NOTES TO THE
CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 operating in 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.
On April 9, 2015, the CPUC approved final decisions in the three investigations pending against the Utility relating to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010. A decision was issued in each investigative proceeding to determine the violations that the Utility committed. The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion c
omprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.
The Penalty Decision requires that at least $688.5 million of the $850 million be allocated to capital expenditures and that the Utility be precluded from including these capital costs in rate base. The remainder will be allocated to safety-related expenses. (See Note 9.)
This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed 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 Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility operate in one segment.
The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2014 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2014 Form 10-K. This quarterly report should be read in conjunction with the 2014 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, asset retirement obligations, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. Actual results could differ materially from those estimates.
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the
2014
Form 10-K.
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
June 30,
2015
, 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
June 30,
2015
, it did not consolidate any of them.
Pension and Other Postretirement Benefits
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.
The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the
three and six months ended June 30, 2015 and 2014
were as follows:
|
|
Pension Benefits
|
|
Other Benefits
|
|
|
Three Months Ended June 30,
|
|
(in millions)
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
Service cost for benefits earned
|
$
|
118
|
|
$
|
96
|
|
$
|
14
|
|
$
|
11
|
|
Interest cost
|
|
169
|
|
|
173
|
|
|
18
|
|
|
19
|
|
Expected return on plan assets
|
|
(218)
|
|
|
(201)
|
|
|
(28)
|
|
|
(26)
|
|
Amortization of prior service cost
|
|
3
|
|
|
5
|
|
|
5
|
|
|
5
|
|
Amortization of net actuarial loss
|
|
3
|
|
|
1
|
|
|
1
|
|
|
1
|
|
Net periodic benefit cost
|
|
75
|
|
|
74
|
|
|
10
|
|
|
10
|
|
Regulatory account transfer
(1)
|
|
9
|
|
|
9
|
|
|
-
|
|
|
-
|
|
Total
|
$
|
84
|
|
$
|
83
|
|
$
|
10
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.
|
|
Pension Benefits
|
|
Other Benefits
|
|
|
Six Months Ended June 30,
|
|
(in millions)
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
Service cost for benefits earned
|
$
|
237
|
|
$
|
195
|
|
$
|
27
|
|
$
|
22
|
|
Interest cost
|
|
337
|
|
|
346
|
|
|
36
|
|
|
38
|
|
Expected return on plan assets
|
|
(436)
|
|
|
(403)
|
|
|
(56)
|
|
|
(52)
|
|
Amortization of prior service cost
|
|
7
|
|
|
10
|
|
|
10
|
|
|
11
|
|
Amortization of net actuarial loss
|
|
6
|
|
|
1
|
|
|
2
|
|
|
1
|
|
Net periodic benefit cost
|
|
151
|
|
|
149
|
|
|
19
|
|
|
20
|
|
Regulatory account transfer
(1)
|
|
18
|
|
|
19
|
|
|
-
|
|
|
-
|
|
Total
|
$
|
169
|
|
$
|
168
|
|
$
|
19
|
|
$
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below:
|
|
Pension
|
|
Other
|
|
|
|
|
|
Benefits
|
|
Benefits
|
|
Total
|
|
(in millions, net of income tax)
|
Three Months Ended June 30, 2015
|
|
Beginning balance
|
$
|
(21)
|
|
$
|
15
|
|
$
|
(6)
|
|
Amounts reclassified from other comprehensive income:
(1)
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost
|
|
|
|
|
|
|
|
|
|
(net of taxes of $1 and $2, respectively)
|
|
2
|
|
|
3
|
|
|
5
|
|
Amortization of net actuarial loss
|
|
|
|
|
|
|
|
|
|
(net of taxes of $2 and $1, respectively)
|
|
1
|
|
|
1
|
|
|
2
|
|
Regulatory account transfer
|
|
|
|
|
|
|
|
|
|
(net of taxes of $3 and $3, respectively)
|
|
(3)
|
|
|
(4)
|
|
|
(7)
|
|
Net current period other comprehensive loss
|
|
-
|
|
|
-
|
|
|
-
|
|
Ending balance
|
$
|
(21)
|
|
$
|
15
|
|
$
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.)
|
|
Pension
|
|
Other
|
|
Other
|
|
|
|
|
|
Benefits
|
|
Benefits
|
|
Investments
|
|
Total
|
|
(in millions, net of income tax)
|
Three Months Ended June 30, 2014
|
|
Beginning balance
|
$
|
(7)
|
|
$
|
15
|
|
$
|
47
|
|
$
|
55
|
|
Other comprehensive income before reclassifications:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in investments
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $0, $0, and $3, respectively)
|
|
-
|
|
|
-
|
|
|
5
|
|
|
5
|
|
Amounts reclassified from other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $2, $2, and $0, respectively)
(1)
|
|
3
|
|
|
3
|
|
|
-
|
|
|
6
|
|
Amortization of net actuarial loss
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $0, $0, and $0, respectively)
(1)
|
|
1
|
|
|
1
|
|
|
-
|
|
|
2
|
|
Regulatory account transfer
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $2, $2, and $0, respectively)
(1)
|
|
(4)
|
|
|
(4)
|
|
|
-
|
|
|
(8)
|
|
Change in investments
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $0, $0, and $10, respectively)
|
|
-
|
|
|
-
|
|
|
(16)
|
|
|
(16)
|
|
Net current period other comprehensive loss
|
|
-
|
|
|
-
|
|
|
(11)
|
|
|
(11)
|
|
Ending balance
|
$
|
(7)
|
|
$
|
15
|
|
$
|
36
|
|
$
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.)
|
|
Pension
|
|
Other
|
|
Other
|
|
|
|
|
|
Benefits
|
|
Benefits
|
|
Investments
|
|
Total
|
|
(in millions, net of income tax)
|
Six Months Ended June 30, 2015
|
|
Beginning balance
|
$
|
(21)
|
|
$
|
15
|
|
$
|
17
|
|
$
|
11
|
|
Amounts reclassified from other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $3, $4, and $0, respectively)
(1)
|
|
4
|
|
|
6
|
|
|
-
|
|
|
10
|
|
Amortization of net actuarial loss
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $3, $1, and $0, respectively)
(1)
|
|
3
|
|
|
1
|
|
|
-
|
|
|
4
|
|
Regulatory account transfer
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $6, $5, and $0, respectively)
(1)
|
|
(7)
|
|
|
(7)
|
|
|
-
|
|
|
(14)
|
|
Change in investments
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $0, $0, and $12, respectively)
|
|
-
|
|
|
-
|
|
|
(17)
|
|
|
(17)
|
|
Net current period other comprehensive loss
|
|
-
|
|
|
-
|
|
|
(17)
|
|
|
(17)
|
|
Ending balance
|
$
|
(21)
|
|
$
|
15
|
|
$
|
-
|
|
$
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.)
|
|
Pension
|
|
Other
|
|
Other
|
|
|
|
|
|
Benefits
|
|
Benefits
|
|
Investments
|
|
Total
|
|
(in millions, net of income tax)
|
Six Months Ended June 30, 2014
|
|
Beginning balance
|
$
|
(7)
|
|
$
|
15
|
|
$
|
42
|
|
$
|
50
|
|
Other comprehensive income before reclassifications:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in investments
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $0, $0, and $7, respectively)
|
|
-
|
|
|
-
|
|
|
10
|
|
|
10
|
|
Amounts reclassified from other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $4, $4, and $0, respectively)
(1)
|
|
6
|
|
|
7
|
|
|
-
|
|
|
13
|
|
Amortization of net actuarial loss
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $0, $0, and $0, respectively)
(1)
|
|
1
|
|
|
1
|
|
|
-
|
|
|
2
|
|
Regulatory account transfer
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $4, $4, and $0, respectively)
(1)
|
|
(7)
|
|
|
(8)
|
|
|
-
|
|
|
(15)
|
|
Change in investments
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of taxes of $0, $0, and $10, respectively)
|
|
-
|
|
|
-
|
|
|
(16)
|
|
|
(16)
|
|
Net current period other comprehensive loss
|
|
-
|
|
|
-
|
|
|
(6)
|
|
|
(6)
|
|
Ending balance
|
$
|
(7)
|
|
$
|
15
|
|
$
|
36
|
|
$
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.)
There was no material difference between PG&E Corporation and the Utility for the information disclosed above, with the exception of other investments which are held by PG&E Corporation.
Accounting Standards Issued But Not Yet Adopted
Fair Value Measurement
In May 2015, the F
ASB
issued
ASU
No. 2015-07,
Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)
, which standardizes reporting
practices related to the fair value hierarchy
for
all investments for which fair value is measured using the net asset value per share. The accounting stan
dards update will be effective for fiscal years beginning after
December 15, 2015.
PG&E Corporation and the Utility are currently evaluating the impact t
he guidance will have on their disclosures and
will adopt this standard starting in
the first quarter of
2016.
Accounting for Fees Paid in a Cloud Computing Arrangement
In April 2015, the F
ASB
issued
ASU
No. 2015-05,
Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
,
which adds guidance to help entities evaluate the accounting treatment for cloud computing arrangements. The accounting standards update will be effective on January 1, 2016. PG&E Corporation and the Utility are currently evaluating the impact t
he guidance will have on their consolidated financial statements and related disclosures and
will adopt this standard starting in
the first quarter of
2016.
Presentation of Debt Issuance Costs
In April 2015, the F
ASB
issued
ASU
No. 2015-03,
Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs
,
which amends existing presentation of debt issuance costs.
PG&E Corporation and the Utility currently disclose debt issuance costs in current assets – other and noncurrent assets – other.
The amendments in this Accounting Standard Update,
effective on January 1, 2016,
require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.
PG&E Corporation and the Utility do not expect this reclassification
to have a material impact on their
consolidated financial statements.
PG&E Corporation and the Utility will adopt this standard starting in the first quarter of 2016.
Revenue Recognition Standard
In May 2014, the FASB issued ASU No. 2014-09,
Revenue from Contracts with Customers,
which amends existing revenue recognition guidance
.
In July 2015, the FASB deferred the effective date of this amendment
for public companies
by one year to January 1, 2018
,
with early adoption permitted as of the original effective date of January 1, 2017.
PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures.
NOTE 3:
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets
Long-term regulatory assets are composed of the following:
|
|
Balance at
|
|
|
June 30,
|
|
December 31,
|
|
(in millions)
|
2015
|
|
2014
|
|
Pension benefits
|
$
|
2,316
|
|
$
|
2,347
|
|
Deferred income taxes
|
|
2,649
|
|
|
2,390
|
|
Environmental compliance costs
|
|
686
|
|
|
717
|
|
Utility retained generation
|
|
434
|
|
|
456
|
|
Price risk management
|
|
142
|
|
|
127
|
|
Unamortized loss, net of gain, on reacquired debt
|
|
103
|
|
|
113
|
|
Electromechanical meters
|
|
36
|
|
|
70
|
|
Other
|
|
110
|
|
|
102
|
|
Total long-term regulatory assets
|
$
|
6,476
|
|
$
|
6,322
|
|
|
|
|
|
|
|
Regulatory Liabilities
Long-term regulatory liabilities are composed of the following:
|
|
Balance at
|
|
|
June 30,
|
|
December 31,
|
|
(in millions)
|
2015
|
|
2014
|
|
Cost of removal obligations
|
$
|
4,414
|
|
$
|
4,211
|
|
Recoveries in excess of asset retirement obligations
|
|
719
|
|
|
754
|
|
Public purpose programs
|
|
708
|
|
|
701
|
|
Other
|
|
489
|
|
|
624
|
|
Total long-term regulatory liabilities
|
$
|
6,330
|
|
$
|
6,290
|
|
|
|
|
|
|
|
Regulatory Balancing Accounts
The Utility’s recovery of revenue requirements and costs is generally decoupled from the volume of sales.
