A economics-driven fix for rising electricity prices is already paying off in the West: according to EDF, the Extended Day-Ahead Market (EDAM), which lets 38 power authorities in 11 states plan electricity use together, saved consumers $11.38 million in its first two months. VX News here features an interview with Michael Colvin, Director of the California Energy Program at Environmental Defense Fund (EDF), on EDAM’s early results, Western market governance, wildfire-driven rates, offshore wind, and Diablo Canyon. Read the interview below.
“The exciting news here is that the Regional Organization for Western Energy has now seated the first five members of its board….& we are already seeing immediate benefits accruing back to customers..”
Michael, when we last spoke in April, the day-ahead-market was days from launch, and you predicted a win on three metrics: customer savings, emissions, and reliability. With PacifiCorp now live since May 1, how is it measuring up against those metrics?
Michael Colvin: Since then, both PacifiCorp and Portland General Electric have joined the day-ahead market, and it has been what I would call a great win for customers and a non-event at the same time. We have seen no issues with these two entities joining the day-ahead market and with the expansion. It has been as smooth as humanly possible, and we are already seeing immediate benefits accruing back to customers, both in savings and in broader economic benefits. Especially with the heat waves we saw earlier this summer, we’ve already seen dividends on the reliability metrics as well.
You told us the West took a long time to figure out governance. Where does the transition to the Regional Organization for Western Energy stand today; and. is it gaining the confidence of the other states that you anticipated?
Michael Colvin: The exciting news here is that the Regional Organization for Western Energy has now seated the first five members of its board. They represent an incredible level of expertise and diversity—geographic diversity from around the West, gender diversity, subject-matter expertise—on basically every single metric. This is the group you want. They’re all people who want to be there: committed public servants dedicated to the energy world who are saying they want to be part of this. I could not be more excited.
If you’re a load-serving entity or a balancing authority in the West and you’ve been on the fence, asking, “Wait a second, will I have confidence in ROWE?”—this should be a huge nudge in that direction.
That’s a great segue to our next question. In 2025, you described Arizona as sitting on the fence. Its utilities have since signaled Markets+, while the Bonneville Power Administration is reconsidering and could join EDAM. Is the West settling into two markets, and what does that mean for the benefits you predicted?
Michael Colvin: It’s a great question, and I want to answer it in two parts. First, think about how much has changed in the last three years. Three years ago, when we first started talking about whether we could have a regionalization approach in the West—before any legislation passed in California, before EDAM launched, before everything that has since happened—it was a pie-in-the-sky idea. It was seen as a great technical idea and a win for customers, but politically infeasible; it just wasn’t going to happen. Look at how much progress has been made in the last two and a half to three years. It’s really remarkable.
So when you ask where the utilities are, where Arizona is, where BPA is, I think everybody is looking very closely at the numbers, because so much has changed so quickly. Starting with BPA, I don’t think the administrator would ever have issued that open letter saying, “Wait a second, here’s what I’m interested in, and I want to reconsider this,” if not for seeing the promise for customers and for reliability. In Arizona, the docket has also been looking at the numbers. A couple of weeks ago, one of the commissioners asked to make certain they’re making the right decision.
Is it possible that we end up with two markets? Absolutely. The Federal Energy Regulatory Commission has issued an order to both the Southwest Power Pool and the California Independent System Operator asking how we reduce seams—the friction—between these markets. There are decisions that need to be made to maximize customer benefit and minimize the wonky thing we call seams. EDF released a study a couple of weeks ago indicating that the difference between well-designed market seams and seams that are not fully considered is hundreds of millions of dollars back to customers. We need to get these details right.
Is it possible that the West eventually combines under one larger market and doesn’t have these seams at all? I still think that’s a distinct possibility, but it’s not going to happen all in one go. Every single balancing authority will have to consider many factors to make certain it’s the right choice for its market. All we need to do right now is be transparent about the numbers and the opportunities, and let customers make sure their decision-makers know what is in their best interest.
You’ve opined that wildfire costs are now the single largest driver of electric rates. With the SB 254 report on the table and EDF making the case for urgent action, what should the Legislature prioritize next session?
Michael Colvin: There is not going to be one grand, easy fix. If there were, we would have done it already. We have to make progress on a few different fronts.
One, we have to make certain that existing wildfire victims are taken care of. Two, we have to recognize that California has a major insurance problem: many homeowners in high wildfire-threat areas are either uninsured or underinsured. The third issue is the subrogation of utility debt if and when there is a utility-caused wildfire.
So how do we establish a priority that goes to the wildfire victims, address the underinsured and uninsured part of the market, and then handle the claims against utilities and that debt? Those are the table stakes. They need to be addressed no matter what.
