The stock of Pacific Gas and Electric Company’s public traded parent, PG&E Corporation, took a beating in the market during the wildfires this fall, but recovered some of its value.  Meanwhile the utility faces large potential insurance claims if power lines or other equipment belonging to it sparked the Camp Fire in northern California.  

The utility may ultimately be found not to blame.

The Camp Fire, which burned in Butte County, started on November 8 and was contained on November 25 after burning more than 153,000 acres and destroying nearly 14,000 residences and almost 5,000 commercial and other buildings.  At least 86 people were killed in Paradise, California.

The stock price of PG&E Corporation fell from around $48 per share on November 8 to less than $18 per share on November 15.  It had recovered to close to $27 by the time the NewsWire went to press.

PG&E Corporation said in a filing with the US Securities and Exchange Commission on November 9 that it and the utility renewed their liability insurance coverage for wildfires at a level of approximately $1.5 billion for the period August 1, 2018 through July 31, 2019.  PG&E Corporation said in the filing that if the utility is found liable for the Camp Fire, the utility could face “significant liability in excess of insurance coverage that would be expected to have a material impact on PG&E Corporation's financial condition.”

If downed power lines belonging to PG&E are found to be the cause of the Camp Fire, the company could be liable for $7.5 to $10 billion in damages.  PG&E said in the filing that it expects to be liable for at least $15 billion in damages related to wildfires caused by PG&E equipment in 2017, even before any additional 2018 liabilities are taken into account.

Senate Bill 901 enacted in September addressed liabilities from wildfires in 2017 and 2019 and beyond, but does not address 2018 wildfires.  (For more details about SB 901, see the “California Update” in the October 2018 NewsWire.)  Even before the Camp Fire, it seemed likely that the legislature would have to address the subject of 2018 fires in the next legislative session.  Assemblyman Chris Holden, who chairs the utility and commerce committee that is expected to take up the issue in 2019, has said PG&E is “too big to fail.”

In the interim, people having been asking questions about how PG&E’s financial woes affect power projects that have contracts to supply electricity to PG&E.

Numbers

For context, PG&E delivers over 61,000 gigawatt hours of electricity per year. Of this amount, approximately 53% comes from power plants owned by PG&E (with more than half of that amount coming from the Diablo Canyon nuclear plant that is scheduled to be shut down by 2025).

In 2017, 33.1% of PG&E’s energy deliveries came from renewable energy sources. Of this amount, 0.5% came from solar facilities owned by PG&E. The remaining amounts were purchased from third parties. Solar contributed 40.8% of PG&E’s renewable energy deliveries, and wind contributed nearly 24.9%.

According to public data released by the California Public Utilities Commission, PG&E has approximately 300 power purchase agreements with projects that are currently operating that use technologies that qualify for the state’s renewable portfolio standard.  These projects amount to more than 6,500 megawatts of capacity.  There are also dozens more power purchase agreements that are listed for projects that are “in development.”  

In PG&E Corporation’s latest annual financial statement, it projected total purchase commitments (undiscounted future expected obligations) for renewable energy of $36.679 billion.  This amount only includes power purchase agreements that have been approved by the CPUC and have met specified construction milestones.  This dwarfs the purchase commitments it has for conventional energy, which stand at $3.867 billion.

This means that a lot of counterparties are taking PG&E credit risk.

Many sponsors and financing parties are asking what happens to existing projects if PG&E is downgraded further or even files for bankruptcy.  

Developers are probably also asking whether PG&E PPAs are still financeable.

Default Triggers

If PG&E were to file for bankruptcy, it would roil the market in California, raising concerns about whether millions would have continued electricity and gas.  Project owners would wonder whether they will continue being paid and whether their PPAs might be set aside in bankruptcy.

In most PPAs, there is no ratings requirement or other financial test that the power purchaser must satisfy.  However, it is common to treat a bankruptcy filing or admission of insolvency by the power purchaser as an event of default.