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 Condensed Consolidated Balance Sheets. 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 composed of the following:
|
|
Receivable
|
|
|
Balance at
|
|
|
June 30,
|
|
December 31,
|
|
(in millions)
|
2015
|
|
2014
|
|
Electric distribution
|
$
|
672
|
|
$
|
344
|
|
Utility generation
|
|
392
|
|
|
261
|
|
Gas distribution
|
|
504
|
|
|
566
|
|
Energy procurement
|
|
308
|
|
|
608
|
|
Public purpose programs
|
|
82
|
|
|
109
|
|
Other
|
|
246
|
|
|
378
|
|
Total regulatory balancing accounts receivable
|
$
|
2,204
|
|
$
|
2,266
|
|
|
|
|
|
|
|
|
|
Payable
|
|
|
Balance at
|
|
|
June 30,
|
|
December 31,
|
|
(in millions)
|
2015
|
|
2014
|
|
Energy procurement
|
$
|
173
|
|
$
|
188
|
|
Public purpose programs
|
|
177
|
|
|
154
|
|
Other
(1)
|
|
526
|
|
|
748
|
|
Total regulatory balancing accounts payable
|
$
|
876
|
|
$
|
1,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
At
June 30,
2015
and December 31,
2014
,
Other regulatory balancing
accounts payable mostly included
energy supplier settlements related to the Utility’s outstanding bankruptcy claims.
(See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 9 below).
NOTE 4: DEBT
Short-term Borrowings
Revolving Credit Facilities and Commercial Paper Program
On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities that were entered into on April 1, 2013. The amendments and restatements extended the termination dates of the credit facilities from April 1, 2019 to April 27, 2020, reduced the amount of lender commitments to the letter of credit sublimits from $100 million to $50 million for PG&E Corporation’s credit facility and from $1.0 billion to $500 million for the Utility’s credit facility, and reduced the swingline commitment on the Utility’s credit facility from $300 million to $75 million.
The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at
June 30,
2015
:
|
|
|
|
|
|
Letters of
|
|
|
|
|
|
|
Termination
|
|
Facility
|
|
Credit
|
|
Commercial
|
|
Facility
|
|
(in millions)
|
Date
|
|
Limit
|
|
Outstanding
|
|
Paper
|
|
Availability
|
|
PG&E Corporation
|
April 2020
|
|
$
|
300
|
(1)
|
$
|
-
|
|
$
|
5
|
|
$
|
295
|
|
Utility
|
April 2020
|
|
|
3,000
|
(2)
|
|
33
|
|
|
1,011
|
|
|
1,956
|
|
Total revolving
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
credit facilities
|
|
|
$
|
3,300
|
|
$
|
33
|
|
$
|
1,016
|
|
$
|
2,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes a $
50
million sublimit for letters of credit 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
m
illion sublimit for letters of credit and a $75 million commitment for swingline loans.
In July 2015, the Utility increased the commercial paper program limit from $1.75 billion to $2.5 billion.
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.
Long-term Debt
Issuances and Maturities
In June 2015, the Utility issued $400 million principal amount of
3.50
% Senior Notes due June
15, 2025 and $100 million of 4.30% Senior Notes due March 15, 2045
. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. In addition, $300 million principal amount of
the Utility’s
Floating Rate Senior Notes
matured in May
2015.
Variable Rate Interest
At
June 30,
2015
, the interest rates on the $
614
million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from
0.01
% to
0.03
%. At
June 30,
2015
, the interest rates on the $
309
million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from
0.02
% to
0.03
%.
NOTE 5: EQUITY
PG&E Corporation’s and the Utility’s changes in equity for the
six
months ended
June 30,
2015
were as follows:
|
|
PG&E Corporation
|
|
Utility
|
|
|
Total
|
|
Total
|
|
(in millions)
|
Equity
|
|
Shareholders' Equity
|
|
Balance at December 31, 2014
|
$
|
16,000
|
|
$
|
16,229
|
|
Comprehensive income
|
|
423
|
|
|
410
|
|
Equity contributions
|
|
-
|
|
|
185
|
|
Common stock issued
|
|
262
|
|
|
-
|
|
Share-based compensation
|
|
34
|
|
|
4
|
|
Common stock dividends declared
|
|
(441)
|
|
|
(358)
|
|
Preferred stock dividend requirement
|
|
-
|
|
|
(7)
|
|
Preferred stock dividend requirement of subsidiary
|
|
(7)
|
|
|
-
|
|
Balance at June 30, 2015
|
$
|
16,271
|
|
$
|
16,463
|
|
|
|
|
|
|
|
In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $
500
million. In the first quarter of 2015, PG&E Corporation sold
1.4
million shares under this agreement for cash proceeds of $
74
million, net of commissions paid of $
1
million. No shares were sold during the
three
months ended
June 30,
2015
.
PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the
six
months ended
June 30,
2015
,
4.3
million shares were issued for cash proceeds of $
178
million under these plans.
NOTE 6: EARNINGS PER SHARE
PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
(in millions, except per share amounts)
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
Income available for common shareholders
|
$
|
402
|
|
$
|
267
|
|
$
|
433
|
|
$
|
494
|
|
Weighted average common shares outstanding, basic
|
|
480
|
|
|
467
|
|
|
479
|
|
|
463
|
|
Add incremental shares from assumed conversions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee share-based compensation
|
|
3
|
|
|
2
|
|
|
4
|
|
|
2
|
|
Weighted average common share outstanding, diluted
|
|
483
|
|
|
469
|
|
|
483
|
|
|
465
|
|
Total earnings per common share, diluted
|
$
|
0.83
|
|
$
|
0.57
|
|
$
|
0.90
|
|
$
|
1.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.
NOTE 7: DERIVATIVES
Use of Derivative Instruments
The Utility is exposed to commodity price risk as a result of its electricity and natur
al gas procurement activities.
Procurement costs are rec
overed 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 forward contracts, swaps, futures, options, and CRRs.
Derivatives are presented in the Utility’s Condensed Consolidat
ed Balance Sheets on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by c
ash 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 Condensed 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 as long as the current ratemaking mechanism remains in place and 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 Condensed 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 Condensed Consolidated
Balance Sheets at fair value. E
ligible derivatives are accounted for under the accrual method of accounting.
Volume of Derivative Activity
The volumes of the Utility’s outstanding derivatives were as follows:
|
|
|
|
|
Contract Volume at
|
|
|
|
|
|
June 30,
|
|
December 31,
|
|
Underlying Product
|
|
Instruments
|
|
2015
|
|
2014
|
|
Natural Gas
(1)
(MMBtus
(2)
)
|
|
Forwards and Swaps
|
|
267,835,872
|
|
308,130,101
|
|
|
|
Options
|
|
125,392,380
|
|
164,418,002
|
|
Electricity (Megawatt-hours)
|
|
Forwards and Swaps
|
|
4,904,985
|
|
5,346,787
|
|
|
|
Congestion Revenue Rights
(3)
|
|
197,344,663
|
|
224,124,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
June 30,
2015
, 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
|
$
|
70
|
|
$
|
(4)
|
|
$
|
15
|
|
$
|
81
|
|
Other noncurrent assets – other
|
|
156
|
|
|
(5)
|
|
|
-
|
|
|
151
|
|
Current liabilities – other
|
|
(70)
|
|
|
4
|
|
|
23
|
|
|
(43)
|
|
Noncurrent liabilities – other
|
|
(147)
|
|
|
5
|
|
|
19
|
|
|
(123)
|
|
Net commodity risk
|
$
|
9
|
|
$
|
-
|
|
$
|
57
|
|
$
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
2014
, 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
|
$
|
73
|
|
$
|
(4)
|
|
$
|
19
|
|
$
|
88
|
|
Other noncurrent assets – other
|
|
178
|
|
|
(13)
|
|
|
-
|
|
|
165
|
|
Current liabilities – other
|
|
(78)
|
|
|
4
|
|
|
26
|
|
|
(48)
|
|
Noncurrent liabilities – other
|
|
(140)
|
|
|
13
|
|
|
9
|
|
|
(118)
|
|
Net commodity risk
|
$
|
33
|
|
$
|
-
|
|
$
|
54
|
|
$
|
87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains and losses associated with price risk management activities were recorded as follows:
|
|
Commodity Risk
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
(in millions)
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
Unrealized gain (loss) - regulatory assets and liabilities
(1)
|
$
|
28
|
|
$
|
27
|
|
$
|
(24)
|
|
$
|
85
|
|
Realized gain (loss) - cost of electricity
(2)
|
|
10
|
|
|
(8)
|
|
|
3
|
|
|
(26)
|
|
Realized loss - cost of natural gas
(2)
|
|
(4)
|
|
|
(3)
|
|
|
(5)
|
|
|
(3)
|
|
Net commodity risk
|
$
|
34
|
|
$
|
16
|
|
$
|
(26)
|
|
$
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 Condensed 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 Condensed 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
June 30,
2015
, 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
|
|
|
June 30,
|
|
December 31,
|
|
(in millions)
|
2015
|
|
2014
|
|
Derivatives in a liability position with credit risk-related
|
|
|
|
|
|
|
contingencies that are not fully collateralized
|
$
|
(2)
|
|
$
|
(47)
|
|
Collateral posting in the normal course of business related to
|
|
|
|
|
|
|
these derivatives
|
|
-
|
|
|
44
|
|
Net position of derivative contracts/additional collateral
|
|
|
|
|
|
|
posting requirements
(1)
|
$
|
(2)
|
|
$
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 8: FAIR VALUE MEASUREMENTS
PG&E Corporation and the Utility measure their cash equivalents, trust assets, price risk management instruments, and other investments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:
-
Level
1 –
Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
-
Level
2 –
Other inputs that are directly or indirectly observable in the marketplace.
-
Level
3 –
Unobservable inputs which are supported by little or no market activities.
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 and other investments are held by PG&E Corporation and not the Utility):
|
|
Fair Value Measurements
|
|
|
At June 30, 2015
|
|
(in millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting
(1)
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market investments
|
$
|
109
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
109
|
|
Nuclear decommissioning trusts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market investments
|
|
32
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
32
|
|
Global equity securities
|
|
1,587
|
|
|
13
|
|
|
-
|
|
|
-
|
|
|
1,600
|
|
Fixed-income securities
|
|
681
|
|
|
541
|
|
|
-
|
|
|
-
|
|
|
1,222
|
|
Total nuclear decommissioning trusts
(2)
|
|
2,300
|
|
|
554
|
|
|
-
|
|
|
-
|
|
|
2,854
|
|
Price risk management instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity
|
|
1
|
|
|
8
|
|
|
212
|
|
|
6
|
|
|
227
|
|
Gas
|
|
1
|
|
|
4
|
|
|
-
|
|
|
-
|
|
|
5
|
|
Total price risk management instruments
|
|
2
|
|
|
12
|
|
|
212
|
|
|
6
|
|
|
232
|
|
Rabbi trusts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-income securities
|
|
-
|
|
|
42
|
|
|
-
|
|
|
-
|
|
|
42
|
|
Life insurance contracts
|
|
-
|
|
|
72
|
|
|
-
|
|
|
-
|
|
|
72
|
|
Total rabbi trusts
|
|
-
|
|
|
114
|
|
|
-
|
|
|
-
|
|
|
114
|
|
Long-term disability trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market investments
|
|
4
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
4
|
|
Global equity securities
|
|
-
|
|
|
22
|
|
|
-
|
|
|
-
|
|
|
22
|
|
Fixed-income securities
|
|
-
|
|
|
117
|
|
|
-
|
|
|
-
|
|
|
117
|
|
Total long-term disability trust
|
|
4
|
|
|
139
|
|
|
-
|
|
|
-
|
|
|
143
|
|
Total assets
|
$
|
2,415
|
|
$
|
819
|
|
$
|
212
|
|
$
|
6
|
|
$
|
3,452
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price risk management instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity
|
$
|
47
|
|
$
|
4
|
|
$
|
164
|
|
$
|
(51)
|
|
$
|
164
|
|
Gas
|
|
-
|
|
|
2
|
|
|
-
|
|
|
-
|
|
|
2
|
|
Total liabilities
|
$
|
47
|
|
$
|
6
|
|
$
|
164
|
|
$
|
(51)
|
|
$
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2)
Represents amount before deducting $
350
million, primarily related to deferred taxes on appreciation of investment value.
