Washington — Though the bankruptcy of PG&E Corp. and its utility, Pacific Gas and Electric Co., has been anticipated for weeks, the reality of the Chapter 11 filing lays bare a dilemma of financial liabilities, contractual obligations and public safety issues likely to take years to untangle.
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Courts, lawmakers and energy regulators will seek a solution acceptable to stakeholders ranging from activist investors opposed to a bankruptcy filing in the first place, to California residents who lost homes and family members in the deadly wildfires of the past two years.
PG&E Corp. has disclosed its liabilities related to the 2017 and 2018 wildfires in its service territory "could exceed $30 billion." Responding to a federal judge's proposed order, PG&E Corp. on January 23 asserted that to "reduce to zero" the number of wildfires caused by the company in the 2019 wildfire season would require the removal of more than 100 million trees at a cost of $75 billion to $150 billion.
Since PG&E Corp.'s shares closed September 11, 2017, at an all-time high of $71.56 and a market capitalization of more than $35.5 billion, the company has lost tens of billions in value.
PG&E Corp. said January 14, one day after its CEO stepped down, that it views Chapter 11 reorganization as the best way to resolve potentially tens of billions in wildfire liabilities while continuing to operate as a utility. In the ensuing weeks, reports said the company could be looking to spin off its gas utility assets, though at an estimated value of $4 billion, several analysts questioned whether such a deal would substantively mitigate liabilities, while leaving PG&E exposed to costs from future wildfires.
On January 22, PG&E Corp. announced a deal with several major banks for $5.5 billion in debtor-in-possession financing, indicating the credit facilities would provide liquidity for what it anticipates will be a two-year bankruptcy proceeding.
On January 28 the California Public Utility Commission held an emergency meeting to discuss granting PG&E Corp. exemption from certain sections of the Public Utilities Code to provide it with debtor-in-possession financing before the expected bankruptcy filing.
PG&E Corp.'s bankruptcy plans have prompted strident opposition from hedge fund BlueMountain Capital Management, which argues the company has sufficient liquidity and other options to resolve its issues. Other experts and analysts have also questioned whether bankruptcy represents the best strategy by PG&E Corp. to change California's inverse condemnation law, which holds utilities responsible for damage to private property regardless of fault.
Further evidence that the company's fortunes remain closely tied to wildfire liability emerged January 24, when a finding by California investigators that PG&E was not the cause of the October 2017 Tubbs Fire caused shares to spike more than 75%. Despite the news brightening the company's outlook slightly, PG&E Corp. has not indicated that its bankruptcy intent had changed.
On Monday, an investor group led by Elliot Management reported offering PG&E $4 billion in funding to keep it out of bankruptcy, largely as a result of the reported reduction in liability. Another group, led by Citadel, was reported to have offered a competing financial package.
By press time on Monday, neither hedge fund offer could be confirmed. PG&E's stock closed on Monday at $12.03/share, giving PG&E Corp. a market capitalization of $6.23 billion.
WILDFIRES, INVERSE CONDEMNATION AT ROOT OF PROBLEM
PG&E Corp. and utility PG&E say they believe it will take roughly two years to enter and exit a federal bankruptcy proceeding.
Company management said as recently as January 24 that they face "extensive litigation, significant potential liabilities and a deteriorating financial situation," which, they noted, "was only further impaired by recent credit agency downgrades to below investment grade."
At the root of the holding company and its subsidiary's difficulties is a rash of wildfires dating back two years and the state's inverse condemnation law under which Pacific Gas and Electric, Edison International subsidiary Southern California Edison Co. and Sempra Energy's San Diego Gas & Electric Co. can be held liable for damages caused by wildfires that the California Department of Forestry and Fire Protection determines they have a hand in starting, even if the utility is not found negligent.
In a January 23 public-side lender presentation, PG&E Corp. noted that a Cal Fire survey released in October 2017 determined that in 18 of 21 fires in 2017, PG&E equipment was "involved" in causing the fire. However, determining exact blame for igniting wildfires has proven difficult. Cal Fire's clearing PG&E of blame for the 2017 Tubbs fire reduced to 17 the number of fires in 2017 for which PG&E has been blamed.
