CCAs and risk management

Author: Deanne M. Barrow Publication | June 5, 2018

Sixteen community choice aggregators that buy electricity, primarily from renewables, to supply to county and city residents are now operating in California. Another eight CCAs are expected to start operations this year.

The CCAs face a series of challenges, not the least of which is forecasting electricity load, since customers who sign up are free to switch electricity suppliers at any time. The California Public Utilities Commission is still debating how large an exit charge to assess against customers who leave the three California investor-owned utilities for CCAs to help reimburse the utilities for the cost of “stranded” equipment the utilities purchased at a time when they had a legal duty to serve a broader market.

A group of panelists talked at an Infocast community choice energy conference in La Jolla in April about the types of risks facing CCAs and how they manage them.

The panelists are Richard Engel, director of power resources, at the Humboldt County CCA Redwood Coast Energy Authority, Ramon Abueg, chief operating officer at Valley Electric Association, Inc., Ranbir Sekhon, director of portfolio planning & analysis and energy procurement & management at Southern California Edison, Samuel Golding, president of Community Choice Partners, and Kent Palmerton, principal at WK Palmerton Associates Inc. The moderator is Deanne Barrow with Norton Rose Fulbright in Washington.

Internal risk management

MS. BARROW: Let’s start by hearing from the two industry consultants on the panel. How have you seen the approach of CCAs to energy risk management evolve over time?

MR. GOLDING: Over the last 12 to 18 months, there has been a sea change in how CCAs go about energy risk management structurally. Richard Engel’s CCA — the Redwood Coast Energy Authority — had a lot to do with spreading the 2.0 model, as we have been loosely referring to it, and leading by example. The 2.0 model brings in a more transparent, industry-standard approach to managing energy risk.

The early CCAs relied on a broker or consultant who would hire a power marketer under a full-requirements contract plus schedule coordination to interface with the CAISO market. The new CCAs hire an independent contractor who operates as an extension of the CCA staff and has all the functional capabilities that energy service providers, power marketers or utilities have to manage the purchase of energy products. These energy “portfolio managers” are often owned by public power entities and operate on a non-profit and highly transparent basis.

By tapping into this institutional capacity from the start, the new CCAs are able to use industry-standard software and gain access to unbiased expertise to analyze all of the sources of risk. This allows the CCAs to contract with various counterparties for a range of products layered over different time periods, and they structure a diversified energy portfolio that is customized to their risk tolerance and policy objectives.

It is a night-and-day shift. The old-versus-new approaches are almost incomparable.

All CCAs are startup enterprises that rely on third parties at launch for key operations. Structurally, the big fork in the road for CCAs in terms of energy risk management is what type of advisors they choose to hire for planning and procurement. It used to be standard practice to hire boutique consultants, but over time CCAs have been moving to hire energy portfolio managers as a superior alternative. Redwood Coast Energy Authority was the first agency to adopt this business model. Kent Palmerton and Richard Engel can talk more deeply about the significance of that choice.

MR. PALMERTON: I started in this business in the 1970s. I have seen the municipal utilities grow up, and I have seen the marketers, brokers and independent power producers grow up. They all started not having a clue about what it took to run the grid and, over time, they have matured to a place where they are now contributing to keeping the grid running.

The CCAs started as full-requirements customers. They are now facing a much broader set of responsibilities. Whether or not the California Public Utilities Commission is correct in the way it is applying oversight will be worked out in the wash. There is a reliability council that needs to continue talking about how to keep the grid running. There is a distribution planning function. CCAs have to take responsibility for some of these issues.

Marin and Sonoma Counties and maybe Lancaster started out with a black-box approach. Political types created the CCAs, and then each outsourced its entire program to one vendor — Shell in the case of Marin, Constellation in the case of Sonoma. Inside the CCA, there were no professionals with utility experience.

They had no clue what was being done for them and, in some cases, it was inefficient. The CCA 2.0 model that Samuel Golding and others have been talking about is for the CCA either to have internal staff or dedicated internal professional consultants that act as staff.

Maybe the CCA 3.0 model will be one where there is an overarching joint action agency or actual professional staff.