|
|
Fair Value Measurements
|
|
|
At December 31, 2014
|
|
(in millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting
(1)
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market investments
|
$
|
94
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
94
|
|
Nuclear decommissioning trusts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market investments
|
|
17
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
17
|
|
Global equity securities
|
|
1,585
|
|
|
13
|
|
|
-
|
|
|
-
|
|
|
1,598
|
|
Fixed-income securities
|
|
741
|
|
|
389
|
|
|
-
|
|
|
-
|
|
|
1,130
|
|
Total nuclear decommissioning trusts
(2)
|
|
2,343
|
|
|
402
|
|
|
-
|
|
|
-
|
|
|
2,745
|
|
Price risk management instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9 in the 2014 Form 10-K)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity
|
|
-
|
|
|
17
|
|
|
232
|
|
|
2
|
|
|
251
|
|
Gas
|
|
1
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
2
|
|
Total price risk management instruments
|
|
1
|
|
|
18
|
|
|
232
|
|
|
2
|
|
|
253
|
|
Rabbi trusts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-income securities
|
|
-
|
|
|
42
|
|
|
-
|
|
|
-
|
|
|
42
|
|
Life insurance contracts
|
|
-
|
|
|
72
|
|
|
-
|
|
|
-
|
|
|
72
|
|
Total rabbi trusts
|
|
-
|
|
|
114
|
|
|
-
|
|
|
-
|
|
|
114
|
|
Long-term disability trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market investments
|
|
7
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
7
|
|
Global equity securities
|
|
-
|
|
|
25
|
|
|
-
|
|
|
-
|
|
|
25
|
|
Fixed-income securities
|
|
-
|
|
|
128
|
|
|
-
|
|
|
-
|
|
|
128
|
|
Total long-term disability trust
|
|
7
|
|
|
153
|
|
|
-
|
|
|
-
|
|
|
160
|
|
Other investments
|
|
33
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
33
|
|
Total assets
|
$
|
2,478
|
|
$
|
687
|
|
$
|
232
|
|
$
|
2
|
|
$
|
3,399
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price risk management instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 9 in the 2014 Form 10-K)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity
|
$
|
47
|
|
$
|
5
|
|
$
|
163
|
|
$
|
(52)
|
|
$
|
163
|
|
Gas
|
|
-
|
|
|
3
|
|
|
-
|
|
|
-
|
|
|
3
|
|
Total liabilities
|
$
|
47
|
|
$
|
8
|
|
$
|
163
|
|
$
|
(52)
|
|
$
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2)
Represents amount before deducting $324 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. Investments, primarily consisting of equity securities, that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days. Equity investments valued at net asset value per share utilize investment strategies aimed at matching the performance of indexed funds. 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
six
months ended
June 30,
2015
and
2014
.
Trust Assets
Nuclear decommissioning trust assets and other trust assets are composed primarily of equity securities, debt securities, and life insurance policies. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.
Equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world. Investments in these funds are classified as Level 2 because price quotes are readily observable and available.
Debt 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.
Price Risk Management Instruments
Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, 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 forwards and swaps 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 forwards and swaps, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded 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 h
edge the financial risk of California Independent System Operator
-imposed congestion charges in the day-ahead market. CRRs are classified as Level 3 and are valued based on CRR auction prices, including historical prices. Limited market data is available in the C
alifornia Independent System Operator
auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions.
Level 3 Measurements and Sensitivity Analysis
The Utility’s market and credit risk management function, which reports to the Chief Risk Officer of the Utility, 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
7
above.)
|
|
|
Fair Value at
|
|
|
|
|
|
|
|
|
(in millions)
|
|
At June 30, 2015
|
|
Valuation
|
|
Unobservable
|
|
|
|
|
Fair Value Measurement
|
|
Assets
|
|
Liabilities
|
|
Technique
|
|
Input
|
|
Range
(1)
|
|
Congestion revenue rights
|
|
$
|
212
|
|
$
|
62
|
|
Market approach
|
|
CRR auction prices
|
|
$
|
(47.09) - 8.17
|
|
Power purchase agreements
|
|
$
|
-
|
|
$
|
102
|
|
Discounted cash flow
|
|
Forward prices
|
|
$
|
22.04 - 57.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Represents price per megawatt-hour
|
|
|
Fair Value at
|
|
|
|
|
|
|
|
|
(in millions)
|
|
At December 31, 2014
|
|
Valuation
|
|
Unobservable
|
|
|
|
|
Fair Value Measurement
|
|
Assets
|
|
Liabilities
|
|
Technique
|
|
Input
|
|
Range
(1)
|
|
Congestion revenue rights
|
|
$
|
232
|
|
$
|
63
|
|
Market approach
|
|
CRR auction prices
|
|
$
|
(15.97) - 8.17
|
|
Power purchase agreements
|
|
$
|
-
|
|
$
|
100
|
|
Discounted cash flow
|
|
Forward prices
|
|
$
|
16.04 - 56.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Represents price per megawatt-hour
Level 3 Reconciliation
The following tables present the reconciliation for Level 3 price risk management instruments for the
three and six months ended June 30, 2015 and 2014
:
|
|
Price Risk Management Instruments
|
|
(in millions)
|
2015
|
|
2014
|
|
Asset (liability) balance as of April 1
|
$
|
42
|
|
$
|
(22)
|
|
Net realized and unrealized gains:
|
|
|
|
|
|
|
Included in regulatory assets and liabilities or balancing accounts
(1)
|
|
6
|
|
|
11
|
|
Asset (liability) balance as of June 30
|
$
|
48
|
|
$
|
(11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.
|
|
Price Risk Management Instruments
|
|
(in millions)
|
2015
|
|
2014
|
|
Asset (liability) balance as of January 1
|
$
|
69
|
|
$
|
(30)
|
|
Net realized and unrealized gains:
|
|
|
|
|
|
|
Included in regulatory assets and liabilities or balancing accounts
(1)
|
|
(21)
|
|
|
19
|
|
Asset (liability) balance as of June 30
|
$
|
48
|
|
$
|
(11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.
Financial Instruments
PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:
-
The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, floating rate senior notes, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at
June 30,
2015
and December 31,
2014
, as they are short-term in nature or have interest rates that reset daily.
-
The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at
June 30,
2015
and December 31,
2014
.
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 June 30, 2015
|
|
At December 31, 2014
|
|
(in millions)
|
Carrying Amount
|
|
Level 2 Fair Value
|
|
Carrying Amount
|
|
Level 2 Fair Value
|
|
PG&E Corporation
|
$
|
350
|
|
$
|
351
|
|
$
|
350
|
|
$
|
352
|
|
Utility
|
|
14,272
|
|
|
15,715
|
|
|
13,778
|
|
|
15,851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market investments
|
$
|
32
|
|
$
|
-
|
|
$
|
-
|
|
$
|
32
|
|
Global Equity securities
|
|
516
|
|
|
1,091
|
|
|
(7)
|
|
|
1,600
|
|
Fixed Income securities
|
|
1,169
|
|
|
60
|
|
|
(7)
|
|
|
1,222
|
|
Total
(1)
|
$
|
1,717
|
|
$
|
1,151
|
|
$
|
(14)
|
|
$
|
2,854
|
|
As of December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market investments
|
$
|
17
|
|
$
|
-
|
|
$
|
-
|
|
$
|
17
|
|
Global Equity securities
|
|
520
|
|
|
1,087
|
|
|
(9)
|
|
|
1,598
|
|
Fixed-income securities
|
|
1,059
|
|
|
75
|
|
|
(4)
|
|
|
1,130
|
|
Total nuclear decommissioning trusts
(1)
|
|
1,596
|
|
|
1,162
|
|
|
(13)
|
|
|
2,745
|
|
Other investments
|
|
5
|
|
|
28
|
|
|
-
|
|
|
33
|
|
Total
|
$
|
1,601
|
|
$
|
1,190
|
|
$
|
(13)
|
|
$
|
2,778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Represents amounts before deducting $
350
million and $324 million at
June 30,
2015
and December 31,
2014
, respectively, primarily related to deferred taxes on appreciation of investment value.
The fair value of debt securities by contractual maturity is as follows:
|
|
As of
|
|
(in millions)
|
June 30, 2015
|
|
Less than 1 year
|
$
|
19
|
|
1–5 years
|
|
458
|
|
5–10 years
|
|
277
|
|
More than 10 years
|
|
468
|
|
Total maturities of debt securities
|
$
|
1,222
|
|
|
|
|
The following table provides a summary of activity for the debt and equity securities:
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2015
|
|
2014
|
|
|
2015
|
|
2014
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales and maturities of nuclear decommissioning
|
|
|
|
|
|
|
|
|
|
|
|
|
trust investments
|
$
|
362
|
|
$
|
347
|
|
$
|
779
|
|
$
|
877
|
|
Gross realized gains on securities held as available-for-sale
|
|
12
|
|
|
28
|
|
|
47
|
|
|
84
|
|
Gross realized losses on securities held as available-for-sale
|
|
(10)
|
|
|
(2)
|
|
|
(13)
|
|
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 9: 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. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows also may be affected by the outcome of the following matters.
Enforcement and Litigation Matters
Improper CPUC Communications
In the Penalty Decision (further described below)
, the CPUC stated that it will begin a new investigation to examine allegations by the City of San Bruno that communications between the Utility’s employees and CPUC personnel violated the CPUC’s rules relating to ex parte communications. Ex parte communications include any communication between a decision maker and an interested person concerning substantive issues in certain identified categories of formal proceedings before the CPUC. The Utility believes that the communications cited by San Bruno are not prohibited ex parte communications. If the CPUC determines that the communications constitute ex parte violations, it is reasonably possible that the CPUC will impose penalties or other remedies, but the Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining the final penalties.
In
September
2014, t
he Utility
notified the CPUC of ex parte communications between the Utility and the CPUC regarding the 2015 GT&S rate case. In November 2014, the CPUC imposed a fine of $1.05 million on the Uti
lity for these communications.
In addition, the CPUC disallowed the Utility from recovering up to the entire amount of the revenue increase that may be authorized in the
pending
GT&S rate case and that otherwise would have been collected from rate
payers over a five-month period.
The CPUC will determine the amount of this disallowance when it issues its decision to authorize the Utility’s GT&S revenue requirements.
In
October and December
2014, t
he Utility also notified the CPUC of additional email communications between the Utility and the CPUC regarding various matters (not limited to the GT&S rate case) that the Utility believes may constitute or describe ex parte communications.
For these additional communications, the Utility believes it is probable that CPUC enforcement action will be taken. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining the final penalties.
On May 21, 2015,
the Utility
filed various documents (including copies of internal email correspondence) with the
CPUC
to complete its response to orders issued by CPUC administrative law judges regarding potential ex parte communications between the Utility and CPUC personnel. The Utility also notified the CPUC of an additional potential ex parte communication made in the 2011 General Rate Case to supplement a notification that the Utility voluntarily provided on October 6, 2014. It is uncertain what action the CPUC or other parties will take in response to these additional reported communications. It is possible that additional orders will be issued to which the Utility will be required to respond. The CPUC could impose fines and penalties on the Utility
relating to communications reported to the CPUC or with respect to additional communications that the Utility may identify and report in response to new orders that may be issued or in connection with new or ongoing investigations or legal proceedings
.
The U.S. Attorney’s Office in San Francisco and the California Attorney General’s office have also begun investigations in connection wi
th the ex parte communications
.
The Utility is cooperating with the federal and state investigators.
It is uncertain whether any charges will be brought against the Utility
.
Other CPUC Matters
CPUC Investigation Regarding Natural Gas Distribution Facilities
Record-Keeping
On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaining to record-keeping practices for its natural gas distribution service and facilities. The order also requires the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. In particular, the order cites the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014. On April 10, 2015, the assigned Commissioner issued a scoping memo and ruling stating that the scope of the proceeding is whether or not the Utility violated any applicable laws, rules, or regulations “by its record-keeping policies and practices with respect to maintaining safe operation of its gas distribution system.” The scope of the proceeding also may include matters resulting from the SED’s ongoing reviews of the Utility’s record-keeping practices relating to mapping, pre-excavation location and marking, and pressure validation for distribution facilities, among other issues.
