2016 |
Natural Gas(1) (MMBtus(2)) |
| Forwards and Swaps |
| 228,768,745 |
| 323,301,331 |
|
| Options |
| 60,736,806 |
| 96,602,785 |
Electricity (Megawatt-hours) |
| Forwards and Swaps |
| 2,872,013 |
| 3,287,397 |
|
| Congestion Revenue Rights(3) |
| 312,272,177 |
| 278,143,281 |
|
|
|
|
|
|
|
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.
At December 31, 2017, the Utility’s outstanding derivative balances were as follows:
Commodity Risk | |||||||||||
| Gross Derivative |
|
|
|
|
| Total Derivative | ||||
(in millions) | Balance |
| Netting |
| Cash Collateral |
| Balance | ||||
Current assets – other | $ | 30 |
| $ | (3) |
| $ | 10 |
| $ | 37 |
Other noncurrent assets – other |
| 103 |
|
| (1) |
|
| - |
|
| 102 |
Current liabilities – other |
| (47) |
|
| 3 |
|
| 13 |
|
| (31) |
Noncurrent liabilities – other |
| (66) |
|
| 1 |
|
| 8 |
|
| (57) |
Total commodity risk | $ | 20 |
| $ | - |
| $ | 31 |
| $ | 51 |
At December 31, 2016, the Utility’s outstanding derivative balances were as follows:
Commodity Risk | |||||||||||
| Gross Derivative |
|
|
|
|
| Total Derivative | ||||
(in millions) | Balance |
| Netting |
| Cash Collateral |
| Balance | ||||
Current assets – other | $ | 91 |
| $ | (10) |
| $ | 1 |
| $ | 82 |
Other noncurrent assets – other |
| 149 |
|
| (9) |
|
| - |
|
| 140 |
Current liabilities – other |
| (48) |
|
| 10 |
|
| - |
|
| (38) |
Noncurrent liabilities – other |
| (101) |
|
| 9 |
|
| 3 |
|
| (89) |
Total commodity risk | $ | 91 |
| $ | - |
| $ | 4 |
| $ | 95 |
| Commodity Risk | |||||||
| For the year ended December 31, | |||||||
(in millions) | 2017 |
| 2016 |
| 2015 | |||
Unrealized gain/(loss) - regulatory assets and liabilities(1) | $ | (71) |
| $ | 64 |
| $ | (6) |
Realized loss - cost of electricity(2) |
| (27) |
|
| (53) |
|
| (14) |
Realized loss - cost of natural gas(2) |
| (5) |
|
| (18) |
|
| (10) |
Total commodity risk | $ | (103) |
| $ | (7) |
| $ | (30) |
|
|
|
|
|
|
|
|
|
(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.
| Balance at December 31, | ||||
(in millions) | 2017 |
| 2016 | ||
Derivatives in a liability position with credit risk-related |
|
|
|
|
|
contingencies that are not fully collateralized | $ | (1) |
| $ | (24) |
Related derivatives in an asset position |
| - |
|
| 19 |
Collateral posting in the normal course of business related to |
|
|
|
|
|
these derivatives |
| - |
|
| 4 |
Net position of derivative contracts/additional collateral |
|
|
|
|
|
posting requirements(1) | $ | (1) |
| $ | (1) |
|
|
|
|
|
|
(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies.
|
| Fair Value Measurements | |||||||||||||
| At December 31, 2017 | |||||||||||||
(in millions) | Level 1 |
| Level 2 |
| Level 3 |
| Netting (1) |
| Total | |||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments | $ | 385 |
| $ | - |
| $ | - |
| $ | - |
| $ | 385 |
Nuclear decommissioning trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
| 23 |
|
| - |
|
| - |
|
| - |
|
| 23 |
Global equity securities |
| 1,967 |
|
| - |
|
| - |
|
| - |
|
| 1,967 |
Fixed-income securities |
| 733 |
|
| 562 |
|
| - |
|
| - |
|
| 1,295 |
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| - |
|
| 18 |
Total nuclear decommissioning trusts (2) |
| 2,723 |
|
| 562 |
|
| - |
|
| - |
|
| 3,303 |
Price risk management instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity |
| - |
|
| 3 |
|
| 129 |
|
| 6 |
|
| 138 |
Gas |
| - |
|
| 1 |
|
| - |
|
| - |
|
| 1 |
Total price risk management |
| - |
|
| 4 |
|
| 129 |
|
| 6 |
|
| 139 |
instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rabbi trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-income securities |
| - |
|
| 72 |
|
| - |
|
| - |
|
| 72 |
Life insurance contracts |
| - |
|
| 71 |
|
| - |
|
| - |
|
| 71 |
Total rabbi trusts |
| - |
|
| 143 |
|
| - |
|
| - |
|
| 143 |
Long-term disability trust |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
| 8 |
|
| - |
|
| - |
|
| - |
|
| 8 |
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| - |
|
| 167 |
Total long-term disability trust |
| 8 |
|
| - |
|
| - |
|
| - |
|
| 175 |
TOTAL ASSETS | $ | 3,116 |
| $ | 709 |
| $ | 129 |
| $ | 6 |
| $ | 4,145 |
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price risk management instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity | $ | 10 |
| $ | 15 |
| $ | 87 |
| $ | (25) |
| $ | 87 |
Gas |
| - |
|
| 1 |
|
| - |
|
| - |
|
| 1 |
TOTAL LIABILITIES | $ | 10 |
| $ | 16 |
| $ | 87 |
| $ | (25) |
| $ | 88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $440 million, primarily related to deferred taxes on appreciation of investment value.