From a utility bill perspective—the last part of your question—I’m keen to see two things. First, are there non-ratepayer sources of funds that can be used for mitigation, to get some of these costs off bill? Second, for what remains on bill, do we have the right balance between costs recovered over a very short period, treated as operational expenditures, and capital-style investments recovered over a longer period?
When I look at Pacific Gas and Electric’s general rate case—its main request for funding—they’re trying to rebalance that mix between short term and long term. That’s going to be a real question we need to get right: can we recover some of these costs over a longer period? This is a once-in-a-generation level of investment in wildfire hardening. Should we spread those costs out over a longer period? That would require a change in how we do ratemaking, but it might be the right thing to do.
In your opinion, does the CPUC have the will and tools to handle this issue?
Michael Colvin: There are certain things the CPUC can do within its existing authority, and I think it has a lot of discretion. But the Legislature needs to recognize that the CPUC only has so many tools available right now. The CPUC cannot change inverse condemnation, for example. There has been a lot of buying and selling of wildfire claims by hedge funds, and the CPUC has no ability to control that or the transaction costs. What the CPUC can do is certainly consequential, but it is not the full picture. The Legislature either needs to give the CPUC additional authority or pursue other discretionary actions to solve this customer problem.
You’ve stressed that rates and bills are not the same thing. You flagged a California premium on utility shareholder returns. What came of the cost-of-capital proceedings; and, which affordability levers matter most now?
Michael Colvin: Great question. In the last cost-of-capital determination, the CPUC returned about $300 million per year in total to customers through a cut to shareholder profits. It was a meaningful step, but not the final step that needs to happen.
I also want to highlight that EDF sponsored a bill the Governor signed this past legislative session. It was authored by Assemblymember Cottie Petrie-Norris—AB 2463—and it aims to increase transparency in how cost-of-capital determinations are made. It basically says, “CPUC, as you make these determinations, show your work.” Many of these determinations are really model versus model in a black box, and the bill tries to unpack that, both for the market’s sake and for customers’ sake. I’m very excited to see it implemented in the next year.
To offer context: How is a bill like AB 2463 implemented?
Michael Colvin: AB 2463 applies to the next cost-of-capital cycle and determination. It requires a certain amount of reporting and transparency on how the cost-of-capital calculations are done—as the CPUC weighs the different betas and factors, it must show the numbers it used in its determination and make that clear. Certain reports are required as part of that process.
I should have included this in my last answer, so apologies. There is a difference between the cost of capital the CPUC authorizes—essentially the maximum allowable authorized ROE—and the actual realized return on equity. Ideally, you want the authorized and actual returns to be very close.
They’ll never be perfectly aligned, but you want them pretty close. If actuals differ significantly from what’s authorized, that’s generally a sign that something hasn’t gone right. My thesis over the last year or so has been that customers are generally over-rewarding shareholders, and that we need to be very cognizant of how those determinations are made.
There has been a distinct effort to examine the difference between authorized and actual returns on equity. An entire record was developed on this as part of PG&E’s general rate case, and we’re very curious to see what the Commission comes up with there. There’s more work to be done.
The CPUC halted Angeles Link in April. How does that decision impact the market for Hydrogen in California and the role of decarbonized fuels for heavy industry?
Michael Colvin: Earlier this year, the CPUC said it would not move forward with the Angeles Link project, and it gave many reasons. The suspension of federal funding for ARCHES was, I think, one of them. Frankly, there was also the question of whether regulated gas customers of SoCalGas—the applicant in that case—should bear the cost, and who should bear it. There were open questions there, and the Commission basically said it’s not the right time to do this.
There’s still an open question about what happens to the money already spent on Angeles Link—whether it should be recovered from customers. We’ll see what the Commission decides. I have personal views on it, and EDF has put some of that into the record.
Going to the heart of your question—the role of decarbonized fuels like hydrogen—I think it’s an open question. There’s still a pending set of applications before the CPUC on whether we should have blended hydrogen projects in the existing natural gas pipeline system. I’m happy to opine on whether that’s a good deal for customers. Spoiler alert: I don’t think it is, but we can talk about that if you want.
And you take on the future of dedicated hydrogen pipeline infrastructure?
I think dedicated hydrogen pipeline infrastructure is the way to go. The real questions are who needs it, how big it needs to be, and where the hydrogen will come from. I don’t think the state has really wrestled with those questions yet. SoCalGas gave it a try, and the facts changed on the ground as they were making that attempt. They’re probably gun-shy about trying again. We have a lot of answering to do, and I think the next administration will have to look at this question very closely.
To follow up: VX News reported, from a Hydrogen Pipeline Safety news release, that Governor Newsom signed SB 804, the Hydrogen Pipeline Safety Act. The bill passed both chambers unanimously. It sets hydrogen-specific standards for leakage, material compatibility, and continuous monitoring, and places oversight of non-CPUC hydrogen pipelines under the State Fire Marshal. Is that responsive to what EDF has been asking for?