The procedural schedule requires the SED’s and intervenors’ testimony to be submitted starting in September 2015 with the Utility’s response due in November 2015
,
followed by rebuttal testimony in December 2015. Hearings are scheduled for January 2016.
PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose penalties on the Utility or require the Utility to implement operational remedies. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining penalties
and given the fact that the extent of any alleged violations is currently unknown
. In addition, the Utility could incur material costs to implement operational remedies, which may not be recoverable.
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 has been completed and that remediation work, including removal of the encroachments, is expected to continue for several years. The S
ED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility or take other enforcement action in the future based on the Utility’s failure to continuously survey its system and remove encroachments. T
he 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.
In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations.
The SED has authority to issue citations and impose fines for violations identified through audits, investigations, or self-reports.
The SED can consider various factors in determining whether to impose fines and the amount of fines, including the severity of the safety risk associated with each violation, the number and duration of the violations, whether the violation was self-reported, and whether corrective actions were taken.
The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of natural gas laws and regulations.
The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with natural gas laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.
Federal
Matters
Federal Criminal Indictment
On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court
that succeeded
the
original
indictment that
was
returned on April 1, 2014. The superseding indictment charges 27 felony counts alleging
that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to recordkeeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also seeks an alternative fine under the Alternative Fines Act which states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.” Based on the superseding indictment’s allegations that the Utility derived gross gains of approximately $281 million and that the victims suffered losses of approximately $565 million, the maximum alternat
ive
fine would be approximately $1.13 billion.
The Utility entered a plea of not guilty.
The Utility believes that criminal charges and the alternat
ive
fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged
in the superseding indictment.
PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Condensed Consolidated Financial Statements as such amounts are not considered to be probable.
The trial is set to begin March 8, 2016.
Other Federal
Matters
T
he Utility was informed that the U.S. Attorney’s Office was
investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. (For more information refer to Note 14 of the Notes to the Consolidated Financial Statements app
earing under Item 8 in the 2014
Form 10-K).
It is uncertain whether any charges will be brought against the Utility
.
The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case.
Capital Expenditures relating to Pipeline Safety Enhancement Pla
n
At
June 30, 2015
, approximately $
645
million of PSEP-related capital costs is recorded in property, plant, and equipment on the Condensed Consolidated Balance Sheets.
The Utility would be required to record charges
to the statement of income
in future periods to the extent PSEP-related capital costs are higher than currently expected.
Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission
The Penalty Decision (see Note 1 above) imposes penalties on the Utility totaling $1.6 billion c
omprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.
For the three months and six months ended June 30, 2015, the Utility recorded additional charges of $75 million and $628 million, respectively, as a result of the Penalty Decision. The cumulative charges at June 30, 2015, and the anticipated future financial impact are shown in the following table:
|
|
|
|
|
|
|
|
Anticipated
|
|
|
|
|
|
Six Months
|
|
Cumulative
|
|
Future
|
|
|
|
|
Ended
|
|
Charges
|
|
Financial
|
|
Total
|
|
(in millions)
|
June 30, 2015
|
|
June 30, 2015
|
|
Impact
|
|
Amount
|
|
Fine payable to the state
(1)
|
$
|
100
|
|
$
|
300
|
|
$
|
-
|
|
$
|
300
|
|
Customer bill credit
|
|
400
|
|
|
400
|
|
|
-
|
|
|
400
|
|
Charge for disallowed capital
(2)
|
|
128
|
|
|
128
|
|
|
561
|
|
|
689
|
|
Disallowed revenue for pipeline safety
|
|
|
|
|
|
|
|
|
|
|
|
|
expenses
(3)
|
|
-
|
|
|
-
|
|
|
161
|
|
|
161
|
|
CPUC estimated cost of other remedies
(4)
|
|
-
|
|
|
20
|
|
|
30
|
|
|
50
|
|
Total Penalty Decision fines and remedies
|
|
|
|
|
|
|
|
|
|
|
|
|
recorded
|
$
|
628
|
|
$
|
848
|
|
$
|
752
|
|
$
|
1,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In March 2015, t
he Utility increased its accrual from $200 million at Decem
ber 31, 2014 to $300 million.
(
2
)
The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate case.
The Utility estimates that approximately $75 million and $128 million of capital spending (which include less than $1 million for remedy related capital costs)
in the three months and six months ended June 30, 2015, respectively, are probable of disallowance, subject to adjustment based on the fina
l 2015 GT&S rate case decision.
(
3
)
These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.
(
4
)
In the Penalty Decision, the CPUC estimates that the Utility would incur $50 million to comply with the other remedies in the Penalty Decision, including $30 million to reimburse the CPUC for the costs of future audits.
Remedial costs are expensed as incurred. Other than the refund of CPUC audit
costs, the majority of the remedies have been completed or are underway and the associated costs have already been incurred.
At June 30, 2015, the Condensed Consolidated Balance Sheets include $300 million in other current liabilities for the fines payable, and $400 million in current regulatory liabilities for the one-time bill credit due to the Utility’s natural gas customers.
The charges recorded are reflected in operating and maintenance expenses in the June 30, 2015, Condensed Consolidated Statements of Income.
The Penalty Decision requires that at least $688.5 million of the $850 million be allocated to capital expenditures and that the Utility be precluded from including these capital costs in rate base. The remainder will be allocated to safety-related expenses. The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case. If the $850 million is not exhausted by designated safety-related projects and programs in the GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent.
It is uncertain what costs the CPUC will ultimately count towards the $850 million shareholder-funded obligation.
To the extent the Utility’s actual costs exceed qualified amounts and are not authorized for recovery, the Utility may be required to record additional charges in future periods.
The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify the safety-related project and programs that will be subject to the disallowance.
Other Legal and Regulatory Contingencies
Accruals for other legal and regulatory contingencies (excluding amounts related to the enforcement and litigation matters described above) totaled
$
43
million at
June 30
, 2015, and $55
million at December 31, 2014. These amounts are included in other current liabilities in the Condensed 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.
Environmental Remediation Contingencies
The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following:
|
|
Balance at
|
|
(in millions)
|
June 30, 2015
|
|
December 31, 2014
|
|
Topock natural gas compressor station
(1)
|
$
|
297
|
|
$
|
291
|
|
Hinkley natural gas compressor station
(1)
|
|
149
|
|
|
158
|
|
Former manufactured gas plant sites owned by the Utility or third parties
|
|
263
|
|
|
257
|
|
Utility-owned generation facilities (other than fossil fuel-fired),
other facilities, and third-party disposal sites
|
|
153
|
|
|
150
|
|
Fossil fuel-fired generation facilities and sites
|
|
96
|
|
|
98
|
|
Total environmental remediation liability
|
$
|
958
|
|
$
|
954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
See “Natural Gas Compressor Station Sites” below.
At
June 30,
2015
,
the Utility expected to recover $
676
m
illion of its environmental remediation liability through various ratemaking mech
anisms authorized by the CPUC
. The Utility will also incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.
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. One of these stations is located near Hinkley, California and is referred to below as the “Hinkley site.” Another station is located near Needles, California and is referred to below as the “Topock site.” The Utility is also required to take measures to abate the effects of the contamination on the environment.
Hinkley Site
The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume and to monitor and control movement of the plume. The Utility's remediation and abatement efforts at the Hinkley site are
overseen by
the Regional Board.
I
n
January
2015, the Regional Board issued a
n
updated
draft clean-up and ab
atement order that proposes
the Utility continue
s
and improve
s
its remedial treatment methods
and contains
a proposed monitoring and reporting program
.
The Regional Board is expected to issue a revised draft clean-up and abatement order in August 2015. After a public com
ment period, the Regional Board
is
expected to consider
adop
tion of a
final clean-up and abatement order
(which may include deadlines to meet specified interim clean up targets)
at its November 2015 meeting.
The Utility’s environmental remediation liability at
June 30,
2015
reflects the Utility’s best estimate of probable future costs associated with its final remediation plan and interim remediation measures. Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, and the nature and extent of the chromium contamination. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, and cash flows.
Topock Site
The Utility's remediation and abatement efforts at the Topock site are overseen by the
DTSC
and the U.S. Department of the Interior. While the Utility has been working with these agencies to develop a final remediation plan, the Utility has been employing various interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River. In September 2014, the Utility submitted its near-final remediation plan to the agencies for approval. The Utility’s plan 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.
The DTSC is conducting an
additional
environmental review of the proposed plan
,
and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in December 2016. After the Utility modifies its plan
in response to the final report,
the Utility
plans to
seek approval to begin construction of the new in-situ treatment system
in early 2017.
The Utility's environmental remediation liability at June 30, 2015 reflects its best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the scope and timing of required remediation work. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.
Reasonably Possible Environmental Contingencies
Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase to as much as $
1.8
billion (including amounts related to the Hinkley and Topock sites described above) if the extent of contamination or necessary remediation is greater than anticipated or if th
e other potentially responsible parties are not financially able to contribute to these costs. 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 during th
e period in which they are recorded.
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.
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.
At December 31,
2014
,
the Consolidated Balance Sheets reflected $
434
million in net claims, within Disputed claims and customer refunds, and
$
291
million of cash in escrow for payment of the remaining net disputed claims, within Restricted cash.
There were no significant changes to these balances during the
six
months ended
June 30,
2015
.
Tax Matters
The IRS is currently reviewing several matters in the 2011, 2012, and 2013 tax returns.
The most significant relates to a 2011 accounting method change to adopt guidance issued by the IRS in determining
which repair costs are deductible for the electric transmission and distribution businesses.
PG&E Corporation and the Utility expect that the IRS will complete its review of the deductible repair costs for the electric transmission and distribution businesses in 2015.
The IRS is also expected to issue guidance during 2015 that determines which repair costs are deductible for the natural gas transmission and distribution businesses.
PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months depending on the IRS guidance that is issued and the resolution of the audits related to the 2011, 2012, and 2013 tax returns. As of
June 30
, 2015, it is reasonably possible that unrecognized tax benefits will decrease by approximately $
370
million within the next 12 months, and most of this decrease would not impact net income.
There were no other significant developments to tax matters during the
six
months ended
June 30
, 2015.
(Refer to Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K.)
Purchase Commitments
In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments.
At December 31, 2014 t
he Utility
had
undiscounted future expected obligations
of approximately $53.3 billion. (See
Note 14 of the Notes to the Consolidated Financ
ial Statements in Item 8 of the
2014 Form 10-K
.
)
During the six months ended June 30, 2015, the Utility entered into several renewable energy and other power purchase agreements that were approved by the CPUC and completed major milestones with respect to construction, resulti
ng in additional commitments
of
approximately
$465 million over the next 2
5
years.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.
The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility also is subject to the jurisdiction of other federal, state, and local governmental agencies.
This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report. It should also be read in conjunction with the 2014 Form 10-K.
Summary of Changes in Net Income and Earnings per Share
The following table is a summary reconciliation of the key changes, after-tax, in PG&E Corporation’s income available for common shareholders and EPS
(as well as earnings from operations and EPS on an earnings from operations basis)
compared to the same period in the prior year (see “Results of Operations” below).
“
Earnings from operations
”
is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability.
“
Items impacting comparability
” represent items that management does not consider part of
the normal course of
operations
and affect comparability of financial results between periods.
PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating plans, and
employee
incentive
compensation
.
PG&E Corporation believes that earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance
. E
arnings from operations
are not a substitute or alternative for
GAAP measures such as income av
ailable for common shareholders
and may not be comparable to similarly titled measures used by other
companies.