Fair Value Measurements | ||||||||||||||
| At December 31, 2016 | |||||||||||||
(in millions) | Level 1 |
| Level 2 |
| Level 3 |
| Netting (1) |
| Total | |||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments | $ | 105 |
| $ | - |
| $ | - |
| $ | - |
| $ | 105 |
Nuclear decommissioning trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
| 9 |
|
| - |
|
| - |
|
| - |
|
| 9 |
Global equity securities |
| 1,724 |
|
| - |
|
| - |
|
| - |
|
| 1,724 |
Fixed-income securities |
| 665 |
|
| 527 |
|
| - |
|
| - |
|
| 1,192 |
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| - |
|
| 14 |
Total nuclear decommissioning trusts (2) |
| 2,398 |
|
| 527 |
|
| - |
|
| - |
|
| 2,939 |
Price risk management instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity |
| 30 |
|
| 18 |
|
| 181 |
|
| (18) |
|
| 211 |
Gas |
| - |
|
| 11 |
|
| - |
|
| - |
|
| 11 |
Total price risk management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
instruments |
| 30 |
|
| 29 |
|
| 181 |
|
| (18) |
|
| 222 |
Rabbi trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-income securities |
| - |
|
| 61 |
|
| - |
|
| - |
|
| 61 |
Life insurance contracts |
| - |
|
| 70 |
|
| - |
|
| - |
|
| 70 |
Total rabbi trusts |
| - |
|
| 131 |
|
| - |
|
| - |
|
| 131 |
Long-term disability trust |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
| 8 |
|
| - |
|
| - |
|
| - |
|
| 8 |
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| - |
|
| 170 |
Total long-term disability trust |
| 8 |
|
| - |
|
| - |
|
| - |
|
| 178 |
TOTAL ASSETS | $ | 2,541 |
| $ | 687 |
| $ | 181 |
| $ | (18) |
| $ | 3,575 |
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price risk management instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity | $ | 9 |
| $ | 12 |
| $ | 126 |
| $ | (21) |
| $ | 126 |
Gas |
| - |
|
| 2 |
|
| - |
|
| (1) |
|
| 1 |
TOTAL LIABILITIES | $ | 9 |
| $ | 14 |
| $ | 126 |
| $ | (22) |
| $ | 127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.
