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Understanding markets

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​by Randy Wilkerson

 Note: There has been a lot of recent discussion about “markets,” especially since Upper Great Plains announced its intention to join the Southwest Power Pool. This story provides a comprehensive look at what markets are, how they operate and what they mean to Western.

Electricity markets, especially in the West, continue to evolve, and are changing the face of the electric utility industry. The changes represent a significant departure from the way business has been conducted for the past century. A variety of different market designs and approaches have been proposed, developed and adopted.

Western hosted a meeting Jan. 24 where almost 90 preference power customers came together at the Desert Southwest Regional Office in Phoenix, Ariz., to share information on the status of these various market activities. Administrator Mark Gabriel said, “Western is closely monitoring and evaluating several industry initiatives that could have a significant impact on the way participants operate or perform marketing activities across the western interconnected power system. It is extremely important that we work closely together on these topics.”

Energy Management and Marketing Office Manager Jeff Ackerman, who works for the Colorado River Storage Project Management Center, opened the session with an overview of Western’s involvement in market issues. Ackerman noted, “Western staff has been working on and evaluating Western Interconnection energy imbalance market issues as far back as early 2011. The interconnection was looking for ways to allow the efficient integration of variable energy resources onto the power grid.”

Markets in West organize, seek solutions

An early energy imbalance market proposal was a west-wide EIM initiative studied by the Western Electricity Coordinating Council and later, in more detail, by the National Renewable Energy Laboratory under the auspices of the Public Utility Commissioners of the Western Governors Association. Eventually, the west-wide approach evolved into several regional efforts, each involving a number of partners.

In the Pacific Northwest, the Northwest Power Pool has been studying the issue of variable energy integration, while in the Southwest, the Southwest Variable Energy Resource Initiative has also been looking at problems and potential solutions associated with integrating variable resources into the regional grid. Meanwhile in 2013, the California Independent System Operator and PacifiCorp announced they will operate a joint EIM together scheduled to begin October 2014.

Ackerman noted that Western has many of the same interests as others in the industry and is experiencing the same issues with integrating variable energy resources in some of its regions. For example, in the Western Area Colorado Missouri Balancing Authority there is presently 210 megawatts of installed wind generation with expectations of an additional 300-600 MW of wind to be connected in the near future. With 75 MW of hydropower capacity set aside to balance variability, the BA is quickly reaching the point where additional flexible resources may need to be acquired to meet our balancing requirement obligations under North American Electric Reliability Corporation criteria. He added, “Western must consider all reasonable solutions to resolve these concerns.”

Exploring market involvement options

When considering any market involvement, Western has some unique factors that may affect its participation. Each Western balancing authority operates under a different Power Marketing plan and project authorizations. Western’s responsibility for managing end-use load within its BAs is not the same as the responsibilities of other BAs, such as those managed by investor-owned utilities. Western’s hydro generation resources are generally committed to federal project-use and preference power customers. Project repayment schedules require that all costs be borne by those taking services from Western, including transmission and firm electric service customers.

Ackerman summed up Western’s approach saying, “Since Western must pass through any costs that it may incur, in general, the benefits received by the end user must exceed the costs of the product or service being received or provided. In any initiative Western must be sensitive to cost considerations and ensure a beneficiary-pays policy. As we move forward and analyze potential new market initiatives that the industry may be considering, we plan to use these criteria as a starting point.”

UGP presents business case

At the Jan. 24 meeting Upper Great Plains Regional Manager Bob Harris and UGP Operations Manager Lloyd Linke presented the background and business case for Western’s decision to pursue membership in the Southwest Power Pool for UGP. [Check out  “UGP pursues RTO membership” news release]

They highlighted the unique nature of the issues created by the growth of markets around the UGP footprint and long history of studying various alternatives to address those issues. Harris pointed out that the Midcontinent System Operator has grown up to UGP’s east, and SPP has developed to the south. There is limited access to the west due to fully subscribed direct-current ties to the Western Interconnection. Finally, there is limited access to Canadian markets to the north.