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
|
EPS
|
|
|
|
|
EPS
|
|
(in millions, except per share amounts)
|
Earnings
|
|
(Diluted)
|
|
Earnings
|
|
(Diluted)
|
|
Income Available for Common Shareholders - 2014
|
$
|
267
|
|
$
|
0.57
|
|
$
|
494
|
|
$
|
1.06
|
|
Natural gas matters
(1)
|
|
57
|
|
|
0.12
|
|
|
81
|
|
|
0.18
|
|
Earnings from Operations - 2014
(2)
|
$
|
324
|
|
$
|
0.69
|
|
$
|
575
|
|
$
|
1.24
|
|
2014 GRC cost recovery
(3)
|
|
99
|
|
|
0.21
|
|
|
198
|
|
|
0.41
|
|
Growth in rate base earnings
|
|
26
|
|
|
0.05
|
|
|
52
|
|
|
0.11
|
|
Nuclear refueling outage
|
|
-
|
|
|
-
|
|
|
26
|
|
|
0.05
|
|
Timing of taxes
(4)
|
|
18
|
|
|
0.04
|
|
|
38
|
|
|
0.08
|
|
Gain on disposition of SolarCity
stock
(5)
|
|
(14)
|
|
|
(0.03)
|
|
|
-
|
|
|
-
|
|
Timing of 2015 GT&S cost recovery
(6)
|
|
(44)
|
|
|
(0.09)
|
|
|
(80)
|
|
|
(0.17)
|
|
Increase in shares outstanding
|
|
-
|
|
|
(0.02)
|
|
|
-
|
|
|
(0.05)
|
|
Other
|
|
33
|
|
|
0.06
|
|
|
51
|
|
|
0.11
|
|
Earnings from Operations - 2015
(2)
|
$
|
442
|
|
$
|
0.91
|
|
$
|
860
|
|
$
|
1.78
|
|
Pipeline-related expenses
(7)
|
|
(9)
|
|
|
(0.02)
|
|
|
(19)
|
|
|
(0.04)
|
|
Legal and regulatory related expenses
(7)
|
|
(10)
|
|
|
(0.02)
|
|
|
(18)
|
|
|
(0.04)
|
|
Fines and penalties
(8)
|
|
(44)
|
|
|
(0.09)
|
|
|
(413)
|
|
|
(0.85)
|
|
Insurance recoveries
(9)
|
|
23
|
|
|
0.05
|
|
|
23
|
|
|
0.05
|
|
Income Available for Common Shareholders - 2015
|
$
|
402
|
|
$
|
0.83
|
|
$
|
433
|
|
$
|
0.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In 2014, natural gas matters included pipeline-related costs to perform work under the PSEP and other activities associated with safety improvements to the Utility's natural gas system, as well as legal
and other costs related to natural gas matters. Natural gas matters also included charges recorded related to fines, third party liability claims, and insurance recoveries in 2014.
(2)
"Earnings from operations" is not calculated in accordance with GAAP and excludes the items impacting comparability shown in Note (1) above and Notes (6), (7), and (8) below.
(3)
Represents the increase in base revenues authorized by the CPUC in the 2014 GRC decision for the three and six months ended June 30, 2015, including the impact of flow-through ratemaking treatment for federal tax deductions for repairs. In 2014, the Utility was incurring approximately $200 million of expense and $1 billion of capital costs above authorized levels until the 2014 GRC decision authorized revenues that supported this higher level of spending. The increase in revenue related to 2014 was not recognized until the quarter ended September 30, 2014, when the 2014 GRC decision was issued.
(4)
Represents the timing of taxes reportable in quarterly financial statements.
(5)
Represents the comparative negative impact of a gain recognized during the three months ended June 30, 2014 as compared to the three months ended June 30, 2015 during which no comparable gain was recognized.
For the six months ended June 30, 2015, this comparative negative impact was offset by a gain recognized during the three months ended March 31, 2015.
(6)
Represents expenses reflected in Earnings from Operations during the three and six months ended June 30, 2015 as compared to the same periods in 2014, with no corresponding increase in revenue. The Utility has requested the CPUC authorize an increase to its revenue requirements for 2015, 2016, and 2017 in its GT&S rate case. Based on the procedural schedule, it is unlikely that the Utility will be able to recognize any increase in its GT&S revenue in 2015.
(7)
In 2015, pipeline-related expenses includes costs incurred to identify and remove encroachments from transmission pipeline rights of way and to perform remaining work under the Utility's PSEP. Legal and regulatory related expenses includes various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.
(8)
Represents the impact of the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements for before-tax amounts).
(9)
Insurance recoveries related to third-party claims and associated legal costs recognized in the three and six months ended June 30, 2015 (See "Results of Operations" below).
Key Factors Affecting Financial Results
PG&E Corporation and the Utility believe that their
future
results of operations, financial condition, and cash flows will be materiall
y affected by the following factors:
|
•
|
Penalties, Fines and Remedial Costs.
Future financial results will be impacted by the timing and amount of disallowed costs the Utility incurs for designated pipeline safety-related projects and programs and to implement remedial measures, as required by the Penalty Decision. The Utility also could be required to pay fines associated with pending federal criminal charges alleging that the Utility knowingly and willfully violated the Pipeline Safety Act and illegally obstructed the NTSB’s investigation into the cause of the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010. Based on the superseding indictment’s allegations, the maximum statutory fine would be $14 million and the maximum alternative fine would be approximately $1.13 billion. Federal and state authorities also are conducting investigations in connection with certain communications between the Utility and CPUC personnel. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case. Fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to these and other enforcement matters, including new CPUC investigations. (See “Enforcement and Litigation Matters”
in Note 9 of the Notes to the Condensed Consolidated Financial Statements
.)
|
|
|
|
|
•
|
The Timing and Outcome of Ratemaking Proceedings.
In the GT&S rate case, the Utility has requested that the CPUC authorize revenue requirements for the Utility’s gas transmission and storage operations from 2015 through 2017. The Utility has requested an increase in its 2015 revenue requirements of $555 million over the comparable authorized revenues, as well as increases for 2016 and 2017. Based on the scoping ruling and procedural schedule that was issued on June 11, 2015, the CPUC
is expected to issue
a
two-part decision, the first decision to authorize GT&S revenue requirements (which would reflect a
potential
disallowance to be imposed as a penalty for the Utility’s violation of the CPUC’s ex parte communication rules
as well as a reduction in the Utility's request to reflect any costs associated with implementing the remedies ordered by the Penalty Decision
), and a second decision to reduce the authorized revenue requirements by the costs of designated safety-related projects and programs up to the $850 million maximum cost disallowance imposed by the Penalty Decision
. Any revenue requirement increase would be retroactive to January 1, 2015. Based on the procedural schedule it is unlikely that
the Utility will be able to recognize any increase in GT&S revenues
in
2015.
If the Utility does not recognize any increase in 2015, the authorized revenue increase would be recorded in 2016.
(See “Ratemaking Proceedings” below for more information.) In addition, the Utility intends to file its 2017 GRC application with the CPUC by September 2015, to request that the CPUC authorize revenue requirements for the Utility’s electric generation business and its electric and natural gas distribution business for 2017 and future years. The outcome of ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors.
|
|
|
|
|
•
|
The
Ability of the Utility to Control Operating Costs and Capital Expenditures.
Whether the Utility is able to earn its authorized rate of return
could be materially affected if the Utility’s actual costs differ from the amounts
that have been
authorized in the final 2014 GRC decision and
that may be authorized in the 2015 GT&S rate case and
future rate case decisions.
In addition to
incurring shareholder-funded costs and costs associated with remedial measures required by the
Penalty Decision, t
he Utility forecasts that in 2015 it will incur unrecovered pipeline-related expenses ranging from
$100 million to $150 million, which primarily relate to
costs
to identify and remove encroachments from transmission pipeline rights-of-way
. Actual costs could be higher.
T
he ultimate amount of unrecovered costs
also could be affected by
how the CPUC determines which costs are included in determining whether the $850 million shareholder-funded obligation under the Penalty Decision has been met, and the outcome of
pending and future investigations and enforcement matters.
(See “Enforcement and Litigation Matters” below.)
The Utility’s ability to recover costs in the future also could be affected by
decreases in customer demand driven by
legislative and regulatory initiatives relating to distributed generation resources
, renewable energy requirements,
and changes in th
e
electric rate structure.
|
|
|
|
|
•
|
The Amount and Timing of the Utility’s Financing Needs
. PG&E
Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure.
F
or the six months ended June 30, 2015, PG
&E Corporation issued $
252
million of common stock and made equity contributions to the Utility of $
185
million.
PG&E Corporation forecasts that it will continue issuing a material amount of equity to support the Utility’s capital expenditures and to fund unrecovered pipeline-related costs
(including costs incurred under the Penalty Decision) and to pay the fine imposed by the Penalty Decision and additional
fines
and penalties
that
may be required by the final outcomes of ongoing enforcement matters.
These equity
issuances
would
have a
further
m
aterial dilutive effect on PG&E Corporation’s EPS. PG&E Corporation’s and the Utility’s ability to access the capital markets and the terms and rates of future financings could be affected by the outcome of the matters discussed in “Enforcement and Litigation Matters” below, changes in their respective credit ratings, general economic and market conditions, and other factors.
|
For more information about the
factors and
risks that could affect future
results of operations,
financial condition, and cash
flows, or that could cause future results to differ from historical results,
see
“Item 1A. Risk Factors”
in the 2014 Form 10-K and in Part II below under “Item 1A. Risk Factors
.
”
In addition, t
his
quarterly r
eport contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. See the
section entitled “Cautionary Language Regarding Forward-Looking Statements” below for a list of some of the factors that may cause actual results to differ materially.
PG&E Corporation and the Utility are not able to predict all the factors that may affect future results
and
do not undertake an obligation to update forward-looking statements, whether in response to new informati
on, future events, or otherwise.
RESULTS OF OPERATIONS
PG&E Corporation
The consolidated results of operations consist primarily of balances related to the Utility, which are discussed below.
The
following
table provides
a summary of net income available for common shareholders for the
three
and six months ended
June 30,
2015
and
2014
:
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
(in millions)
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
Consolidated Total
|
$
|
402
|
|
$
|
267
|
|
$
|
433
|
|
$
|
494
|
|
PG&E Corporation
|
|
-
|
|
|
21
|
|
|
30
|
|
|
23
|
|
Utility
|
$
|
402
|
|
$
|
246
|
|
$
|
403
|
|
$
|
471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PG&E Corporation’s net income primarily consists of interest expense on long-term d
ebt,
income taxes, and
other income from investments.
Results inc
lude
approximately $30 million and $20 million of realized gains and associated tax benefits related to an investment in SolarCity Corporation recognized in the first quarter of 2015 and second quarter of 2014, respectively.
Utility
The tables below show certain items from the Utility’s Condensed Consolidated Statements of Income for the three
and six
months ended
June 30,
2015
and
2014
. The tables separately identify the r
evenues
and costs
that impact
ed
earnings
from those that did
not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers
(such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs)
and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that
have been specifically authorized
(
such as the payment of pension costs
)
and the corresponding revenues the Utility is authorized to collect to recover such costs
, do not impact earnings.
Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on
rate base. Expenses that impact earnings are primarily those
that the Utility incurs to own and operate its assets.
