What will the California power markets look like in the next 10 years? Will there be incentives for new gas plants? What is the future for a separate capacity market? How much need will there be for additional power? Will the RPS targets increase again? How will California deal with imports of out-of-state power? What transmission challenges will the state face? What will it take to integrate the huge amount of renewables with the grid? How will CO2 cap and trade affect pricing and capacity? What new environmental restrictions are likely to be imposed? A panel talked about the challenges and potential opportunities in the California market at the 24th annual Chadbourne global energy and finance conference in California in June.

The panelists are Dr. Robert Weisenmiller, chairman of the California Energy Commission, Jan Smutney-Jones, executive director of the Independent Energy Producers Association, Mitchell Ross, general counsel of NextEra Energy Resources, and Bill Monsen, a principal with MRW & Associates, a prominent California consultancy. The moderators are Bob Shapiro with Chadbourne in Washington and Paul Kaufman with Chadbourne in Los Angeles.

MR. SHAPIRO: Bob Weisenmiller, what is the difference between the California Energy Commission and the California Public Utilities Commission?  

DR. WEISENMILLER: The California Energy Commission was started in the 1970s. It does power plant siting. Any thermal power plant over 50 megawatts must come to us for approval. We also do energy planning for the state, and we look at all the various options.  

One of the things we look at is energy efficiency. We do building and appliance standards in California for new construction. We also do renewable energy development. We decide what qualifies as a renewable, and we are now starting to look at what the municipal utilities are doing in terms of their renewable portfolios. We also do contingency planning to make sure the state is prepared in case anything goes wrong.  

The CPUC is more than 100 years old. It started as a railroad commission. It regulates the rates that utilities can charge for power, telephone, transportation and water.

MR. SHAPIRO: Jan Smutny-Jones, how are the California utilities doing on meeting their renewable portfolio targets, and are both investor-owned utilities and municipal utilities now required to meet state renewable energy targets?

MR. SMUTNEY-JONES: They are at about a 20% renewable energy mix. We will be at 25% by 2016. The utilities will tell you that they are well on their way to reach 33% by 2020. The municipal utilities have also become fairly active. The municipal utilities in northern California are ahead of their colleagues in the south. There is a significant amount of new activity in the renewables sector. The portfolio part of the renewable portfolio standard is gone. All the new development is largely solar PV right now, which is creating a new set of dynamics and issues.  

PPA Failure Rates

MR. KAUFMAN: All of the procurement in California for renewables is done through requests for proposals and some bilateral contract negotiation. You hear about high failure rates as some developers were too aggressive in their bids. What do you think the failure rate is today?  

DR. WEISENMILLER: The utilities will be on track to reach a 33% renewable portfolio by 2020 assuming a 40% failure rate. If we look at projects on the ground, the actual failure rate is not close to 40%. What happens is that someone turns in a bid, but cannot develop the project, and someone else steps in and gets the project done. I think there will be more development of renewables than we are projecting.  

MR. MONSEN: I am a little more pessimistic about the failure rates, but between 30% and 40% is a fair estimate. The other thing that will happen over the next 10 years is that we will start to see some of the shorter-term renewable contracts end, a peak in the contracted levels in 2018 or 2019 and then a fall off. There may be room for new contracts after 2019.  

MR. ROSS: There are quite a few wind projects that will start coming off contracts in the next several years, and those are excellent opportunities for renewables.  

MR. SHAPIRO: Is it still the case that new renewable energy projects in California cannot be financed without long-term power contracts? Can a power hedge work?  

MR. ROSS: We think a PPA is essential. We think that the state RPS targets are aggressive and that the municipal utilities are behind the investor-owned utilities in achieving their goals. These projects are perfectly suited, from an operational perspective, for PPAs.  

Future Drivers

MR. SMUTNEY-JONES: I would be careful about getting fixated on the 33%. That number materialized out of the ether. Climate change policy will be driving California energy policy over the next several decades. My sense is that we reach 33% and then people will go “Well, now what are we going to do?” Climate change is a fairly big and complicated issue that cuts across all technologies. The big issue today is how to have more renewables and also have the electricity during the time of day when you need it most.  