Linke noted, “The number of potential trading partners has decreased significantly, from 55 partners in 2002 to 5 potential partners today. Trading partners are critical because hydropower varies with water conditions; there may be excess generation to sell in wet years, and dry years create the need to purchase additional power to meet contractual obligations. As more trading partners join organized markets, Western has fewer options. Transmission congestion and congestion charges make it difficult and expensive to deliver power into a market or purchase power from a market participant without being a member.”

Harris added, “Future market access is the predominant issue.”

Western studied three alternative operations options: “Join MISO,” “Join SPP” and a stand-alone option. Linke said, “Regardless of the RTO decision, future UGP operations and purchased power and surplus sales strategies will have to change.” A detailed analysis of the costs and benefits of each of the options identified the Join SPP option as having a significant cost/benefit advantage over either of the other options, with a total benefit to Western of $11.5 million the first year and $14.2 million in future years.

Western also conducted a multicriteria decision analysis on each option to quantify the risk associated with each. In addition to being the most beneficial financially, the Join SPP option also presented the lowest risk.

Based on these analyses and significant public and customer involvement, Gabriel announced the decision for UGP to pursue membership in SPP Jan. 9. Western and SPP are currently negotiating the specific terms of the membership agreement with the target of becoming a full member of SPP in October 2015. Harris emphasized this decision was based solely on the unique situation of UGP and the business case established by the analyses. Western will approach any other market decisions on a region-by-region and case-by-case basis.

CAISO/PacifiCorp EIM not good fit

Closing out the public portion of the meeting, Thomas Veselka of Argonne National Laboratory presented the results of Argonne’s analysis of the potential impacts of the CAISO/PacifiCorp EIM. Western was concerned that a number of entities might join and Western could become islanded by the CAISO/PacifiCorp EIM. Western contracted with ANL to evaluate what effects that would have on Western’s customers and Western’s ability to conduct business.

The study was designed to provide preliminary insights into future operations and examined four business cases:

  • Western continues to operate as it does now, and surrounding BAs join the EIM with current levels of VERs.

  • Western continues to operate as it does now, and surrounding BAs join the EIM with higher levels of VERs.

  • Western BAs join the EIM with current levels of VERs.

  • Western BAs join the EIM with higher levels of VERs.

The analysis concluded Western’s participation would most likely be very limited because federal resources are contractually committed to customers, and water delivery obligations and environmental operating criteria further limit Western’s ability to dispatch resources in response to market price signals.

The study also found that Western’s participation would most likely be expensive due to the high startup costs, participation fees and the need for additional staff. The study also noted that Western’s participation would most likely increase risks by subjecting Western to potentially high prices and generation imbalance costs, among other factors. The study concluded that although the CAISO/PacifiCorp EIM may be beneficial for some entities within Western’s BAs, the CAISO/PacifiCorp

EIM design is not well-suited for Western because of its regulatory and operational constraints. The study recommended that Western continue to monitor the activities of the CAISO/PacifiCorp EIM and market-related initiatives within the Western Interconnection to ensure that its business practices would be able to adapt to whatever changes might occur.