The Utility’s operating results for the three and six months ended June 30, 2015 reflect charges associated with the impact of the Penalty Decision. (See “Utility Revenues and Costs that Impacted Earnings” below.)
|
|
Three Months Ended June 30, 2015
|
|
Three Months Ended June 30, 2014
|
|
|
Revenues/Costs:
|
|
|
|
Revenues/Costs:
|
|
|
|
(in millions)
|
That Impacted Earnings
|
That Did Not Impact Earnings
|
Total Utility
|
|
That Impacted Earnings
|
That Did Not Impact Earnings
|
Total Utility
|
|
Electric operating revenues
|
$
|
1,877
|
$
|
1,585
|
$
|
3,462
|
|
$
|
1,632
|
$
|
1,600
|
$
|
3,232
|
|
Natural gas operating revenues
|
|
526
|
|
228
|
|
754
|
|
|
454
|
|
265
|
|
719
|
|
Total operating revenues
|
|
2,403
|
|
1,813
|
|
4,216
|
|
|
2,086
|
|
1,865
|
|
3,951
|
|
Cost of electricity
|
|
-
|
|
1,277
|
|
1,277
|
|
|
-
|
|
1,349
|
|
1,349
|
|
Cost of natural gas
|
|
-
|
|
118
|
|
118
|
|
|
-
|
|
200
|
|
200
|
|
Operating and maintenance
|
|
1,065
|
|
418
|
|
1,483
|
|
|
1,005
|
|
316
|
|
1,321
|
|
Depreciation, amortization, and decommissioning
|
|
651
|
|
-
|
|
651
|
|
|
556
|
|
-
|
|
556
|
|
Total operating expenses
|
|
1,716
|
|
1,813
|
|
3,529
|
|
|
1,561
|
|
1,865
|
|
3,426
|
|
Operating income
|
|
687
|
|
-
|
|
687
|
|
|
525
|
|
-
|
|
525
|
|
Interest income
(1)
|
|
|
|
|
|
3
|
|
|
|
|
|
|
3
|
|
Interest expense
(1)
|
|
|
|
|
|
(189)
|
|
|
|
|
|
|
(185)
|
|
Other income, net
(1)
|
|
|
|
|
|
20
|
|
|
|
|
|
|
17
|
|
Income before income taxes
|
|
|
|
|
|
521
|
|
|
|
|
|
|
360
|
|
Income tax provision
(1)
|
|
|
|
|
|
115
|
|
|
|
|
|
|
110
|
|
Net income
|
|
|
|
|
|
406
|
|
|
|
|
|
|
250
|
|
Preferred stock dividend requirement
(1)
|
|
|
|
|
|
4
|
|
|
|
|
|
|
4
|
|
Income Available for Common Stock
|
|
|
|
|
$
|
402
|
|
|
|
|
|
$
|
246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These items impacted earnings for the three months ended
June 30,
2015
and
2014
.
|
|
Six Months Ended June 30, 2015
|
|
Six Months Ended June 30, 2014
|
|
|
Revenues/Costs:
|
|
|
|
Revenues/Costs:
|
|
|
|
(in millions)
|
That Impacted Earnings
|
That Did Not Impact Earnings
|
Total Utility
|
|
That Impacted Earnings
|
That Did Not Impact Earnings
|
Total Utility
|
|
Electric operating revenues
|
$
|
3,662
|
$
|
2,814
|
$
|
6,476
|
|
$
|
3,217
|
$
|
3,015
|
$
|
6,232
|
|
Natural gas operating revenues
|
|
1,031
|
|
609
|
|
1,640
|
|
|
925
|
|
684
|
|
1,609
|
|
Total operating revenues
|
|
4,693
|
|
3,423
|
|
8,116
|
|
|
4,142
|
|
3,699
|
|
7,841
|
|
Cost of electricity
|
|
-
|
|
2,277
|
|
2,277
|
|
|
-
|
|
2,559
|
|
2,559
|
|
Cost of natural gas
|
|
-
|
|
392
|
|
392
|
|
|
-
|
|
560
|
|
560
|
|
Operating and maintenance
|
|
2,652
|
|
754
|
|
3,406
|
|
|
2,038
|
|
580
|
|
2,618
|
|
Depreciation, amortization, and decommissioning
|
|
1,282
|
|
-
|
|
1,282
|
|
|
1,094
|
|
-
|
|
1,094
|
|
Total operating expenses
|
|
3,934
|
|
3,423
|
|
7,357
|
|
|
3,132
|
|
3,699
|
|
6,831
|
|
Operating income
|
|
759
|
|
-
|
|
759
|
|
|
1,010
|
|
-
|
|
1,010
|
|
Interest income
(1)
|
|
|
|
|
|
4
|
|
|
|
|
|
|
5
|
|
Interest expense
(1)
|
|
|
|
|
|
(376)
|
|
|
|
|
|
|
(364)
|
|
Other income, net
(1)
|
|
|
|
|
|
46
|
|
|
|
|
|
|
37
|
|
Income before income taxes
|
|
|
|
|
|
433
|
|
|
|
|
|
|
688
|
|
Income tax (benefit) provision
(1)
|
|
|
|
|
|
23
|
|
|
|
|
|
|
210
|
|
Net income
|
|
|
|
|
|
410
|
|
|
|
|
|
|
478
|
|
Preferred stock dividend requirement
(1)
|
|
|
|
|
|
7
|
|
|
|
|
|
|
7
|
|
Income Available for Common Stock
|
|
|
|
|
$
|
403
|
|
|
|
|
|
$
|
471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These items impacted earnings for the
six
months ended June 30,
2015
and
2014
.
Utility Revenues and Costs that Impacted Earnings
The following discussion presents the Utility’s operating results for the
three
and six
months ended
June 30,
2015
and
2014
, focusing on revenues and expenses that impact
ed
earnings for these periods.
Operating Revenues
The Utility’s electric and natural gas operating revenues that impacted earnings
increased by
$
317
million
,
or
15%
,
and by $551 million, or 13%,
in the
three and six
months ended
June 30,
2015
, respectively,
compared to the same period
s
in
2014
.
The increases
reflect
approximately $320
million and $58
5
million of higher base revenues
in the
three and six
months ended
June 30,
2015
,
respectively,
as authorized by the CPUC in the 2014 GRC decision and for nuclear decommissioning costs and the FERC in the TO rate case.
The increases to base revenues include approximately $115 million and $230 million for the three and six months ended June 30, 2015, respectively, related to 2014 increases that were not recognized until the quarter ended September 30, 2014, as a result of the timing of the GRC decision
. The increases in operating revenues were partially offset by the absence of $35 million and $68 million in the three and six months ended June 30, 2015, respectively, of revenues the CPUC authorized the U
tility to collect for recovery of certain PSEP-related costs
during the same periods in 2014.
Recovery of PSEP-related costs incurred during 2015 will depend upon the timing and outcome of the GT&S rate case. The Utility has requested the CPUC authorize an increase to its revenue requirements for 2015, 2016, and 2017 in its GT&S rate case.
Based on the procedural schedule, it is unlikely that the Utility will be able to recognize any increase in its GT&S revenue in 2015
. (See “Ratemaking Proceedings” below.)
Operating and Maintenance
The
Utility’s operating and maintenance expenses
that impacted earnings increased by $
60
million, or
6%
, and
by $614 million, or 30%, in the three and six months ended
June 30,
2015
compared to the same periods in
2014
. The increases for both periods are primarily due to $75 million and $628 million in charges associated with the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements).
The
increases were partially offset by $39 million in insurance recoveries related to third-party claims and associated legal costs related to natural gas matters recognized in the three and six months ended June 30, 2015 with no similar activity in 2014. The Utility has recovered a cumulative total of $505 million through insurance of the $558 million of cumulative charges for
these
claims.
The Utility’s future financial statements will continue to be
impacted by additional charges associated with the Penalty Decision and unrecoverable pipeline-related expenses. (See “Key Factors Affecting Financial Results” above and Note 9 of the Notes to the Condensed Consolidated Financial Statements.)
Depreciation, Amortization, an
d Decommissioning
The Utility’s depreciation, amortization, and decommissioning expenses
increased $
95
million
,
or
17%, and by $188 million, or 17%, respectively,
in
the
three and six
months ended
June 30,
2015
compared to the same period
s
in
2014
,
primarily due to
an increase in depreciation rates as authorized by the CPUC in the 2014 GRC decision and an increase in capital additions.
Interest Income
,
Interest Expense
, and Other Income, Net
There were no material changes to interest income, interest expense, and other income, net for the periods presented.
Income Tax Provision
The Utility’s revenue requirements for the 2014 GRC decision period reflects flow-through ratemaking for income tax expense benefits attributable to the accelerated recognition of repair costs and certain other property-related costs for federal tax purposes.
The Utility began to recognize the impact of these income tax expense benefits in the third quarter of 2014
when it received a final GRC decision
.
The Utility’s financial results reflect a reduction in income tax expense associated with these temporary differences, resulting in a lower effective tax rate.
(See Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K.)
The income tax provision increased by $5 million, or 5%, and
decreased by $187 million, or
89%, in the three and six months ended June 30, 2015
as compared to the same periods in 2014
.
The decrease in the income tax provision in the six months
ended June 30, 2015 is primarily due to lower pre-tax income resulting from the impact of the Penalty Decision
(see Note 9 of the Notes to the Condensed Consolidated Financial Statements).
The following describes the change in the Utility’s effective tax rate for the three and six months ended June 30, 2015 as compared to the same periods in 2014:
|
|
|
|
•
|
The effective tax rates for the three months ended June 30, 2015 and 2014 were 22% and 31%, respectively.
The decrease in the effective tax rate was primarily due to the effect of the flow-through treatment of property-related costs for federal tax purposes that the Utility began to record in the quarter ended September 30, 2014.
|
|
|
|
|
•
|
The effective tax rates for the six months ended June 30, 2015 and 2014 were 5% and 31%, respectively.
The decrease in the effective tax rate was primarily due to the effect of the flow-through treatment of property-related costs for federal tax purposes that the Utility began to record in the quarter ended September 30, 2014 and the impact of the Penalty Decision recorded in 2015 with no comparable amount recorded for the same period in 2014. Under applicable accounting standards, charges resulting from the Penalty Decision are recorded at the statutory rate in the period incurred.
|
In
June 2015, State Bill 681 was introduced and proposes that the Utility be denied applicable state tax deductions for charges associated with the Penalty Decision.
The tax treatment of the costs and resulting financial impact will be affected by the final outcome of this legislation (see “Item 1A. Risk Factors” in Part II below).
Utility Revenues and Costs that did not Impact Earnings
Cost of Electricity
The
Utility’s cost of electricity includes the costs of power purchased from third parties (including renewable energy resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
(in millions)
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
Cost of purchased power
|
$
|
1,207
|
|
$
|
1,287
|
|
$
|
2,129
|
|
$
|
2,399
|
|
Fuel used in own generation facilities
|
|
70
|
|
|
62
|
|
|
148
|
|
|
160
|
|
Total cost of electricity
|
$
|
1,277
|
|
$
|
1,349
|
|
$
|
2,277
|
|
$
|
2,559
|
|
Average cost of purchased power per kWh
(1)
|
$
|
0.103
|
|
$
|
0.097
|
|
$
|
0.101
|
|
$
|
0.093
|
|
Total purchased power (in millions of kWh)
(2)
|
|
11,747
|
|
|
13,320
|
|
|
21,038
|
|
|
25,788
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Average cost of purchased power for the three and six months ended June 30, 2015 increased compared to the same periods in 2014 primarily due to
a
higher volume of renewables. This increase was partially offset by lower market prices for natural gas.
(2)
T
he decrease in purchased power resulted from an increase at the Utility’s own generation facilities. This increased generation reflects increases in gas-fired generation in both the three and six months ended June 30, 2015 and nuclear generation at Diablo Canyon during the six months ended June 30, 2015 as compared to the same periods in 2014.
The Utility’s total purchased power is driven by customer demand, the availability of the Utility’s own generation facilities including Diablo Canyon and its hydroelectric plants, and the cost effectiveness of each source of electricity
.
Cost of
Natural
Gas
The Utility’s cost of natural gas includes the costs of procurement, storage, transportation of natural gas
,
costs to comply with California’s cap-and-trade program,
and realized gains and losses on price risk man
agement activities. (See Note 7
of the Notes to the
Condensed
Consolidated Financial Statements
.
) The Utility’s cost of natural gas
is impacted
by the market price of natural gas, changes in the cost of storage and transportation,
and
changes in customer demand.
The Utility expects the cost of natural gas for 2015 will continue to be lower due to lower market prices.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
(in millions)
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
Cost of natural gas sold
|
$
|
83
|
|
$
|
165
|
|
$
|
317
|
|
$
|
489
|
|
Transportation cost of natural gas sold
|
|
35
|
|
|
35
|
|
|
75
|
|
|
71
|
|
Total cost of natural gas
|
$
|
118
|
|
$
|
200
|
|
$
|
392
|
|
$
|
560
|
|
Average cost per Mcf
(1)
of natural gas sold
|
$
|
2.18
|
|
$
|
4.34
|
|
$
|
2.88
|
|
$
|
4.22
|
|
Total natural gas sold (in millions of Mcf)
|
|
38
|
|
|
38
|
|
|
110
|
|
|
116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
One thousand cubic feet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
and Maintenance
Expense
s
The Utility’s operating expenses also include certain recoverable costs that the Utility incurs as part of its operations such as pension contributions and public purpose programs costs.