Following bankruptcy, owners of projects would have to decide how to proceed.  Default options include leaving the PPA in place or terminating it.  Many older renewable energy PPAs require the utility to pay higher prices than could be obtained currently in the merchant market or by entering into another offtake arrangement (such as a hedge or corporate PPA).  A generator cannot stop performing a PPA after the utility defaults by declaring bankruptcy.

PG&E would have the option under bankruptcy law to assume or reject its contracts.  If a contract is assumed, then it must continue performing.  If the contract is rejected, then the counterparty is left with a general unsecured claim in the bankruptcy with a damages claim calculated pursuant to the terms to the PPA.  Despite having PPAs that may have high costs, PG&E may be willing to assume them because the CPUC generally allows PG&E to pass through to its customers amounts paid for electricity under PPAs as a purchased-power expense.

If PG&E attempts to reject PPAs, there could be a potential jurisdictional conflict between the bankruptcy court and FERC.  A full analysis of potential rejection of PPAs is very involved, but a bankruptcy court likely could allow PG&E to reject PPAs.

Many of the projects with PG&E PPAs were financed in the project finance market. These financings are privately negotiated and not generally available for review, but contain event-of-default clauses that are triggered if the power purchaser files for bankruptcy or admits insolvency.  After a default, the lenders usually can accelerate all obligations and initiate foreclosure proceedings.  However, if PG&E continues to perform under the power purchase agreement, the lenders may wait to take any action because they prefer not to foreclose so long as the debt is being paid.  Being in default is never a comfortable position.

Assuming that PG&E does not file for bankruptcy, as the legislature seems intent on avoiding, existing projects will still be affected, primarily because PG&E was recently downgraded.  Moody’s downgraded the senior unsecured debt rating of PG&E Corporation from Baa2 to Baa3, and it downgraded the utility’s senior unsecured rating to Baa2 from Baa1.

Such downgrades by themselves are not usually a default in a project financing.  There is usually no ratings requirement or other financial test for the power purchaser.

When lenders and tax equity investors are undertaking due diligence on a project, the diligence on the power purchaser is usually limited to ensuring that the power purchaser is an investment-grade counterparty.  

Tax equity documents typically will not contain any provisions related to the power purchaser (other than a consent right with respect to replacement of the power purchaser).  During negotiations, the financing parties are most concerned about losing an offtake contract due to the failure of the project company to perform its obligations, not the other way around.  Perhaps this will change in the future.

While most project finance debt is not publicly rated, some exceptionally large solar projects have debt that has been publicly rated by the rating agencies.

The rating agencies have downgraded debt on projects that have power purchase agreements with PG&E.

The downgrades are unlikely to have direct effects on the financings.  The publicly available financing documents do not contain any provision relating to the rating of PG&E.  However, the downgrades will have a couple indirect effects.  First, the debt is likely to be less valuable.  This will only matter to lenders if they try to sell their debt.  If the debt is held until maturity, a downgrade will not matter.  Second, to the extent the lower rating foreshadows further financial stress of PG&E to such an extent that it stops paying under the power purchase agreement, then other events of default (such as the failure to pay interest or principal) could eventually come into play.

Going forward, there will be some limited effects felt in the renewable energy market.

While the lenders to existing projects have little recourse, re-financing existing debt on projects with PG&E PPAs will become more difficult and expensive.  Given the seeming unlikelihood of a PG&E bankruptcy, lenders will probably continue to lend to projects with PG&E offtake contracts, but potentially only with a “PG&E premium.”

PG&E was not expected to enter into many, if any, new PPAs for a while even before the wildfire.  It is several years ahead of schedule of the RPS requirements.  In addition, the large utilities in California are rapidly losing load to community choice aggregators so they are reluctant to commit to new electricity purchases.

During the California energy crisis in 2000-2001 when PG&E filed for bankruptcy and Southern California Edison was teetering on the edge, downgrade provisions appeared in PPAs.  The return of such provisions is unlikely as long as legislative or regulatory relief makes it likely that PG&E will remain a going concern.