Risk management in this context means managing uncertain outcomes, whether from a regulatory, financial, human resources, facility or infrastructure standpoint.

Risk management crosses boundaries within an organization. It is a means to mitigate or at least understand the exposures and risks facing the organization. As a CCA engages in things like long-term financing, it just adds additional risks with which the CCA lacks experience. Each layer has a new set uncertainties that has to be managed.

It is not a good idea to have multiple parties responsible for the same areas. In time, we will figure out who should be responsible for the issues that affect the grid.

MS. BARROW: Let’s hear from the CCA on the panel. Richard Engel, tell us a little about how Redwood Coast Energy Authority got started and the approach it takes to risk management.

MR. ENGEL: We are a bit different from most of the other CCAs in California in a few ways. One difference is we were a pre-existing joint powers agency. We were established around the same time as the San Diego Regional Energy Office. This was in the wake of the California electricity crisis in the early 2000s. Humboldt County was looking for a way to take more local control over its energy destiny. We are an energy peninsula that is somewhat isolated from the rest of the power grid in California.

In the face of these challenges, we set up the Redwood Coast Energy Authority in 2003. We focused initially on demand-side management. That was the lion’s share of our effort for the first decade or so. We then branched out into transportation electrification, developing and operating a network of public electric vehicle charging stations around the county. We did a renewable energy secure communities study with funding from the California Energy Commission. It led to the establishment of our CCA program in 2017 as a strategy for moving to a renewable energy-based local energy economy. We are about to celebrate the one-year anniversary of our CCA launch in May. We have about 60,000 electric accounts serving about 700,000 megawatt hours of load annually.

I want to acknowledge what Kent Palmerton said about the value of building on the experience of others. People have been buying and selling energy for a long time — well before CCAs were around. In our case, our power manager is The Energy Authority, and it came in with years of experience serving dozens of clients like municipal utilities. We did not have to reinvent the wheel in terms of our risk management.

We have a risk management policy that is downloadable from our website, and I have made sure that the current version is posted there. We first adopted it in December 2016, which is about six months before we started serving customer loads. This coincided with when we started actually doing power procurement. We recently revised it and updated it to reflect some changes in our organization, and our board adopted the updated version earlier this month.

I encourage other CCAs to look at it. It is a good model. One feature is it defines our risk management team, of which I am a member. We have five director-level staff within our organization who share the role of being risk managers. They are supported by a staff member from The Energy Authority, and one additional outside independent person of expertise in energy risk management also serves on that team. We review all developments affecting risk that have happened in the preceding month.

A table in the policy is the essential kernel of the risk management policy. It shows our transactions by volume, term, maturity and cash value. Smaller transactions can be done on our behalf by The Energy Authority. If transactions move above a certain level, they need to be approved by our executive director. Then there is another tier with cutoff points and specific numeric values that requires approval by majority vote of our risk management team. We have had a couple deals that exceeded that level and had to go to our board of directors for approval.

Taking a step back and looking at the broader concept of risk management, in 2012 we completed a study that was funded by the California Energy Commission to look at what it would take to make Humboldt County, our service area, a renewable energy power community over a two-decade time span. Forming the community choice energy program was one of the actions identified. It is what prompted us to establish the CCA program.

Forming the CCA was one measure to address a number of risks to our community, including climate change, energy security and resiliency, and energy affordability. I see the very creation of our CCA, its operation and its expansion as a risk management strategy.

MS. BARROW: Ramon Abueg, you represent Valley Electric Association, which is a not-for-profit electric cooperative based in Nevada and California serving 22,000 accounts.

What advice do you have, what parallels and commonalities do you see with CCAs, what best practices can you share?

Advice for CCAs

MR. ABUEG: You have to decide how you are going to get from point A to point B, and you have to be able to take off-ramps. You need to be able to measure where you are at all times and see what progress you are making with the investment.

As a co-op, our main priority is to provide rate stability to our members. We have been innovative in the sense that we are trying not only to leverage the infrastructure that we own, including transmission, but also to move into other applications like community solar.

We have a risk management plan in place to make sure that there are checks and balances at all times on our decisions. If decisions to be made are complex, they go to a risk management committee designated by our board, so that decisions are not being made in a vacuum. We make sure that the decisions are informed decisions.