If the Utility were to spend over authorized amounts, these expenses could have an impact to earnings.
LIQUIDITY AND FINANCIAL RESOURCES
Overview
The Utility’s ability to fund operations, finance capital expenditures, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets.
The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its debt financing costs.
The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure consisting of 52% equity and 48% debt and preferred stock.
The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs.
PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends, primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital and credit markets.
PG&E Corporation has material stand-alone cash flows related to the issuance of equity and long-term debt, dividend payments, and borrowings and repayments under its revolving credit facility. P
G&E Corporation relies on short-
term debt, including commercial paper, to fund temporary financing needs.
PG&E Corporation forecasts that it will issue betwee
n $
700
million and $
800
million i
n common stock during 2015 primarily to fund equity contributions to the Utility.
The Utility’s equity needs will continue
to be affected by
unrecovered
pipeline-related costs (including
costs incurred to comply with the Penalty Decision) and to pay fines imposed by the Penalty Decision and additional
fines
and penalties that may be
imposed in connection with the
matters described in “Enforcement and Litigation Matters” below.
Common stock issuances by PG&E Corporation to fund these needs would
have a material dilutive impact on PG&E Corporation’s EPS
.
Cash and Cash Equivalents
Cash and cash equivalents consist of cash and short-term, highly liquid investm
ents with original maturities of
three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code. (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 9 of the Notes to the
Condensed
Consolidated Financial Statements). The Utility is uncertain when and how the remaining disputed claims will be resolved.
Financial Resources
Debt and Equity
Financings
In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $
500
million. In
the first quarter of 2015
, PG&E Corporation sold
1.4
million shares under this agreement for cash proceeds of $
74
million, net of commissions paid of $
1
million.
No shares were sold during the
three
months ended
June 30, 2015
.
In addition, PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the
six months
ended
June 30, 2015,
4.3
million shares were issued for cash proceeds of $
178
million under these plans
.
The proceeds from these sales were used for general corporate purposes, including the contribution of equity to the Utility. For the six months ended June 30, 2015, PG&E Corporation made equity contributions to the Utility of $185 million.
Additionally,
PG&E Corporation and the Utility expect to continue to issue long-term and short-term debt for general corporate purposes and to maintain the CPUC-authorized capital structure during 2015.
In June 2015, the Utility issued $400 million principal amount of 3.50% Senior Notes due June 15, 2025 and $100 million of 4.30% Senior Notes due March 15, 2045. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.
Revolving Credit Facilities and Commercial Paper Program
On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities that were entered into on April 1, 2013. At June 30, 2015, PG&E Corporation and the Utility had $295 million and $2.0
billion available under their respective $300 million and $3.0 billion revolving credit facilities. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements and “Item 5. Other Information”)
T
he 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 own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility.
In addition, these revolving credit facilities
include usual and customary
provisions
regarding events of default and covenants
limiting liens, mergers, sales of all or substantially all of
PG&E Corporation’s
and the Utility’s assets, and other fundamental changes.
At
June 30
,
2015
, PG&E Corporation and the Utility were in compl
iance with all covenants under their respective
revolving credit facilities.
Dividends
In June 2015
, the Board of
Directors of PG&E Corporation
declared
quarterly
dividends of
$
0.4
55 per share, totaling
$
219
million
, of which approximately $214
million was paid on
July
15
, 201
5
to shareholders of record on
June 30
, 201
5
.
In June 2015, the Board of Directors of the Utility declared a common stock dividend of $179 million that was paid to PG&E Corporation on June 17, 2015.
In June
2015
, the Board of
Directors of
the Utility declared dividends
on its outstanding series of pref
erred stock, payable on August 15, 2015
, to shareholders of record on
July 31, 2015
.
Utility Cash Flows
The Utility’s cash flows were as follows:
|
|
Six Months Ended June 30,
|
|
(in millions)
|
2015
|
|
2014
|
|
Net cash provided by operating activities
|
$
|
1,860
|
|
$
|
1,261
|
|
Net cash used in investing activities
|
|
(2,486)
|
|
|
(2,297)
|
|
Net cash provided by financing activities
|
|
719
|
|
|
1,041
|
|
Net change in cash and cash equivalents
|
$
|
93
|
|
$
|
5
|
|
|
|
|
|
|
|
Operating Activities
The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.
During the six months ended June 30, 2015,
net cash provided by
operating activities
increased by
$
599
million
compared to
the same period in 2014. This increase was primarily due to higher base revenue collections authorized in the 2014 GRC and lower purchased power costs (see “Cost of Electricity” under “Results of Operations – Utility Revenues and Costs that did not Impact Earnings” above).
Future cash flow from operating activities will be affected by various factors, including:
|
•
|
the shareholder-funded bill credit of $400 million to natural gas customers in 2016, and the payment of a $300 million fine to the State General Fund during 2015, as required by the Penalty Decision (see “Enforcement and Litigation Matters” below)
;
|
|
|
|
|
•
|
the timing and amounts of other fines or penalties that may be imposed in connection with the
criminal prosecution
of the Utility and the remaining
investigations
and other enforcement matters
(see “Enforcement and Litigation Matters” below);
|
|
|
|
|
•
|
the timing and outcome of ratemaking proceedings, in
cluding the 2015 GT&S rate case;
|
|
|
|
|
•
|
the timing and amount of costs the Utility incurs, but does not recover, associated with its natural gas system
(including costs to implement remedial measures and $850 million to pay for designated pipeline safety projects and programs, as required by the Penalty Decision)
;
|
|
|
|
|
•
|
the timing and amount of tax payments, tax refunds, net collateral payments, and interest payments; and
|
|
|
|
|
•
|
the timing of the resolution of the Chapter 11 disputed claims and the amount of
principal and
interest on these claims that the Utility will be required to pa
y
.
|
Investing Activities
Net cash used in investing activities
increased
by $
189
million
during the six months ended June 30, 2015 as
compared to
the same period in 2014.
The Utility’s investing activities primarily consist of construction of new and replacement facilities necessary to
provide
safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear
generation
facilities.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.
The Utility estimates that it will incur approximately $5.5 billion in capital expenditures in 2015 and between
$5.3 billion and $5.8
billion in 2016.
Financing Activities
During the six months ended June 30, 2015
,
net cash provided by financing activitie
s
decreased
by
$
322 million c
ompared to the same period in
2014
. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by
or used in operating activities,
the level of cash provided by or used in investing activities
, the conditions in the capital markets, and the maturity date of existing debt instruments
. The Utility generally utilizes long-term debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.
ENFORCEMENT AND LITIGATION MATTERS
PG&E Corporation and the Utility have
significant
contingencies arising from their operations, including contingencies related to
the
enforcement and litigation matters
described in
Note 9 in the Condensed Consolidated Financial Statements. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s future financial results.
Potential CPUC Investigation of the Utility’s Safety Culture
In connection with the issuance of the Penalty Decision
, the President of the CPUC questioned whether the Utility has developed a safety culture that is effective throughout the organization and whether the CPUC’s theories of deterrence – its system of penalties and remedies – assure an effective safety culture in a utility. He directed the CPUC to begin a new investigation to examine the Utility’s safety culture and practices, including whether they are effective and comprehensive across the organization, and whether there is sufficient accountability for safety results. He also questioned whether the Utility “is too big to succeed” from a safety perspective, although he did not order the CPUC to begin a new investigation into this issue. He stated that he intended to request the CPUC’s Legal Division to analyze and evaluate the CPUC’s policies regarding penalties and remedies, and make recommendations for adoption by the CPUC.
The timing, scope, and potential outcome of the new investigation and analysis are uncertain.
Other Pending Lawsuits and Claims
As previously reported, PG&E Corporation received a letter, dated March 26, 2015, on behalf of a purported shareholder demanding that the PG&E Corporation Board of Directors (1) take all necessary actions to recover from certain officers and directors the amount of damages sustained by PG&E Corporation as a result of their alleged misconduct in connection with the events surrounding the San Bruno accident and other matters, and (2) institute corporate governance changes and improvements. In May 2015, the Board created an Evaluation Committee to evaluate the matters set forth in the demand letter and to recommend to the Board an appropriate response to these matters.
On June 5, 2015, the purported shareholder who submitted the demand letter filed a derivative lawsuit in San Mateo County Superior Court, alleging that his shareholder demand was wrongfully refused. As of June 30, 2015, there were six purported derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.
PG&E Corporation and the Utility are uncertain when and how the above lawsuits and the shareholder demand will be resolved.
RATEMAKING PROCEEDINGS
The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies.
Significant regulatory developments that have occurred since the 201
4
Form 10-K
was filed with the SEC are discussed below.
2015 Gas Transmission and Storage Rate Case
In the 2015 GT&S rate case, t
he Utility requested that the CPUC authorize a 2015 revenue requirement of $1.2
9
billion to recover anticipated costs of providing natural gas transmission and storage services, an increase of $5
55
million over currently authorized amounts.
The Utility also requested attrition increases of $
61
million in 2016 and $
168
million in 2017.
The Utility requested that the CPUC authorize the Utility’s forecast of its 2015 weighted average rate base for its gas transmission and storage business of $3.56 billion, which includes capital s
pending
above authorized levels for the prior rate case period.
The O
ffice of Ratepayer Advocates
has recommended a 2015 revenue requirement of $
1.044 billion
, an increase of $329 million over authorized amounts.
TURN recommended that the Utility not recover costs associated with hydrostatic testing for pipeline segments placed in service between January 1, 1956 and June 30, 1961, as well as certain other work that TURN considers to be remedial.
TURN also recommended the disallowance of about $200 million of capital expenditures incurred over the period 2011 through 2014 and recommended that about $500 million of capital expenditures during this period be subject to a reasonableness review and an independent audit.
TURN states that the Utility’s cost recovery should not begin until the CPUC issues a decision on the independent audit.
The Utility also has proposed changes to the revenue sharing mechanism authorized in the last GT&S rate case (covering 2011-2014) that subjected a portion of the Utility’s transportation and storage revenue requirement to market risk.
The Utility proposed full balancing account treatment that allows for recovery of the Utility’s authorized transportation and storage revenue requirements
(
except for the revenue requirement associated with the Utility’s 25% interest in the Gill Ranch storage field
)
.
Based on the scoping ruling and procedural schedule that was issued on June 11, 2015, the CPUC
is expected to issue
a
two-part decision, the first decision to authorize GT&S revenue requirements (which would
include
a
potential
disallowance to be imposed as a penalty for the Utility’s violation of the CPUC’s ex parte communication rules
as well as a reduction in the Utility's request to reflect any costs associated with implementing the remedies ordered by the Penalty Decision
), and a second decision to reduce the authorized revenue requirements by the costs of designated safety-related projects and programs up to the $850 million maximum cost disallowance imposed by the Penalty Decision
.
(See Note 9 in the Condensed Consolidated Financial Statements for more information about the CPUC’s Penalty Decision.)
Under
the procedural schedule,
the CPUC’s
decision to authorize revenue requirements
likely will not be
issued
until 2016
and
the CPUC’s
decision to determine the revenue requirement reduction
will follow. (The ruling states
that,
in any event,
the case would be completed
within 18 months of the date of the ruling, or by December 2016.
)
Based on the procedural schedule, it is unlikely that the Utility will be able to recognize
any increase in its GT&S revenue in 2015.
FERC
T
O
Rate Cases
On July 30, 2014, the Utility requested 2015 retail electric transmission revenue requirement of $1.366 billion, a $326 million increase over the currently authorized revenue requirement of $1.040 billion.
The
Utility’s
proposed rates went into effect on March 1, 2015, subject to refund, and pending a
final decision by the FERC.
On July 2, 2015, the Utility and other settling parties (including the CPUC) filed a motion at the FERC requesting that the FERC approve a settlement proposing that the Utility’s 2015 retail electric transmission revenue requirement be set at $1.201 billion, a $161 million increase to the currently authorized revenue requirement of $1.040 billion. The settlement is subject to the FERC’s approval. If approved by the FERC, the outcome is not expected to have a material effect. The FERC is expected to issue a decision in late 2015 or early 2016.