MR. SHAPIRO: So even if the state reaches 33% renewable energy by 2020, the utilities will have to buy even more renewable energy to meet new CO2 targets?

DR. WEISENMILLER: When I joined the governor on a trip to China recently, we visited with provincial officials at every stop, and climate change was very much on their minds. I am the scientist on the California Energy Commission. If there are any doubters, go down to the Scripps Oceanographic Institute where they have a pier where they have measured the temperature of the water since 1910. The water temperature has gone up two degrees in that period of time. We are seeing clear climate change during our lifetimes. We have very aggressive goals for 2020, but we are also now starting to look at 2050. We are being forced to think about decarbonizing our power system. We are starting to set very aggressive goals by 2050 and to think about where we need to be by 2035 to reach them.  

MR. SHAPIRO: Has the CEC been looking at how electric cars in California will affect electricity demand as well as carbon reduction?  

DR. WEISENMILLER: The governor set a target for 1.5 million electric vehicles on the highway by 2025. One reason is we still have major air pollution issues in Southern California. Eighteen percent of the economy along the south coast is goods movement. We have no choice but to electrify the transportation system. As we electrify the transportation system, it will affect the power system. As we shift more vehicles over to electricity, that will enhance the mandate for renewables since 33% of a growing number of megawatt hours is a larger number of renewables. The transportation system is such a huge lift for our economy and it affects all of us in such fundamental ways that electrification will require thousands and thousands of decisions to make it happen.  

MR. SMUTNEY-JONES: Forty percent of the carbon footprint in California is transportation. Twenty percent is the electric sector, of which only half of that is electricity generated in California as opposed to neighboring states. We will not get to our climate change goals unless the transportation issue is addressed, and we view that as a potentially big market opportunity.

MR. SHAPIRO: It will drive up demand for electricity.  

DR. WEISENMILLER: Right. We are very concerned that charging all those cars occurs off peak, although when we assess the impact of the explosive growth of solar PV on our systems, we could easily end up double peaking. We have wind at night and solar during the day and, as the wind drops off in the morning just as loads go up, solar will bear some of that load. At some point when the solar peaks, we could basically see the net load dropping and then, as the sun sets, have this incredible load spike followed by the sun setting and the wind coming up and loads dropping. That is basically a double peak, and it means that we may find ourselves at some point trying to encourage people to charge at what would have been our traditional peak times.  

We have a couple things to think through trying to figure out the operational impacts of renewables plus transportation. Add on top of that the decision to close the San Onofre nuclear plant. It is a pretty challenging set of options to think through now.  

MR. SHAPIRO: And you have growing distributed generation, which may end up reducing load.  

DR. WEISENMILLER: In the last year, we have added about 1,000 megawatts of large-scale solar. I expect by the end of this year, another 1,000 megawatts will be added to our grid. We also have about 1,700 megawatts of behind-the-meter renewable distributed generation installed. We have 160,000 solar installations in California, and we are on target to get to one million. A lot of it is behind the meter and coastal. We have a lot of it along the coast in areas that have fog coming in and out. These are huge operational issues with which we are dealing.  

Power Plant Retirements

MR. SHAPIRO: San Diego Gas & Electric and Southern California Edison have decided not to try to restart the San Onofre nuclear plant. That is 2,300 megawatts of generating capacity that will disappear.  

MR. ROSS: I feel a lot of sympathy for Southern California Edison and San Diego Gas & Electric customers in Los Angeles and San Diego. It was not a technical issue that prevented the restart of the San Onofre units. It was an issue of how much time and money would have to be invested and just the difficulty nuclear faces in public perception. There are other examples of nuclear units across the country that were in perfectly good shape, but that for regulatory uncertainty or other economic reasons were shut down. It is usually not due to technical issues. Nuclear has a challenging reputation. When something goes wrong on a wind farm, you fix a turbine blade here and there. When something goes wrong in a nuclear plant, it is a very bad day.

MR. MONSEN: San Onofre was obviously a critical asset in the Southern California grid. It supplied local capacity to the load pocket in Southern California. It will be an enormous challenge to replace the generating capacity in an area in which it is very difficult to site new power plants given air and water regulation in California. It will mean a larger effort to implement demand-side measures that may or may not perform.  