MS. BARROW: While we are on the topic of sharing best practices for energy risk management, Ranbir Sekhon, as a veteran of the power industry at Southern California Edison, what practical advice and insights would you offer CCAs that are trying to come up the learning curve?

MR. SEKHON: CCAs are the next evolution in the energy market. As they develop, they should learn from each other and also leverage the knowledge of the utilities. These risk management practices do not need to be recreated from scratch. They exist. We should be sharing knowledge about them. We all want a stable grid. We should be working together to achieve that.

Having a risk management policy, having a hierarchy, having the structure that sets limits and ensures more people share in decisions the greater the risks are good practices.

One thing people often forget is that a good training program is needed. A good training process can help ensure that everybody working in the CCA understands what the risk policy is and how it affects the decisions they will make. The risk policy should include elements around market risks, regulatory risks and manipulation.

Market manipulation is a big deal and has a lot of strict rules. People need to understand what those rules are and be trained so as not to violate them inadvertently. This also requires checks and balances.

Regulatory risks

MS. BARROW: You mention regulatory risk. One of the biggest regulatory risks CCAs face is the uncertainty around the power charge indifference adjustment. The PCIA is a charge that CCA customers have to pay when leaving bundled utility service. It gets reset every year, and CCAs do not have visibility into what the amount will be. It has gone up every year since 2010. How in developing a comprehensive risk management policy can CCAs account for the uncertainty around the PCIA?

MR. SEKHON: It is an interesting question. Being aware of the risk is a good place to start. The next step is figuring out how the risk can be mitigated. This involves using data to forecast what the rate could be. It is important to understand the policies that are being considered and the laws that govern how the process is supposed to work.

I also suggest reading the comments on file from intervenors in the PCIA proceedings before the California Public Utilities Commission. In order to understand risk, you cannot just look at it from one side. You need to look at it from multiple angles to develop mitigation measures. This may involve applying forecasting techniques to predict the possible outcomes.

There is always going to be regulatory risk. The PCIA is just one example. Another example is the resource adequacy proceeding the CPUC completed last year. The commission looked at the intermittency of wind and solar resources and decided to adopt a new mechanism for measuring the resource adequacy of these power sources. That had been a process that had been ongoing since 2012.

The result took a lot of people by surprise, but it should not have done so because there were plenty of warning signals for anyone who chose to look. (For more on California market risks, see “America’s Leading Renewables Market in Flux” in the August 2017 NewsWire and “The Changing California Electricity Market” in the June 2017 NewsWire.)

MR. ENGEL: We had a case study on the PCIA. I can share how that played out for us.

Part of our risk management policy is to do periodic stress testing that involves modelling worst-case scenarios. The PCIA is a prominent component of that model.

What assumption to make in the model played out publicly in our board meetings. A substantial part of our energy portfolio comes from locally-generated biomass power. Humboldt County is the leading forest products-producing county in California. As a result, we have a lot of waste material from local saw mills. The preferred path for disposing of that waste material is in local biomass power production.

Sourcing our power needs from local biomass projects comes with a price premium. However, our board has demonstrated a willingness to pay that price premium because of the number of local jobs that are created. We use stress testing to figure out to what extent we can afford to pay the premium instead of buy power from other sources outside our community.

Our stress testing shows our board in very clear terms what the tradeoffs are under a business-as-usual scenario and also under a worst-case PCIA scenario. It helps us make decisions everybody is comfortable with at a risk level that everybody feels is acceptable.

MR. GOLDING: The power grid is the most complex machine ever constructed. There are changing fundamentals within that system due to the spread of distributed energy, the rapid adoption of variable renewables, the rise of community choice aggregators, new regulations and the market rules and the way we allocate the costs and benefits among market participants.

All of those features are changing in real time.

Right now we have 16 CCAs, 160 staff and some very qualified CEOs coming in and building up their teams. At the same time, the CCAs have started to work together collaboratively to share resources. For example, CalCCA is a trade association that is engaged primarily in regulatory and policy discussions and monitoring for CCAs.