PG&E has indicated the Cal Fire report will not stop a bankruptcy filing. It said in a statement that resolving the legal liabilities and financial challenges stemming from the 2017 and 2018 wildfires "will be enormously complex and will require us to address multiple stakeholder interests, including thousands of wildfire victims and others who have already made claims and likely thousands of others we expect to make claims."
Responding to calls by investor-owned utilities to address the liabilities caused by inverse condemnation, in September 2018, then-Governor Jerry Brown signed into law SB 901, which called for "reasonableness" by the California Public Utility Commission when costs and expenses arising from wildfires are considered. But SB 901 applied only to 2017 fires, and PG&E Corp. has said it does not expect the CPUC to permit it to securitize costs relating to 2017 Northern California fires on an expedited or emergency basis.
Under inverse condemnation, a utility found to have been involved in the ignition of a fire that destroys property is sued by the property owner. The deadly November 2018 Camp Fire in Paradise, California, promised to escalate the number of lawsuits PG&E would face.
DECLINING CUSTOMER BASE
To date, among the biggest variables in a potential PG&E bankruptcy has been new California Gov. Gavin Newsom, who took office January 7. Some long-time industry observers have assumed that Newsom, along with the state legislature and the CPUC, would not let PG&E Corp. and Pacific Gas and Electric file their second bankruptcy in 18 years.
On January 23, Newsom made new appointments to the CPUC and the California ISO's board of governors. But, as of January 28, Newsom had made no official statements suggesting an intervention was in the works.
Indeed, by all accounts, the parent company and the utility were not actively seeking a state intervention.
In fact, what PG&E Corp. appears to have decided is that it needs a restructuring and reorganization in the face of changing power market dynamics.
The company has been concerned for more than the past year with an eroding customer base and declining demand for its power, much of which comes from comparatively high-priced power purchase agreements signed in the 2008-2011 time frame.
Roughly a year ago, in a speech in Houston, the now departed CEO Geisha Williams told a large audience that Pacific Gas and Electric's internal projections were for a 50% decline in its customer base by 2022 due to the rise in its service territory of Community Choice Aggregators, or CCAs, whose customer lists have been expanding at the expense of Pacific Gas and Electric.
In the same speech, Williams said the utility was looking at how to renegotiate a number of contracts to trim back its supply.
A key question to be answered by the bankruptcy filing is just how thorough and wide-ranging of a reorganization the company's new board of directors and interim CEO John Simon will pursue.
The company's key assets are its Northern California electricity transmission and distribution system, its roughly 4,000 MW of hydroelectric capacity and the 2,160-MW Diablo Canyon Power facility it says it will retire in 2024-2025, and its natural gas distribution and transmission pipeline unit that in 2017 was convicted of six felony charges connected to the 2010 San Bruno, California, pipeline explosion, for which it received a fine and a five-year probation period.
SUPPLIERS AND PPAs
PG&E's fidelity to its power purchase agreements remains a central theme of the bankruptcy, with analysts and bankers paying close attention to the proceeding's impact on the company's contracts, which include offtakes with 256 renewable projects with a combined output of nearly 7,000 MW.
"We are concerned about yieldcos with large contract exposure to [PG&E Corp.]," Macquarie Capital analysts wrote in a January 14 research note, citing Clearway Energy, NextEra Energy Partners and Atlantica Yield, "if only because they pay out 80-85% of projected [cash available for distribution] in dividends." Macquarie also noted PG&E honored its renewable power contracts during its 2001 bankruptcy proceedings.
In a recent report, CreditSights placed the odds of PG&E not rejecting above-market, pass-through renewable contracts during its bankruptcy at 70% to 80%, and was bullish for Clearway Energy, NextEra Energy Partners, as well as PG&E utility bondholders.
"The consensus is rejecting [pass-through] contracts doesn't make sense," Credit Sights analysts Andrew DeVries, Charlotta Chung and Nick Moglia wrote, adding that such a scenario would ultimately raise the cost of signing new renewable generation without benefiting PG&E in the bankruptcy case. Rejecting PPAs would also entitle the contracts' counterparties to join a claims pool alongside bondholders and wildfire victims.
But news of the bankruptcy still torpedoed the credit ratings at some facilities with PG&E offtake agreements.