MR. SMUTNY-JONES: A question that will have to be addressed is how to reach carbon policy goals after shutting down 2,300 megawatts of carbon-free energy.  

MR. KAUFMAN: Once-through cooling is another problem in California. The last time I checked, something like 17 or 19 power plants, many of them in southern California, had this type of cooling system.  

DR. WEISENMILLER: We have about 6,000 megawatts of existing power plants along the coast with these types of systems. They will have to be either repowered or replaced. Federal law requires them to stop using ocean water for cooling. Most of those plants are old, post-Korean War vintage. They operate about 5% of the time. So they are not exactly barn burners in operational capacity, but they are very important to reliability.  

Statewide, we have a lot of power. Reserve margins are well over 20% for a one-in-10 weather event, which is the conventional metric, so that is not the issue. The issue is that the transmission system is built around the assumption that San Onofre is operating so that we can power San Diego. We are struggling with the issue of what happens without San Onofre, what is the right mix of preferred resources and how many of those coastal thermal units should be retired or replaced.

MR. MONSEN: The CPUC in its decision on local capacity requirements authorized Southern California Edison to procure between 1,000 and 1,200 megawatts of new gas-fired generation over a certain number of years on the understanding that the cooling regulations would be met. The CPUC did not say those plants will not be repowered, but did say those plants as they exist today will not continue to operate.  

MR. SMUTNEY-JONES: This is a very complicated problem because you need 8,000 to 10,000 megawatts of generation in in the area north of San Diego to keep the system going. You cannot just import all of that. There is a big issue of how to replace these units.  

When Huntington Beach was built, there was nothing but farmland around it. There are now very expensive homes, and we have a very strong environmental community that is happy to see the rest of the country moving from coal to gas but wants California to move off gas. In some proceedings, we end up with people saying, “You don’t need to do anything because we are going to meet it all with rooftop solar and demand response.” This is “the unicorns are coming” theory of utility planning. This is going to be a huge issue. Those units were built in the Eisenhower era. The capacity factors of those units were around 60%. The 2010 number was something like 4% in terms of capacity.  

Skewed Incentives

MR. SHAPIRO: It is one thing to say that you need capacity. It is another to have a mechanism to encourage people actually to build the new capacity. Is there going to be a capacity market? Why has the CPUC been reluctant to encourage a capacity market, and what is happening with flexible capacity?  

DR. WEISENMILLER: We have very little demand response in California that can activate within a half-hour time frame. Most of it requires 24 hours. So if you are looking at renewable integration, demand response is not particularly useful. At the same time, we have existing thermal units that are operating less than 40% of the time.

All of us, the CPUC, the California Independent System Operator that runs the grid and the CEC, agree that we need some sort of forward market. Part of the issue is jurisdiction. Is it under federal or state jurisdiction? We had a pretty horrible experience around the year 2000 with FERC jurisdiction. There is a lot of reticence by the CPUC to cede any more jurisdiction to the Federal Energy Regulatory Commission. At the same time, there is certainly an understanding that we need some sort of multi-year procurement process.  

The reality is that conversation is going to go on for a few years until we put in place a mechanism that provides the pricing signals we need, but that has the jurisdictional aspects that we can live with.  

MR. MONSEN: The utilities have held all-source solicitations for new resources, and they have explicitly excluded existing resources from those solicitations. So we have this bifurcated capacity market in California. You can get up to a 10-year PPA for new gas-fired generation. However, existing generation is stuck in the one to three-year resource adequacy world, and it is very hard to make long-term capital decisions given a one- to three-year time frame.  

MR. SMUTNEY-JONES: The problem really comes down to the jurisdictional issue as the chairman indicated. During the energy crisis in 2000 and 2001, a letter was sent by every member of our Congressional delegation, including Darrell Issa, telling FERC to leave its hands off the California ISO.  

However, people forget that the CPUC failed to approve longterm contracts, which would have eliminated all the volatility we saw that summer. The only story anyone here remembers is that FERC did this to us and so the problem is that the California ISO is regulated by FERC.  