Together we are far greater than the sum of our individual parts. We are seeing more joint-action initiatives among CCAs, joint procurement, consideration of joint services and how we can build more expertise in-house.

We call the evolving new individual business model “CCA 2.0” and the trend toward joint action “CCA 3.0.”

MR. ABUEG: Once a risk management policy has been established, it cannot remain static. Things are changing constantly, so an organization must be nimble with its policy. An organization must stay on top of market and industry changes and make sure that its policy evolving with changes in how the market functions.

MS. BARROW: One change on the horizon is SB 350. This bill requires that, starting in 2021, at least 65% of every retail seller’s procurement in California to be under long-term contracts, meaning contracts with terms of 10 years or more.

However, developers entering into long-term power contracts with CCAs are taking a risk because CCAs lack credit ratings and do not have long operating histories. Lenders and tax equity investors in the underlying projects focus on these risks, too. Will CCAs be able to rise to the occasion and meet their obligations under SB 350?

MR. PALMERTON: There are lot of moving parts that might not make that possible. If the PCIA question is not resolved, it is hard to know what portfolio a CCA will have as customers may be reluctant to depart bundled service from the local investor-owned utility until the exit fee is settled.

The inherent problem with long-term procurement is the long-term nature of the obligation. A CCA may have a hard time predicting its electricity load over an extended period. Meeting the requirements of SB 350 is going to be very, very difficult.

Sixty-five percent of the portfolio needs to be long term. It may be too early in the life of CCAs to do that.

Creative structures

MR. SEKHON: SB 350 defines “long term” as 10 years or more. Banks might be looking for contracts that are longer than that. CCAs will need to take that into account.

The panel discussions yesterday were primarily focused on how the banks view risk associated with CCAs. In the short term, the lock box process has worked, but that may not be something that is feasible longer term. This market will require creativity, such as through aggregate procurements where small CCAs enter into joint procurements to get to a bigger deal size. Another proposal that was floated yesterday is for the developer to sell only part of his output to a CCA and to sell the rest to other creditworthy entities, possibly corporates like Google. Another idea is to combine projects into a portfolio where only part of the portfolio depends on CCA contracts. Creative structures like that will allow CCAs to do long-term deals, given the fact that they may not yet have the credit ratings they need.

MS. BARROW: So joint procurement — for example, where two or more CCAs form a new joint powers agency, a “super CCA” if you will — is one strategy the CCAs are considering using to contract for long-term resources.

The proliferation of distributed energy resources in California is another change that is not so much on the horizon as already at our doorstep. How does distributed energy change the risk equation for CCAs?

MR. GOLDING: Distributed energy and energy risk management are highly interrelated, and this creates an opportunity for joint action as a “super CCA.”

As context, customers expect to have fairly stable rates over the course of the year. In practice, this means that the CCA must predict electricity needs, hedge a certain volume through forward purchase contracts and then manage the residual market-price exposure going forward. Customer load profiles are uncertain and variable. This creates financial risk for the CCA.

Another way to think about this conceptually is that if a CCA did not have to contract for power ahead of time and instead used the wholesale market to supply all its electricity needs and just passed those costs through to customers, then there would be no financial risk for the CCA. The risk is created by the need to offer fixed rates to customers and hedge ahead of time.

How does this relate to distributed energy? Distributed energy changes the pattern of electricity usage of the customer base. It has a direct effect on forecasting and energy risk management.

California is the most rapidly expanding distributed energy market in the nation. Distributed energy can affect customer electricity usage patterns in both passive and active ways. The volume of dispatchable distributed energy resources today in California is equivalent to a large nuclear power plant. These are assets that can be controlled to varying degrees, such as battery storage, electric vehicles, micro-turbines, fuel cells and so on. The volume of non-dispatchable distributed energy resources — primarily rooftop solar — is equivalent to several large nuclear power plants.

We need to be constantly monitoring the spread of distributed energy resources of various types, assessing the energy usage patterns of our customer base and factoring this into our forecasts, electricity purchases and energy risk management strategies. It is a complex, big-data challenge.

Creating a “super CCA,” where two or more CCAs establish a joint-action agency, is particularly important here because of how complex the issues are. If CCAs can tackle the challenge together by forming a unified operational agency, then they will be in a much better position collectively to integrate distributed energy into their operations.