On July 29, 2015, the Utility filed a rate case at FERC that requests a 2016 retail electric transmission revenue requirement of $1.515 billion, a $314 million increase over the settled revenue requirement of $1.201 billion pending FERC approval. The Utility forecasts that it will make investments of $1.246 billion in 2016 in various capital projects. The Utility's forecasted rate base for 2016 is $5.85 billion, compared to forecasted rate base of $5.12 billion in 2015. The Utility has requested that the FERC approve a 10.96% return on equity. The Utility's rate case is pending acceptance at the FERC.
The California Legislature and the CPUC require the California investor-owned electric utilities to accommodate the growth in distributed electric generation resources (including solar installations), increase the amount of renewable energy delivered to customers, and meet cost-effective energy storage targets. These mandates, along with other state laws and regulations relating to the reduction of GHG emissions
,
the establishment of energy efficiency standards for buildings,
and the creation of community choice aggregators that provide electric service to their communities,
have affected, and are likely to continue to affect, customer demand for the Utility’s electric and natural gas service. Future changes in state laws to increase the amount of renewable energy targets, to establish higher building energy efficiency standards, or to increase the maximum number of “direct access” customers who can procure electricity from alternate energy providers, could
further
decrease customer demand. Customer demand also can be affected as the CPUC continues to implement state law requirements to reform electric rates to more closely reflect the utilities’ actual costs of service, reduce cross-subsidization among customer rate classes,
implement new net energy metering rules,
and allow customers to have greater control over their energy use.
The Utility’s ability to recover its investments, including investments associated with new requirements and initiatives, as well as its electricity procurement and other operating costs, will, in large part, depend on the final form of legislative or regulatory requirements and whether the associated ratemaking mechanisms can be timely adjusted to reflect changes in customer demand for the Utility’s electricity and natural gas service.
Electric Distribution Resources Plan
As required by California law, on July 1, 2015, the Utility filed its proposed electric distribution resources plan to identify optimal locations on its electric distribution system for deployment of distributed generation resources. The Utility’s proposal allows energy technologies to be interconnected with each other and integrated into the larger grid while continuing to provide customers with safe, reliable and affordable electric service.
The Utility envisions a future electric grid, titled the Grid of Things™, that would allow customers to choose new advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service.
Some of the Utility’s initiatives include smart grid infrastructure modernization and new community solar programs. The Utility plans to request authorization in its 2017 GRC and future applications, to recover the investment costs that it forecasts it will incur under its proposed electric distribution resources plan.
Electric Rate Reform and Net Energy Meeting
New state legislation that became effective on January 1, 2014 (AB 327) grants the CPUC authority to approve fixed charges to be collected from retail electric residential customers and to revise residential electric rate designs to more closely reflect the cost of service.
In February 2014, as ordered by the CPUC, the Utility submitted a long-term residential electric rate reform plan that proposes a fixed customer charge, gradual flattening of the tiered rate structure, and an optional time-of-use rate.
On July 3, 2015, the CPUC approved a final decision providing for the gradual flattening of the tiered rate structure from four tiers to two tiers with a 1.25 to 1 rate price ratio by January 1, 2019, to bring residential electric rates closer to
the Utility’s cost of service.
The decision creates a Super User Electric Surcharge to apply to extremely high electricity users beginning in 2017.
The Utility is required to file a proposal no later than January 1, 2018, to charge residen
tial customers based on time-of-
use rates unless customers elect otherwise. The Utility also may propose to impose a fixed charge on customers.
Under the CPUC’s decision, time-of-use rates must be implemented before the CPUC will permit the imposition of a fixed charge.
The CPUC also approved increased minimum bill charges for residential customers.
AB 327 also requires the CPUC to develop a new tariff or contract for net energy metering by December 31, 2015, that must be implemented no later than July 1, 2017.
California’s net energy metering tariff currently allows customers installing renewable distributed generation to offset their electric consumption and receive bill credits for power delivered to the grid at their full retail rate.
Increasing levels of installed renewable distributed generation by customers, coupled with net energy metering that provides full retail rate credits that do not reflect the Utility’s cost structure, have shifted costs from distributed generation customers to other customers.
AB 327 requires the CPUC to assess opportunities to reduce this cost-shift through residential rate and net energy metering tariff reform.
In July 2014, the CPUC began a new rulemaking proceeding to develop a successor to the existing net energy metering tariff to comply with the requirements of AB 327.
The Utility is scheduled to file its successor tariff proposal on August 3, 2015.
The CPUC is expected to issue a decision by December 2015.
On February 9, 2015, the Utility filed an application requesting the CPUC to approve the Utility’s proposal to deploy, own, and maintain EV charging infrastructure in its service territory to accelerate EV infrastructure deployment and customer education programs in support of California’s climate goals.
Future use of this charging infrastructure could aid the integration of increased intermittent renewable energy on the state’s electric power grid.
Under the Utility’s proposal, the Utility would develop more than 25,000 EV charging stations and the associated infrastructure over an estimated five years.
The Utility estimates this would meet approximately 25% of projected EV charging station needs by 2020.
The Utility plans to contract with third party EV service providers to operate and maintain the charging stations.
The Utility estimates that it would incur capital costs of $551 million and operating costs of $103 million over the proposed project timeline.
The Utility has requested that the CPUC authorize the Utility to collect an average annual revenue requirement over the project development years of $81 million to recover these costs.
The Utility has requested that the CPUC issue a decision before the end of 2015. Under the proposal, the Utility would begin implementation in 2016, with first deployments of charging stations in 2017.
ENVIRONMENTAL MATTERS
The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes
, such as
groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations
; the reporting and reduction of carbon dioxide and other
greenhouse gas
emissions; the discharge of pollutants into the air, water, and soil; and the transportation, handling, storage, and disposal of spent nuclear fuel.
(See
Note
9
of the Notes to the Condensed Consolidated Financial Statements
, as well as
“Item 1A. Risk Factors” and Note 14 in the 2014 Form 10-K.)
CONTRACTUAL COMMITMENTS
PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (See “Commitments” in Note 9 of the Notes to the Condensed Consolidated Financial Statements). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and Management’s Discussion and Analysis
of Financial Condition and Results of Operations
– Contractual Commitments in the 2014 Form 10-K.
Off-Balance Sheet Arrangements
PG&E Corporation and the Utility do not have any
off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources
, other than those discussed in Note 14 of the Notes to the Consolidated Financial Statements in the 2014 Form 10-K (the Utility’s commodity purchase agreements)
.
RISK MANAGEMENT ACTIVITIES
PG&E Corporation
, mainly through its ownership of the
Utility,
and the Utility
are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for elect
ricity, natural gas, electric
transmission, natural gas transportation,
and
storage;
emissions allowances and offset credits,
other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “pric
e risk” and “interest rate risk.
” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.
The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (
i.e
., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of energy and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases.
These
activities are
discussed in detail in the
2014
Form 10-K. There were no significant developments to the
Utility and PG&E Corporation
’s risk management activities during the
six
months ended
June 30
,
2015
.
The preparation of the Condensed Consolidated Financial Sta
tements in accordance with
GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, asset retirement obligations, and pension and other postretirement benefits plans to be critical accounting policies.
These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of ma
terial judgments and estimates.
Actual results may differ materially
from these estimates.
These accounting policies and their key characteristics are discussed in detail in the
2014
Form 10-K
.
ACCOUNTING
STANDARDS
ISSUED BUT NOT YET ADOPTED
See the discussion above in Note 2 of
the Notes to the Condensed Consolidated Financial Statements.
CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters,
estimated losses, including penalties and fines, associated with various investigations
and proceedings
;
forecasts of
pipeline-related expenses
that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results.
Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:
|
•
|
The outcome and timing of the 2015 GT&S rate case, including the amount of revenue disallowance imposed as a penalty for improper ex parte communications and how the authorized revenue requirements are reduced to reflect the disallowance of costs associated with designated safety-related projects and programs as required by the Penalty Decision;
|
|
|
|
|
•
|
the outcomes of the federal criminal prosecution of the Utility, the CPUC’s investigation of the Utility’s natural gas distribution operations, the SED’s unresolved enforcement action matters, and the other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas-related laws and regulations, and the amount of fines, penalties, and remedial costs that the Utility may incur in connection with such matters;
|
|
|
|
|
•
|
the t
iming and outcome of the CPUC’s
investigation and the p
ending criminal investigations
relating to communications between the Utility and the CPUC that may have violated the CPUC’s rules regarding ex parte communications or are
otherwise
alleged to be improper, and whether such
matters
negatively affect the final decisions to be issued in the 2015 GT&S rate case or other ratemaking proceedings;
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whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by the criminal prosecution of the Utility, the state and federal investigations of natural gas incidents, improper communications between the CPUC and the Utility; and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way;
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the restrictions on communications between the Utility and the CPUC that have been imposed by the CPUC that, along with continuing public criticism of the Utility and the CPUC, may make it more difficult for the Utility to sustain or repair a constructive working relationship with the CPUC and achieve balanced regulatory outcomes;
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the timing and outcome of ratemaking proceedings (such as the 2015 GT&S rate case, the 2017 GRC and the TO rate case
s
) and the Utility’s ability to control its costs within the adopted levels of spending;
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the amount and timing of additional common stock and debt issuances by PG&E Corporation, the proceeds of which are contributed as equity to maintain the Utility’s authorized capital structure as the Utility incurs charges and costs that it cannot recover through r
ates (including
shareholder-funded costs to complete designated safety projects and programs as ordered in the Penalty Decision) and fines;
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the outcome of the anticipated CPUC investigation into the Utility’s safety culture, and future legislative or regulatory actions that may be taken to require the Utility to restructure into separate entities, undertake some other corporate restructuring, or implement corporate governance changes;
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the outcomes of future investigations or other enforcement proceedings that may be commenced relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including the construction, expansion or replacement of its electric and gas facilities; inspection and maintenance practices, customer billing and privacy, and physical and cyber security; and whether the current or potentially worsening state regulatory environment increases the likelihood of unfavorable outcomes;
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the impact of environmental laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; the extent to which the Utility is able to recover environmental costs in rates or from other sources; and the ultimate amount of environmental costs the Utility incurs but does not recover, such as the remediation costs associated with the Utility’s natural gas compressor station site located near Hinkley, California;
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the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; and whether the Utility decides to resume its pursuit to renew the two Diablo Canyon operating licenses, and if so, whether the licenses are renewed;
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the impact of droughts or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, or vandalism (including cyber-attacks), and other events, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies; and subject the Utility to third-party liability for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory penalties on the Utility;
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the impact of environmental laws and regulations aimed at the reduction of
greenhouse gases
, and whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations and the cost of renewable energy procurement;
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the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and recover its investments through rates and earn its authorized
return on equity
, and whether the Utility’s business strategy to address the impact of growing distributed and renewable generation resources and changing customer demands is successful;
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the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates;
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whether the Utility’s information technology, operating systems and networks, including the advanced metering system infrastructure, customer billing, financial, and other systems, can continue to function accurately while meeting regulatory requirements; whether the Utility is able to protect its operating systems and networks from damage, disruption, or failure caused by cyber-attacks, computer viruses, or other hazards; whether the Utility’s security measures are sufficient to protect against unauthorized or inadvertent disclosure of information contained in such systems and networks; and whether the Utility can continue to rely on third-party vendors and contractors that maintain and support some of the Utility’s operating systems;
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the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties;
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the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;
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changes in credit ratings which could result in increased borrowing costs especially if PG&E Corporation or the Utility were to lose its investment grade credit ratings;
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the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the ultimate outcomes of the CPUC’s pending investigations, the criminal prosecution, and other enforcement matters affect the Utility’s ability to make distributions to PG&E Corporation, and, in turn, PG&E Corporation’s ability to pay dividends;
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the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, regulations, or their interpretation
,
including whether state law is enacted to prohibit
the Utility from claiming tax deductions for costs associated with
designated safety-related projects and programs that are disallowed by the Penalty Decision; and
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the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.
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For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see “Risk Factors” in the
2014 Form 10-K and in Part II, Item. 1A. Risk Factors below
. PG&E Corporation and the Utility do not undertake an
y
obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.