We have added 16,000 megawatts of gas-fired generating capacity since 1999. At the end of a 10-year PPA, you are just out. You cannot bid into any new solicitations. We probably have 10,000 megawatts in contracts coming to their 11th year within the next four years. This is going to be a noisy, complicated mess, but we will sort it out within the next 18 months. It will not look like a capacity market.  

MR. KAUFMAN: It has been said that when California, sneezes the rest of the country catches a cold. When you look at the entire country, where do you think the capacity issues have been handled correctly?  

MR. ROSS: I am not sure that I can attest to a very good or even a preferred approach to handling capacity markets. We are struggling in a lot of places like the Northeast because they are going to turn that market upside down. We are happy to serve California. We are happy to provide services to our customers in California. We pretty much stay out of this discussion.  

Out-of-State Generation

MR. SHAPIRO: To what extent can out-of-state generators help solve this problem? Are transmission constraints so severe that new transmission cannot really be part of the solution?  

DR. WEISENMILLER: There is a role for out-of-state generation. We have a very good relationship with Nevada. It is only going to improve. The energy imbalance market is a way to help on a lot of the renewable integration issues around the West. Ultimately, we will have to deal with the fact that we have 38 balancing authorities in the West, but it is a good first step.  

Many out-of-state generators come to my office saying, “We are able to provide 3,000 megawatts so you can get to 33%.” The answer is that we are going to get to 33% even without out-of-state generation. Out-of-state generation can be a part of a future conversation. By law, we have a pretty strong preference for the first 33% to be California-centric.  

The only real question is the timing of when we go above 33% in our planning. We are trying to deal with some of the consequences of success that I do not think anyone anticipated. Most of these people, when they built the gas-fired assets, thought they would be operating at about 80% and not 40%.  

The next question is how to deal with the operational issues. The last time that we looked at capacity markets, we looked at what was occurring in the rest of the country. That was part of the reason to step back. We figured that we had been at the cutting edge enough, and we wanted other people to run that gauntlet for a while. Hopefully, we can move forward and build off of some of the experience elsewhere.  

MR. MONSEN: In terms of out-of-state generation, California has a very clear mandate for in-state renewable generation. Out-of-state gas-fired generation is not going to play a large incremental role in the state primarily because the state is awash in capacity. The value of out-of-state capacity to the investor-owned utilities is low. Its capacity is much more valuable when it is targeted to local capacity areas.

Cogeneration

MR. KAUFMAN: That is a beautiful segué to my next question. What role will combined heat and power or CHP play in meeting capacity needs?  

DR. WEISENMILLER: CHP is great as a local resource. The issue we are running into is a very complicated settlement among the CHP community and the utilities that is rolling through utility procurements to enter into PPAs.  

The utilities see themselves as being baseload long. This means that existing geothermal is having a hard time getting any contract. CHP, if it is baseload, is going have a hard time getting a contract. I have had my folks go through the state facilities in Orange County and San Diego to see whether there are any CHP opportunities. Unfortunately, there is just not a lot of thermal load in Orange County.  

MR. MONSEN: The Crockett cogeneration project is 240 megawatts. It is up in the San Francisco basin area and was essentially fully dispatchable earlier. It has since gone back to a more baseload type of agreement. It is not impossible for combined heat and power to do that.  

MR. SMUTNEY-JONES: Our air board came up with around 7,000 megawatts of potential demand for new CHP facilities. Someone made that figure up, too. Back in the early days of the independent power industry, the reality was that we actually had industries in California that needed steam for industrial uses. We were making paper, glass and things like that. Well, we don’t do that anymore. We do all kinds of other things. I think the thermal load from an industrial perspective is gone. I do not see demand for another 7,000 megawatts of power plants that generate both steam and electricity.  

The kind of capacity that California really needs is locational and flexible. For example, at 12 p.m. today, there will be 1,900 megawatts of utility-scale solar and about 1,500 megawatts of solar behind the meter. That will run at maximum output until 2 p.m. and, by 5 p.m., it will drop to almost nothing. We peak at 4:30 p.m. in California. The ramp rate at the end of the day is going to be huge. You are going to need enough gas-fired generation to integrate the solar. Without this, you have a big problem.