|
| Fair Value at |
|
|
|
|
|
|
| ||||||||||||
(in millions) |
| At December 31, 2017 |
| Valuation |
| Unobservable |
|
|
| ||||||||||||
Fair Value Measurement |
| Assets |
| Liabilities |
| Technique |
| Input |
| Range (1) | |||||||||||
Congestion revenue rights |
| $ | 129 |
| $ | 24 |
| Market approach |
| CRR auction prices |
| $ | (16.03) - 11.99 | ||||||||
Power purchase agreements |
| $ | - |
| $ | 63 |
| Discounted cash flow |
| Forward prices |
| $ | 18.81 - 38.80 | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
| Fair Value at |
|
|
|
|
|
|
| |||||
(in millions) |
| At December 31, 2016 |
| Valuation |
| Unobservable |
|
|
| ||||
Fair Value Measurement |
| Assets |
| Liabilities |
| Technique |
| Input |
| Range (1) | |||
Congestion revenue rights |
| $ | 181 |
| $ | 35 |
| Market approach |
| CRR auction prices |
| $ | (11.88) - 6.93 |
Power purchase agreements |
| $ | - |
| $ | 91 |
| Discounted cash flow |
| Forward prices |
| $ | 18.07 - 38.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Represents price per megawatt-hour
| Price Risk Management Instruments | ||||||
(in millions) | 2017 |
| 2016 | ||||
Asset (liability) balance as of January 1 | $ | 55 |
| $ | 89 | ||
Net realized and unrealized gains: |
|
|
|
|
| ||
Included in regulatory assets and liabilities or balancing accounts (1) |
| (13) |
|
| (34) | ||
Asset (liability) balance as of December 31 | $ | 42 |
| $ | 55 | ||
|
|
|
|
|
| ||
(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
| At December 31, | ||||||||||||
| 2017 |
| 2016 | ||||||||||
(in millions) | Carrying Amount |
| Level 2 Fair Value |
| Carrying Amount |
| Level 2 Fair Value | ||||||
Debt (Note 4) |
|
|
|
|
|
|
|
|
|
|
| ||
PG&E Corporation | $ | 350 |
| $ | 350 |
| $ | 348 |
| $ | 352 | ||
Utility |
| 17,090 |
|
| 19,128 |
|
| 15,813 |
|
| 17,790 | ||
|
|
|
| Total |
|
| Total |
|
|
| |
| Amortized |
|
| Unrealized |
|
| Unrealized |
|
| Total Fair | |
(in millions) | Cost |
|
| Gains |
|
| Losses |
|
| Value | |
As of December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts |
|
|
|
|
|
|
|
|
|
|
|
Short-term investments | $ | 23 |
| $ | - |
| $ | - |
| $ | 23 |
Global equity securities |
| 524 |
|
| 1,463 |
|
| (2) |
|
| 1,985 |
Fixed-income securities |
| 1,252 |
|
| 51 |
|
| (8) |
|
| 1,295 |
Total (1) | $ | 1,799 |
| $ | 1,514 |
| $ | (10) |
| $ | 3,303 |
As of December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts |
|
|
|
|
|
|
|
|
|
|
|
Short-term investments | $ | 9 |
| $ | - |
| $ | - |
| $ | 9 |
Global equity securities |
| 584 |
|
| 1,157 |
|
| (3) |
|
| 1,738 |
Fixed-income securities |
| 1,156 |
|
| 48 |
|
| (12) |
|
| 1,192 |
Total (1) | $ | 1,749 |
| $ | 1,205 |
| $ | (15) |
| $ | 2,939 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) Represents amounts before deducting $440 million and $333 million at December 31, 2017 and 2016, respectively, primarily related to deferred taxes on appreciation of investment value.
| As of | |
(in millions) | December 31, 2017 | |
Less than 1 year | $ | 41 |
1–5 years |
| 414 |
5–10 years |
| 352 |
More than 10 years |
| 488 |
Total maturities of fixed-income securities | $ | 1,295 |
| 2017 |
| 2016 |
| 2015 | |||
(in millions) |
|
|
|
|
|
|
|
|
Proceeds from sales and maturities of nuclear decommissioning |
|
|
|
|
|
|
|
|
investments | $ | 1,291 |
| $ | 1,295 |
| $ | 1,268 |
Gross realized gains on securities held as available-for-sale |
| 53 |
|
| 18 |
|
| 55 |
Gross realized losses on securities held as available-for-sale |
| (11) |
|
| (26) |
|
| (37) |
|
Pension Plan
2017 |
| 2016 | |||||
Change in plan assets: |
|
|
| ||||
Fair value of plan assets at beginning of year | $ | 14,729 |
| $ | 13,745 | ||
Actual return on plan assets |
| 2,380 |
|
| 1,358 | ||
Company contributions |
| 335 |
|
| 334 | ||
Benefits and expenses paid |
| (792) |
|
| (708) | ||
Fair value of plan assets at end of year | $ | 16,652 |
| $ | 14,729 | ||
|
|
|
|
|
| ||
Change in benefit obligation: |
|
|
|
|
| ||
Benefit obligation at beginning of year | $ | 17,305 |
| $ | 16,299 | ||
Service cost for benefits earned |
| 472 |
|
| 453 | ||
Interest cost |
| 714 |
|
| 715 | ||
Actuarial (gain) loss |
| 1,048 |
|
| 637 | ||
Plan amendments |
| 10 |
|
| (91) | ||
Benefits and expenses paid |
| (792) |
|
| (708) | ||
Benefit obligation at end of year (1) | $ | 18,757 |
| $ | 17,305 | ||
|
|
|
|
|
| ||
Funded Status: |
|
|
|
|
| ||
Current liability | $ | (7) |
| $ | (7) | ||
Noncurrent liability |
| (2,098) |
|
| (2,569) | ||
Net liability at end of year | $ | (2,105) |
| $ | (2,576) | ||
|
|
|
|
|
| ||
(1) PG&E Corporation’s accumulated benefit obligation was $16.8 billion and $15.6 billion at December 31, 2017 and 2016, respectively.