MS. BARROW: A common theme running through this discussion is collaboration by CCAs — for example through joint procurement — and also through CCAs leveraging the institutional knowledge and experiences of other CCAs, the three California investor-owned utilities, municipal utilities and coops.

Richard Engel, RCEA is collaborating with Pacific Gas & Electric, on several new local projects. One is a distributed energy project that will connect solar and storage on a micro-grid to supply electricity to the airport in Humboldt County. Can you tell us more?

MR. ENGEL: The project will get underway this year with funding from the EPIC program run by the California Energy Commission in partnership with the Schatz Energy Research Center at Humboldt State University. RCEA is putting in a substantial amount of the cost to the tune of about $6 million.

It is a four-year project that will put in 2 MW of wholesale solar plus another 250 KW net-metered solar and 8 MWh of energy storage for use by our regional airport. The system will also serve Coast Guard facilities that provide search and rescue along the California coast between the Oregon border and the Sonoma-Mendocino county line. The storage component will let us do energy arbitrage and better match loads with supply.

PG&E sees value in developing micro-grids throughout its service territory and establishing tariffs that ensure all parties are properly compensated. In this case, the generating and storage assets will be owned and operated by us, RCEA. There are multiple customers of the micro-grid. The Coast Guard base is one. There are another 17 electric accounts that will be served, mostly county government agencies and a few tenants of the airport.

This will be a good learning opportunity for PG&E.

RCEA and PG&E will share control of the dispatch. When in islanded mode during power outages, PG&E will have full control of the facility. Working out the details to that will be really critical. RCEA as an organization existed before we started serving our CCA function, We have a 15-year history of working with PG&E. We probably have a less adversarial relationship with our local investor-owned utility than most of the other CCAs have with theirs, and we are leveraging that positive working relationship for this project.

Offshore wind

MR. BARROW: We are running short on time and will get to audience questions in a moment, but Richard could you also tell us about the floating offshore wind project that RCEA is developing in partnership with PG&E?

MR. ENGEL: I’ll keep this short. When we did a survey called “renewable energy secure communities” several years ago, it was the first time that anybody had looked comprehensively at all the different renewable energy resources available to our county. On the resource side, we discovered the big elephant in the room was offshore wind. If you look at the National Renewable Energy Laboratory map of the wind resources in North America, at about 20 miles offshore in far northern California and southern Oregon, you encounter just about the best wind resource anywhere in North America, on or offshore.

Because of the nature of the continental shelf on the West Coast, it is not feasible to construct the type of fixed-bottom offshore wind project that has been widely done in northern Europe and that is starting to show up at Block Island and other planned projects off Rhode Island and Massachusetts. Off the West Coast, you must use floating turbines. There are not very many turbine manufacturers that have gotten very far into developing that technology. However, one of them, Principle Power, is based here in California, in Emeryville. It approached us last year with the idea of exploring the possibility of an offshore wind project.

We entered into a memorandum of understanding with it for purposes of early exploration. It quickly became clear that to move forward, we really needed to apply for an offshore lease with the federal Bureau of Ocean Energy Management. Last week, we applied for the grid interconnection study with CAISO.

Being a public agency, we felt we had to put out a public request for proposals before committing to Principle Power, so we put out an RFP in February. We got a number of impressive responses to that from developers all over the world. We had a great experience putting together a local review team for the statements of qualifications that included a broad range of stakeholders, including PG&E, ourselves, fishing interests, environmental groups and local labor unions. We see this as a great development opportunity for port revitalization and re-stimulating the local blue-collar jobs that have been on the decline with the timber industry shrinking.

For this project to be cost effective, it must be at a larger scale than what our own energy appetite would justify. We have sized the project at the 100- to 150-MW range. We will be looking for other offtakers for this project.

We are looking at probably a five-to-seven-year timeline for development of the project. From the data, it looks like there is a 50% or 55% capacity factor when you get out 20 miles or more out to sea, so it could be a great project, but we definitely need to do our due diligence. We are be eager to keep this project moving forward.


Contacts

Deanne M. Barrow

Deanne M. Barrow

Washington, DC