Michael Colvin: It’s certainly responsive. I don’t know that it will solve the problems in total, but it is absolutely a step in the right direction.
Pivoting to offshore wind – you have shared with VXNews that California could work within the 10 gigawatts of Wind already leased. With the federal buyout and Attorney General Bonta’s challenge, is that still realistic? And what role does the regional market play with respect to offshore wind?
Michael Colvin: Great question. Let’s set the stage. Under the Biden administration, the federal government leased five sites to developers in a fair and transparent process. At the turnover of administrations, the Trump administration issued an executive order suspending offshore wind, which was then struck down. The federal government then tried a couple of other things that were also struck down. Basically, everything on offshore wind that has hit the courts to date, the federal government has been told, “No, that’s not how this works.”
In response, the federal government went directly to the leaseholders and offered to buy back the leases using money never appropriated by Congress. The Department of the Interior wanted to use funds from a blanket Department of Justice settlement fund that was never meant for these purposes. Three of the five leaseholders have taken that deal.
Upon seeing this, California issued subpoenas through the California Energy Commission and, after reviewing them, issued three notices of intent to file lawsuits. Two of those have now become actual lawsuits. Under the Outer Continental Shelf Lands Act, you have to wait a certain period between the notice of intent and filing the lawsuit, and we’re in that waiting period on the third. I fully anticipate that once it’s up, California will file a third lawsuit against the administration for the illegal or inappropriate use of these funds.
And the significance of these suits?
Michael Colvin: The significance is to establish that it was improper for the federal government to use these monies and offer these lease buyback deals, and that these were inappropriate—basically bullying—tactics. That’s my guess as to what will be found based on the subpoenas the California Energy Commission issued. My guess is that the lease buybacks will be ruled improper and the leases will revert. How that happens and what the end state looks like—my crystal ball is as good as yours. We’ll see what the courts decide, or whether there’s some other disposition of these lawsuits.
There’s still an open question of how we give developers and investors enough confidence that California is still the right place to invest in offshore wind.
I should go back to my answer for one second, because I didn’t say this clearly enough. Part of the buyback deal the Trump administration offered the developers was: we’ll give you your money back, and we hope you use it for fossil projects instead. California said no, that’s not how this works. We get to set our own procurement policies. This is an illegal use of funds and an overreach by the federal government in the conditions it’s placing.
I’ll also note that California’s energy policymakers have a long memory. If a developer took this deal, it would be very hard for them to get another contract approved in California. Why would state regulators have confidence in you if you were willing to leave California on a high-priority project like offshore wind? Some complicated dynamics are going to unfold here. Whether these leases revert to the original developers, get re-auctioned, or another developer comes along and wants to take them over—there are a lot of options. The state might want to hold its own auction. I’m not exactly sure how it’s going to shake out.
The other part of your question—how offshore wind plays into the market—is really important. As of now, and for the foreseeable future, the existing lease sites are off California’s shore. Oregon wasn’t able to get its auction done in time, and Washington was even further behind. So the West Coast and the Western states will probably look to these five lease sites to access offshore wind, and the right way to share that electricity across state lines will be through the Regional Organization for Western Energy.
It probably won’t be through the day-ahead market service, but through some future market service offering. As ROWE develops its list of market services, it will likely look at how to share big, expensive contracts that benefit many customers across state lines, and probably develop something for offshore wind, long-duration energy storage, and enhanced geothermal—resources that are a really good fit for the grid, that many utilities and balancing authorities will want, but that no single balancing authority will want to develop on its own. As you look at ROWE’s priority list, I think emerging resources like offshore wind, enhanced geothermal, and new forms of long-duration storage will be part of that conversation and a very high priority.
Last question. This past April, you said the state would need scenario planning with or without Diablo Canyon. Has that planning advanced; and how does rising load from data centers change the calculus?
Michael Colvin: The planning is in flight, is how I’d put it. Nothing has officially been decided yet, but the next steps on those scenarios have taken hold.
On data centers, Diablo is an interesting fit. It’s a baseload resource, and data centers in part need baseload, high-reliability power, so there’s a natural match. The open question is whether it’s the only match. For the new load coming from data centers—which is somewhat speculative—the state has not yet said what the best fit is, and there hasn’t been a uniform decision. I don’t think data center load will determine whether Diablo stays online, because there are a lot of other options available.
I think we talked about this in April, but to say it again clearly: Diablo is a best-in-class facility, seen as a national model of how a nuclear facility should be run, and the people who work there are great. When I raise questions about Diablo, I’m not saying anything bad about the workers or how the unit is run. But we should recognize that it’s older technology and an expensive investment for customers. We should think long and hard about whether this is the best place for customers to make that investment. It very well could be, but that’s the question we should be asking ourselves. It’s not an aspersion against the unit or how it’s operated.