Postretirement Benefits Other than Pensions
2017 |
| 2016 | |||||
Change in plan assets: |
|
|
|
|
| ||
Fair value of plan assets at beginning of year | $ | 2,173 |
| $ | 2,035 | ||
Actual return on plan assets |
| 298 |
|
| 167 | ||
Company contributions |
| 33 |
|
| 52 | ||
Plan participant contribution |
| 87 |
|
| 85 | ||
Benefits and expenses paid |
| (171) |
|
| (166) | ||
Fair value of plan assets at end of year | $ | 2,420 |
| $ | 2,173 | ||
|
|
|
|
|
| ||
Change in benefit obligation: |
|
|
|
|
| ||
Benefit obligation at beginning of year | $ | 1,877 |
| $ | 1,766 | ||
Service cost for benefits earned |
| 59 |
|
| 52 | ||
Interest cost |
| 77 |
|
| 76 | ||
Actuarial (gain) loss |
| (49) |
|
| 11 | ||
Plan amendments |
| - |
|
| 37 | ||
Benefits and expenses paid |
| (157) |
|
| (153) | ||
Federal subsidy on benefits paid |
| 3 |
|
| 3 | ||
Plan participant contributions |
| 87 |
|
| 85 | ||
Benefit obligation at end of year | $ | 1,897 |
| $ | 1,877 | ||
|
|
|
|
|
| ||
Funded Status: (1) |
|
|
|
|
| ||
Noncurrent asset | $ | 553 |
| $ | 368 | ||
Noncurrent liability |
| (30) |
|
| (72) | ||
Net asset at end of year | $ | 523 |
| $ | 296 | ||
|
|
|
|
|
| ||
(1) At December 31, 2017 and 2016, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.
Pension Plan
2017 |
| 2016 |
| 2015 | ||||||||
Service cost | $ | 472 |
| $ | 453 |
| $ | 479 | ||||
Interest cost |
| 714 |
|
| 715 |
|
| 673 | ||||
Expected return on plan assets |
| (770) |
|
| (828) |
|
| (873) | ||||
Amortization of prior service cost |
| (7) |
|
| 8 |
|
| 15 | ||||
Amortization of net actuarial loss |
| 22 |
|
| 24 |
|
| 10 | ||||
Net periodic benefit cost |
| 431 |
|
| 372 |
|
| 304 | ||||
Less: transfer to regulatory account (1) |
| (92) |
|
| (34) |
|
| 34 | ||||
Total expense recognized | $ | 339 |
| $ | 338 |
| $ | 338 | ||||
|
|
|
|
|
|
|
|
| ||||
(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.
Postretirement Benefits Other than Pensions
2017 |
| 2016 |
| 2015 | ||||||||
Service cost | $ | 59 |
| $ | 52 |
| $ | 55 | ||||
Interest cost |
| 77 |
|
| 76 |
|
| 71 | ||||
Expected return on plan assets |
| (97) |
|
| (107) |
|
| (112) | ||||
Amortization of prior service cost |
| 15 |
|
| 15 |
|
| 19 | ||||
Amortization of net actuarial loss |
| 4 |
|
| 4 |
|
| 4 | ||||
Net periodic benefit cost | $ | 58 |
| $ | 40 |
| $ | 37 | ||||
|
|
|
| ||
(in millions) | Pension Plan |
| PBOP Plans | ||
Unrecognized prior service cost | $ | (6) |
| $ | 14 |
Unrecognized net loss |
| 5 |
|
| (5) |
Total | $ | (1) |
| $ | 9 |
| Pension Plan |
| PBOP Plans | ||||||||||||||
| December 31, |
| December 31, | ||||||||||||||
| 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | ||||||
Discount rate | 3.64 | % |
| 4.11 | % |
| 4.37 | % |
| 3.60- 3.67 | % |
| 4.05 - 4.19 | % |
| 4.27 - 4.48 | % |
Rate of future compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
increases | 3.90 | % |
| 4.00 | % |
| 4.00 | % |
| - |
|
| - |
|
| - |
|
Expected return on plan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
assets | 6.20 | % |
| 5.30 | % |
| 6.10 | % |
| 3.30 - 7.10 | % |
| 2.80 - 6.00 | % |
| 3.20 - 6.60 | % |
The assumed health care cost trend rate as of December 31, 2017 was 6.8%, decreasing gradually to an ultimate trend rate in 2025 and beyond of approximately 4.5%. A one-percentage-point change in assumed health care cost trend rate would have the following effects:
One-Percentage-Point |
| One-Percentage-Point | |||
(in millions) | Increase |
| Decrease | ||
Effect on postretirement benefit obligation | $ | 128 |
| $ | (129) |
Effect on service and interest cost |
| 9 |
|
| (10) |
| Pension Plan |
| PBOP Plans | ||||||||||||||||||||||||
| 2018 |
| 2017 |
| 2016 |
| 2018 |
| 2017 |
| 2016 | ||||||||||||||||
Global equity | 29 | % |
| 27 | % |
| 25 | % |
| 33 | % |
| 32 | % |
| 32 | % | ||||||||||
Absolute return | 5 | % |
| 5 | % |
| 5 | % |
| 3 | % |
| 3 | % |
| 3 | % | ||||||||||
Real assets | 8 | % |
| 10 | % |
| 10 | % |
| 6 | % |
| 7 | % |
| 7 | % | ||||||||||
Fixed income | 58 | % |
| 58 | % |
| 60 | % |
| 58 | % |
| 58 | % |
| 58 | % | ||||||||||
Total | 100 | % |
| 100 | % |
| 100 | % |
| 100 | % |
| 100 | % |
| 100 | % | ||||||||||
| Fair Value Measurements | ||||||||||||||||||||||||||||||||||||||
| At December 31, | ||||||||||||||||||||||||||||||||||||||
| 2017 |
| 2016 | ||||||||||||||||||||||||||||||||||||
(in millions) | Level 1 |
| Level 2 |
| Level 3 |
| Total |
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||||||||||||||||||||||
Pension Plan: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Short-term investments | $ | 287 |
| $ | 424 |
| $ | - |
| $ | 711 |
| $ | 364 |
| $ | 369 |
| $ | - |
| $ | 733 | ||||||||||||||||
Global equity |
| 1,292 |
|
| - |
|
| - |
|
| 1,292 |
|
| 996 |
|
| - |
|
| - |
|
| 996 | ||||||||||||||||
Real assets |
| 499 |
|
| - |
|
| - |
|
| 499 |
|
| 610 |
|
| - |
|
| - |
|
| 610 | ||||||||||||||||
Fixed-income |
| 1,916 |
|
| 5,520 |
|
| 4 |
|
| 7,440 |
|
| 1,754 |
|
| 4,774 |
|
| 5 |
|
| 6,533 | ||||||||||||||||
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| 6,818 |
|
| - |
|
| - |
|
| - |
|
| 5,950 | ||||||||||||||||
Total | $ | 3,994 |
| $ | 5,944 |
| $ | 4 |
| $ | 16,760 |
| $ | 3,724 |
| $ | 5,143 |
| $ | 5 |
| $ | 14,822 | ||||||||||||||||
PBOP Plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Short-term investments | $ | 31 |
| $ | - |
| $ | - |
| $ | 31 |
| $ | 33 |
| $ | - |
| $ | - |
| $ | 33 | ||||||||||||||||
Global equity |
| 141 |
|
| - |
|
| - |
|
| 141 |
|
| 115 |
|
| - |
|
| - |
|
| 115 | ||||||||||||||||
Real assets |
| 55 |
|
| - |
|
| - |
|
| 55 |
|
| 70 |
|
| - |
|
| - |
|
| 70 | ||||||||||||||||
Fixed-income |
| 163 |
|
| 757 |
|
| - |
|
| 920 |
|
| 150 |
|
| 656 |
|
| - |
|
| 806 | ||||||||||||||||
Assets measured at NAV |
| - |
|
| - |
|
| - |
|
| 1,281 |
|
| - |
|
| - |
|
| - |
|
| 1,153 | ||||||||||||||||
Total | $ | 390 |
| $ | 757 |
| $ | - |
| $ | 2,428 |
| $ | 368 |
| $ | 656 |
| $ | - |
| $ | 2,177 | ||||||||||||||||
Total plan assets at fair value |
|
|
|
|
|
|
|
|
| $ | 19,188 |
|
|
|
|
|
|
|
|
|
| $ | 16,999 | ||||||||||||||||
The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2017 and 2016:
| ||
(in millions) | Fixed- | |
For the year ended December 31, 2017 | Income | |
Balance at beginning of year | $ | 5 |
Actual return on plan assets: |
|
|
Relating to assets still held at the reporting date |
| (1) |
Relating to assets sold during the period |
| - |
Purchases, issuances, sales, and settlements: |
|
|
Purchases |
| 3 |
Settlements |
| (3) |
Balance at end of year | $ | 4 |
|
|
|
|
| |
(in millions) | Fixed- | |
