PG&E Corp annual report, FY2016

PG&E Corporation 2016 Form 10-K Summary

Business context and reporting period

PG&E Corporation is a California holding company whose principal subsidiary, Pacific Gas and Electric Company, provides regulated electric and natural gas generation, transmission, distribution, and storage services in northern and central California. The filing covers the fiscal year ended December 31, 2016, with comparative information for 2015 and 2014. The filing is a combined report for PG&E Corporation and the Utility; amounts below are primarily for PG&E Corporation unless noted.

Financial performance and liquidity

Metric	2016	2015	Change
Operating revenues	$17.666 billion	$16.833 billion	Up 5.0%
Operating income	$2.177 billion	$1.508 billion	Up 44.4%
Net income	$1.407 billion	$888 million	Up 58.4%
Income available to common shareholders	$1.393 billion	$874 million	Up 59.4%
Diluted EPS	$2.78	$1.79	Up $0.99
Operating margin	12.3%	9.0%	Expanded
Net margin	8.0%	5.3%	Expanded

• Natural gas revenue increased to $3.802 billion from $3.176 billion, while electric revenue increased to $13.864 billion from $13.657 billion. Earnings-related revenue increased 13%, primarily from the 2015 gas transmission and storage rate case and higher authorized base revenues.
• Operating and maintenance expense increased to $7.354 billion from $6.951 billion, reflecting Butte fire costs, capital disallowances, pipeline-related costs, and legal and regulatory expenses. These increases were partly offset by the absence of certain 2015 San Bruno penalty charges.
• Net cash provided by operating activities was $4.409 billion, compared with $3.780 billion in 2015. Capital expenditures were $5.709 billion, resulting in $5.526 billion of net cash used in investing activities.
• Cash and cash equivalents were $177 million at year-end, compared with $123 million in 2015. Restricted cash declined to $7 million after the release of approximately $161 million from bankruptcy-related escrow.
• Consolidated long-term debt, excluding the current portion, was $16.220 billion, compared with $15.925 billion. Short-term borrowings were $1.516 billion, including approximately $1.016 billion of Utility commercial paper.
• PG&E Corporation and the Utility had revolving credit availability of approximately $300 million and $1.9 billion, respectively. Debt-to-capitalization ratios were 51% for PG&E Corporation and 50% for the Utility, below the 65% covenant limit.
• PG&E Corporation contributed $835 million of equity to the Utility in 2016 and issued $842 million of common stock. Management forecast $400 million to $600 million of additional equity issuance in 2017, primarily to fund Utility capital needs.
• The annual PG&E Corporation common dividend increased to $1.925 per share from $1.82. The boards adopted a target payout ratio of 55% to 65%, with a goal of approximately 60% by 2019, subject to future board decisions and liquidity requirements.

Material changes versus the prior comparable period

• Reported earnings improved substantially, but the comparison was affected by significant unusual items in both years. Management reported 2016 earnings from operations of $1.884 billion, or $3.76 diluted EPS, versus $1.519 billion, or $3.12 diluted EPS, in 2015.
• 2016 included $232 million after-tax of Butte fire-related costs, net of insurance; $498 million of pre-tax fines and penalties; $113 million of pipeline-related expenses; $72 million of legal and regulatory expenses; and a $219 million pre-tax gas transmission and storage capital disallowance.
• The Utility recorded a $750 million Butte fire third-party claims accrual and a $625 million probable insurance recovery. The recorded Butte fire liability was $690 million at year-end after payments, while the insurance receivable was $575 million.
• The Utility recorded $219 million of charges for capital expenditures probable of disallowance in the 2015 gas transmission and storage rate case and $283 million of 2016 charges related to the earlier San Bruno penalty decision.
• Net property, plant, and equipment increased to $50.581 billion from $46.723 billion. The asset retirement obligation increased to $4.684 billion from $3.643 billion, substantially reflecting revised nuclear decommissioning estimates.
• The estimated undiscounted cost to decommission the Utility's nuclear facilities increased by approximately $1.4 billion. The recorded nuclear decommissioning obligation was $3.5 billion at December 31, 2016, and nuclear decommissioning trust assets had a fair value of approximately $2.9 billion.

Guidance, outlook, commentary, risks and unusual items

• Management expects approximately $6.0 billion of capital expenditures in each of 2017, 2018, and 2019. The Utility also forecast $80 million to $125 million of unrecovered pipeline-related expenses in 2017.
• The pending 2017 general rate case settlement proposed an $88 million increase in 2017 authorized revenue requirements, additional increases of $444 million in 2018 and $361 million in 2019, and a disputed potential 2020 attrition-year increase of $361 million. CPUC approval was not assured.
• The Utility's proposed cost-of-capital modification could reduce authorized ROE from 10.40% to 10.25% beginning in 2018 and was estimated to reduce annual revenue requirements by approximately $100 million, subject to market rates and CPUC approval.
• The Utility applied to retire Diablo Canyon Units 1 and 2 when their current licenses expire in 2024 and 2025, respectively. The proposal includes replacement energy efficiency, renewable, and other greenhouse-gas-free resources, a voluntary 55% renewable target beginning in 2031, and requested recovery of employee, community, procurement, and license-related costs.
• The Utility was convicted in federal court on one obstruction count and five pipeline-integrity counts. The January 2017 sentence imposed five years of corporate probation, five years of third-party monitoring, a $3 million fine, advertising requirements, and community service. Additional monitoring and compliance costs may not be recoverable through rates.
• The CPUC's 2015 natural gas penalty decision imposed $1.6 billion of fines, customer credits, disallowed capital funding, and remedial measures. The Utility had recorded $1.518 billion cumulatively through 2016, with additional 2017 charges expected.
• Other significant exposures include pending CPUC proceedings concerning alleged improper ex parte communications, gas safety and record-keeping, potential future safety citations, federal investigations, environmental remediation, nuclear decommissioning, cyber and operational risks, and the Butte fire.
• Environmental remediation liabilities totaled $958 million at year-end. Management stated that undiscounted future environmental costs could reach as much as $1.9 billion if contamination or remediation requirements exceed current expectations.

Most important facts for investors to verify

• Whether Butte fire losses exceed the $750 million accrued and whether insurance recoveries of approximately $625 million are ultimately collected; the filing states that losses above the accrued amount are reasonably possible but the upper range cannot be estimated.
• The final outcomes and financial effects of the 2017 general rate case, the FERC transmission rate case, the cost-of-capital proceeding, and the ex parte communications investigation.
• Actual unrecovered pipeline, compliance, monitoring, and remediation costs, including amounts excluded from rate base or otherwise not recoverable from customers.
• Whether CPUC approval of the Diablo Canyon retirement and replacement-resource plan is obtained, including recovery of the proposed employee and community costs and the Utility's remaining plant investment.
• The pace and pricing of future equity and debt issuance, potential EPS dilution, dividend capacity, credit ratings, and compliance with debt covenants.
• The adequacy and collectability of insurance coverage for wildfire, nuclear, environmental, and other catastrophic liabilities.
• The effect of renewable procurement, distributed generation, community choice aggregation, net energy metering, electric-vehicle infrastructure, energy-storage requirements, and changing customer demand on future rate base and earnings.