Berkshire Hathaway Energy's 550-MW Topaz Solar Farm saw the rating on its $1.1 billion senior secured notes downgraded to a junk C rating from BBB- by Fitch Ratings on January 16. Fitch also downgraded to C from BBB- $140.4 million of trust certificates associated with the Genesis Solar Energy Project, a 250-MW facility co-owned by NextEra Energy Inc. and NextEra Energy Partners.
NextEra Energy attempted to shield itself from the bankruptcy's fallout, urging the Federal Energy Regulatory Commission in a January 18 complaint to prohibit PG&E from using its bankruptcy petition to "abrogate, amend or reject" the terms of its PPAs without the agency's approval. PG&E has requested FERC deny the complaint.
On January 25, FERC noted that courts are divided on the issue, and clarified that FERC's stance is that it has concurrent jurisdiction with the bankruptcy court. Thus, PG&E will need approval from both FERC and the bankruptcy court before changing or rejecting a PPA.
Three major gas pipeline companies, Ruby Pipeline, Transwestern Pipeline and Gas Transmission Northwest, have significant exposure to a PG&E bankruptcy. However, no significant changes in gas pipeline flows have been observed this month, and officials at one of the major pipelines expressed confidence their contracts would be protected because of PG&E's reliance on them to serve its core utility customers.
"I think there's some cause for optimism around the Ruby contracts in particular," said Steven Kean, CEO of Kinder Morgan, which owns and operates Ruby. Kean's remarks were in response to an analyst's question during Kinder Morgan's most recent investor presentation.
Ruby is a 680-mile, 42-inch diameter pipeline system with a capacity of 1.5 Bcf/d that extends from Wyoming to Oregon. PG&E holds 375 MMcf/d on Ruby in two contracts, one for PG&E's core electric generation operations and the other for its gas utility distribution business. The contracts are scheduled to expire on October 31, 2026.
"We view both of those as contracts that are core to PG&E's business," Kean said, noting the agreements total about $93 million a year in Ruby's pipeline revenue.
"These contracts are used by PG&E, and we've been told to expect continued utilization of those contracts," he said, noting the "reliability aspects" recently shown by an outage on GTN during which PG&E needed to rely more heavily on Ruby for gas supply.
Kean also noted that in PG&E's previous bankruptcy proceeding, the utility did not reject or renegotiate its firm pipeline transportation contracts. "That's not proof of what they'll do this time, but we think there are reasons for optimism with these contracts," he said.
Both Ruby and GTN, which is owned and operated by TransCanada, supply most of PG&E's gas supply via the utility's Redwood Path, which is the northern zone of PG&E's intrastate pipeline system. Receipts on the Redwood Path have averaged 1.79 Bcf/d this month so far, almost exactly in line with the December average of 1.8 Bcf/d.
PG&E's GTN contract totals 360 MMcf/d from Kingsgate, British Columbia, near Idaho border to Malin, Oregon, PG&E's main northern receipt point at the Oregon-California border. The contract is set to expire on October 31, 2020. Transwestern, which is owned by Energy Transfer, interconnects with PG&E's Baja Path at the Arizona-California border and is delivering only about 20 MMcf/d less gas this month than during December. PG&E's Transwestern contract, which totals 181 MMcf/d, also is scheduled to expire on March 31.
The bankruptcy proceeding, which is PG&E's second in two decades, is likely to be more difficult this time around, said Dennis Sperduto, principal analyst at S&P Global Market Intelligence.
"The last time they declared bankruptcy back in 2001, they emerged from it a little over three years later," said Sperduto, who says the utility's early 2000s Chapter 11 saga had its roots in "a badly designed electric industry framework."
"This time it's made worse for several reasons. There's an excellent chance there's negligence in some of the fires on PG&E's part. Not all of them," said Sperduto, citing the January 24 report absolving PG&E of responsibility in the Tubbs Fire. Additionally, Sperduto is far from confident that PG&E will still exist in something resembling its current structure.
"I don't think the company will end up surviving in its current state. I think there will be a big push to at least break up the company into separate electric and gas operations."
"For investors, the worst case scenario is things drag on for two, three, four years," said Sperduto, who expects the process to take some time, noting that the utility's last bankruptcy process took three years.
"I don't believe there's going to be a quick resolution."
-- Fotios Tsarouhis, Ashleigh Cotting and Dan Testa, S&P Global Market Intelligence; Jeffrey Ryser, firstname.lastname@example.org