For the year ended December 31, 2016 | Income | |
Balance at beginning of year | $ | 3 |
Actual return on plan assets: |
|
|
Relating to assets still held at the reporting date |
| 3 |
Relating to assets sold during the period |
| - |
Purchases, issuances, sales, and settlements: |
|
|
Purchases |
| - |
Settlements |
| (1) |
Balance at end of year | $ | 5 |
| Pension |
| PBOP |
| Federal | |||||||
(in millions) | Plan |
| Plans |
| Subsidy | |||||||
2018 | $ | 712 |
| $ | 83 |
| $ | (8) | ||||
2019 |
| 811 |
|
| 87 |
|
| (9) | ||||
2020 |
| 850 |
|
| 91 |
|
| (9) | ||||
2021 |
| 886 |
|
| 95 |
|
| (10) | ||||
2022 |
| 920 |
|
| 100 |
|
| (3) | ||||
Thereafter in the succeeding five years |
| 5,002 |
|
| 508 |
|
| (15) | ||||
|
| Year Ended December 31, | |||||||
(in millions) | 2017 |
| 2016 |
| 2015 | |||
Utility revenues from: |
|
|
|
|
| |||
Administrative services provided to PG&E Corporation | $ | 8 |
| $ | 7 |
| $ | 6 |
Utility expenses from: |
|
|
|
|
|
|
|
|
Administrative services received from PG&E Corporation | $ | 65 |
| $ | 74 |
| $ | 53 |
Utility employee benefit due to PG&E Corporation |
| 73 |
|
| 91 |
|
| 82 |
|
| Balance at | ||||
| December 31 |
| December 31, | ||
(in millions) | 2017 |
| 2016 | ||
Topock natural gas compressor station | $ | 334 |
| $ | 299 |
Hinkley natural gas compressor station |
| 147 |
|
| 135 |
Former manufactured gas plant sites owned by the Utility or third parties(1) |
| 320 |
|
| 285 |
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites(2) |
| 115 |
|
| 131 |
Fossil fuel-fired generation facilities and sites(3) |
| 123 |
|
| 108 |
Total environmental remediation liability | $ | 1,039 |
| $ | 958 |
|
|
|
|
|
|
(1) Primarily driven by the following sites: Vallejo, SF East Harbor, Napa, and SF North Beach
(2) Primarily driven by the Shell Pond site
(3) Primarily driven by the SF Potrero Power Plant site
| Power Purchase Agreements |
|
|
|
|
|
|
| ||||||||||||||||
| Renewable |
| Conventional |
|
|
| Natural |
| Nuclear |
|
|
| ||||||||||||
(in millions) | Energy |
| Energy |
| Other |
| Gas |
| Fuel |
| Total | |||||||||||||
2018 | $ | 2,150 |
| $ | 718 |
| $ | 280 |
| $ | 388 |
| $ | 96 |
| $ | 3,632 | |||||||
2019 |
| 2,193 |
|
| 706 |
|
| 221 |
|
| 167 |
|
| 102 |
|
| 3,389 | |||||||
2020 |
| 2,188 |
|
| 686 |
|
| 175 |
|
| 148 |
|
| 143 |
|
| 3,340 | |||||||
2021 |
| 2,168 |
|
| 588 |
|
| 153 |
|
| 93 |
|
| 70 |
|
| 3,072 | |||||||
2022 |
| 1,975 |
|
| 512 |
|
| 143 |
|
| 93 |
|
| 60 |
|
| 2,783 | |||||||
Thereafter |
| 26,005 |
|
| 657 |
|
| 526 |
|
| 357 |
|
| 151 |
|
| 27,696 | |||||||
Total purchase |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
commitments | $ | 36,679 |
| $ | 3,867 |
| $ | 1,498 |
| $ | 1,246 |
| $ | 622 |
| $ | 43,912 | |||||||
(in millions) | Operating Leases | |
2018 | $ | 44 |
2019 |
| 41 |
2020 |
| 40 |
2021 |
| 36 |
2022 |
| 27 |
Thereafter |
| 138 |
Total minimum lease payments | $ | 326 |
Loss Accrual (in millions) |
|
|
Balance at December 31, 2015 | $ | - |
Accrued losses |
| 750 |
Payments(1) |
| (60) |
Balance at December 31, 2016 |
| 690 |
Accrued losses |
| 350 |
Payments(1) |
| (479) |
Balance at December 31, 2017 | $ | 561 |
|
|
|
(1) As of December 31, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $624 million of which
$539 million has been paid by the Utility.
|
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
| Years Ended December 31, | |||||||
(in millions, except per share amounts) |
| 2017 |
|
| 2016 |
|
| 2015 |
Administrative service revenue | $ | 63 |
| $ | 70 |
| $ | 51 |
Operating expenses |
| (5) |
|
| (73) |
|
| (53) |
Interest income |
| 1 |
|
| 1 |
|
| 1 |
Interest expense |
| (11) |
|
| (10) |
|
| (10) |
Other income |
| 4 |
|
| 2 |
|
| 30 |
Equity in earnings of subsidiaries |
| 1,667 |
|
| 1,388 |
|
| 852 |
Income before income taxes |
| 1,719 |
|
| 1,378 |
|
| 871 |
Income tax provision (benefit) |
| 73 |
|
| (15) |
|
| (3) |
Net income | $ | 1,646 |
| $ | 1,393 |
| $ | 874 |
Other Comprehensive Income |
|
|
|
|
|
|
|
|
Pension and other postretirement benefit plans obligations (net of taxes of $0, |
|
|
|
|
|
|
|
|
$1, and $0, at respective dates) | $ | 1 |
| $ | (2) |
| $ | (1) |
Net change in investments (net of taxes of $0, $0, and $12, at respective dates) |
| - |
|
| - |
|
| (17) |
Total other comprehensive income (loss) |
| 1 |
|
| (2) |
|
| (18) |
Comprehensive Income | $ | 1,647 |
| $ | 1,391 |
| $ | 856 |
Weighted Average Common Shares Outstanding, Basic |
| 512 |
|
| 499 |
|
| 484 |
Weighted Average Common Shares Outstanding, Diluted |
| 513 |
|
| 501 |
|
| 487 |
Net earnings per common share, basic | $ | 3.21 |
| $ | 2.79 |
| $ | 1.81 |
Net earnings per common share, diluted | $ | 3.21 |
| $ | 2.78 |
| $ | 1.79 |
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED BALANCE SHEETS
Balance at December 31, | |||||||
(in millions) | 2017 |
| 2016 | ||||
ASSETS |
|
|
|
|
| ||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents | $ | 2 |
| $ | 106 | ||
Advances to affiliates |
| 24 |
|
| 24 | ||
Income taxes receivable |
| 27 |
|
| 25 | ||
Total current assets |
| 53 |
|
| 155 | ||
Noncurrent Assets |
|
|
|
|
| ||
Equipment |
| 3 |
|
| 2 | ||
Accumulated depreciation |
| (3) |
|
| (2) | ||
Net equipment |
| - |
|
| - | ||
Investments in subsidiaries |
| 19,514 |
|
| 18,172 | ||
Other investments |
| 144 |
|
| 133 | ||
Intercompany receivable |
| 72 |
|
| - | ||
Deferred income taxes |
| 123 |
|
| 267 | ||
Total noncurrent assets |
| 19,853 |
|
| 18,572 | ||
Total Assets | $ | 19,906 |
| $ | 18,727 | ||
|
|
|
|
|
| ||
LIABILITIES AND SHAREHOLDERS’ EQUITY |
|
|
|
|
| ||
Current Liabilities |
|
|
|
|
| ||
Short-term borrowings | $ | 132 |
| $ | - | ||
Accounts payable – other |
| 6 |
|
| 7 | ||
Other |
| 23 |
|
| 274 | ||
Total current liabilities |
| 161 |
|
| 281 | ||
Noncurrent Liabilities |
|
|
|
|
| ||
Long-term debt |
| 350 |
|
| 348 | ||
Other |
| 175 |
|
| 158 | ||
Total noncurrent liabilities |
| 525 |
|
| 506 | ||
Common Shareholders’ Equity |
|
|
|
|
| ||
Common stock |
| 12,632 |
|
| 12,198 | ||
Reinvested earnings |
| 6,596 |
|
| 5,751 | ||
Accumulated other comprehensive income (loss) |
| (8) |
|
| (9) | ||
Total common shareholders’ equity |
| 19,220 |
|
| 17,940 | ||
Total Liabilities and Shareholders’ Equity | $ | 19,906 |
| $ | 18,727 | ||
PG&E CORPORATION
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
Year ended December 31, | ||||||||
| 2017 |
| 2016 |
| 2015 | |||
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
Net income | $ | 1,646 |
| $ | 1,393 |
| $ | 874 |
Adjustments to reconcile net income to net cash provided by |
|
|
|
|
|
|
|
|
operating activities: |
|
|
|
|
|
|
|
|
Stock-based compensation amortization |
| 20 |
|
| 74 |
|
| 66 |
Equity in earnings of subsidiaries |
| (1,667) |
|
| (1,388) |
|
| (852) |
Deferred income taxes and tax credits-net |
| 139 |
|
| 11 |
|
| 10 |
Current income taxes receivable/payable |
| (2) |
|
| (1) |
|
| 5 |
Other |
| (75) |
|
| (24) |
|
| (70) |
Net cash provided by operating activities |
| 61 |
|
| 65 |
|
| 33 |
Cash Flows From Investing Activities: |
|
|
|
|
|
|
|
|
Investment in subsidiaries |
| (455) |
|
| (835) |
|
| (705) |
Dividends received from subsidiaries (1) |
| 784 |
|
| 911 |
|
| 716 |
Net cash provided by (used in) investing activities |
| 329 |
|
| 76 |
|
| 11 |
Cash Flows From Financing Activities: |
|
|
|
|
|
|
|
|
Borrowings (repayments) under revolving credit facilities |
| 132 |
|
| - |
|
| - |
Common stock issued |
| 395 |
|
| 822 |
|
| 780 |
Common stock dividends paid (2) |
| (1,021) |
|
| (921) |
|
| (856) |
Net cash provided by (used in) financing activities |
| (494) |
|
| (99) |
|
| (76) |
Net change in cash and cash equivalents |
| (104) |
|
| 42 |
|
| (32) |
Cash and cash equivalents at January 1 |
| 106 |
|
| 64 |
|
| 96 |
Cash and cash equivalents at December 31 | $ | 2 |
| $ | 106 |
| $ | 64 |
Supplemental disclosure of cash flow information |
|
|
|
|
|
|
|
|
Cash received (paid) for: |
|
|
|
|
|
|
|
|
Interest, net of amounts capitalized | $ | (9) |
| $ | (9) |
| $ | (9) |
Income taxes, net |
| - |
|
| (13) |
|
| - |
Supplemental disclosure of noncash investing and financing activities |
|
|
|
|
|
|
|
|
Noncash common stock issuances | $ | 21 |
| $ | 20 |
| $ | 21 |
Common stock dividends declared but not yet paid |
| - |
|
| 248 |
|
| 224 |
|
|
|
|
|
|
|
|
|
(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow.
(2) In July and October of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.53 per share.
In July and October of 2016 and January and April of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share.
In January, April, July, and October of 2015 and January and April of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
|
PG&E Corporation
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2017, 2016, and 2015
|
|
| Additions |
|
|
|
|
|
| |||||
Description |
| Balance at Beginning of Period |
|
| Charged to Costs and Expenses |
|
| Charged to Other Accounts |
|
| Deductions (2) |
|
| Balance at End of Period |
Valuation and qualifying accounts deducted from assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for uncollectible accounts (1) | $ | 58 |
| $ | 55 |
| $ | - |
| $ | 49 |
| $ | 64 |
2016: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for uncollectible accounts (1) | $ | 54 |
| $ | 50 |
| $ | - |
| $ | 46 |
| $ | 58 |
2015: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for uncollectible accounts (1) | $ | 66 |
| $ | 43 |
| $ | - |
| $ | 55 |
| $ | 54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
Pacific Gas and Electric Company
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2017, 2016, and 2015
|
|
| Additions |
|
|
|
|
|
| |||||||||||
Description |
| Balance at Beginning of Period |
|
| Charged to Costs and Expenses |
|
| Charged to Other Accounts |
|
| Deductions (2) |
|
| Balance at End of Period | ||||||
Valuation and qualifying accounts deducted from assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2017: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Allowance for uncollectible accounts (1) | $ | 58 |
| $ | 55 |
| $ | - |
| $ | 49 |
| $ | 64 | ||||||
2016: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Allowance for uncollectible accounts (1) | $ | 54 |
| $ | 50 |
| $ | - |
| $ | 46 |
| $ | 58 | ||||||
2015: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Allowance for uncollectible accounts (1) | $ | 66 |
| $ | 43 |
| $ | - |
| $ | 55 |
| $ | 54 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off
|
|
|
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