 The following is an overview of markets within Western's territory that attended the Jan. 24 meeting: 
  Southwest Variable Energy Resource Initiative
Dave Slick, Manager of Power Contracts and Energy Initiatives for Salt River Project, gave an update on activities in the southwestern U.S. SVERI is a consortium of utilities in the Southwest that began discussing variable energy resources in 2012. Their mission is to evaluate the likely penetration, locations and operating characteristics of VERs over the next 20 years and explore tools that may facilitate VER integration and provide benefits to customers. At this stage, the group is primarily focused on data collection.
Slick pointed out issues in the Southwest are not necessarily the same as in other regions of the country. For example, the Southwest is not facing the volume of VERs that California must manage, nor does it have the combination of hydropower and wind resource size as in the Pacific Northwest. Also, the Southwest has not seen the same level of wind development as in other regions. Collectively, SVERI participants’ plans include gas-fired generating capability in the long term that is sufficient to meet the ramp-rate requirements presented by projected VERs. 
  CAISO/PacifiCorp
Don Fuller, California Independent System Operator’s Director of Strategic Alliances, provided details on the new CAISO/PacifiCorp energy imbalance market. CAISO initially proposed an EIM structure in March 2012 to assist in integration of renewables and enhanced reliability through the sharing of diverse resources across a larger geographical area. PacifiCorp agreed to join the EIM in April 2013, and NV Energy has announced its plan to join the next time new participants are allowed entry. CAISO is in the process of filing the appropriate tariffs with the Federal Energy Regulatory Commission and finalizing the EIM’s governance structure. The market is expected to go live in fall 2014.
Key features of the CAISO/PacifiCorp EIM include a scalable approach that uses CAISO’s existing market structure and can add other participants at any time. Based on its existing market design, the EIM will dispatch least-cost resources automatically every five minutes to resolve imbalances. The market uses a number of rules to ensure that participants have sufficient resources available to meet their obligations. CAISO and PacifiCorp expect to save a minimum of $10.9 million and $10.5 million, respectively, each year.
Southwest Power Pool
Carl Monroe, Executive Vice President and Chief Operating Officer of the Southwest Power Pool, presented features of the current markets SPP operates and described SPP’s plans for future market development. SPP became a Federal Energy Regulatory Commission-approved regional transmission organization in 2004 and now has 75 members including investor-owned utilities, public power and independent generation and transmission entities. 
As an RTO, SPP currently operates a transmission service market where participants buy and sell use of regional transmission lines that are owned by different parties. SPP also operates an energy imbalance service where participants buy and sell wholesale electricity in real time. The market uses the least expensive energy from regional resources to serve demand first. Sometimes it is less expensive for a participant to purchase power from another provider than to generate its own power. SPP monitors resource/load balance to ensure system reliability.
SPP has just implemented what it calls the Integrated Marketplace, combining its existing markets with a day-ahead market where SPP determines what generating units should run the next day for maximum cost effectiveness. The Integrated Marketplace also adds an operating reserves market to buy and sell reserve energy to meet emergency needs and regulate instantaneous load and generation changes.
SPP has proposed a scalable version of its Integrated Marketplace that it believes could be used by utilities throughout the Western Interconnection regardless of membership in the SPP RTO.
 Northwest Power Pool
Rachel Dibble, Bonneville Power Administration’s representative on the Northwest Power Pool Member’s Market Assessment and Coordination Initiative, described NWPP’s approach as they address the issues of variable generation and markets. Phase 1 of NWPP’s effort attempted to assess the costs and benefits of developing an energy imbalance market in the Northwest. Through that study they found that no single solution addressed the entire problem. They determined the region needed a comprehensive framework that was built on a foundation of reliability and local control, addressed capacity sufficiency and captured cost savings through diversity and economic dispatch of resources.
Phase 2 refined cost estimates and developed an implementation plan that maximizes benefits, with or without a full-blown EIM. The approach is composed of a number of steps that could be implemented individually or together. Each step would add value whether or not it was combined with other steps.

Phase 3 begins the implementation of the plan developed in Phase 2 and will focus on seven projects that will enhance reliability in the region and increase coordination, such as regional flow forecasting and data sharing. It also includes identifying the tasks required to take the next steps toward improving operational integrity in Phase 4. Phase 4 implements resource sufficiency solutions in 2015 and 2016 to ensure equitable treatment in the market for capacity and resource sufficiency. Finally, Phase 5 would deliver automated regional efficiencies to members through security constrained economic dispatch with a central operator, essentially a complete EIM.

The plan can be terminated at any point along the way, and members will still gain value from those steps that have been implemented up to that point, whether or not they develop a complete EIM.

 

 

 Why markets matter

​​Electricity is the only commodity where the demand is created, order placed and product manufactured, delivered and consumed, all in an instant. Since current technology imposes limitations on the ability of energy service providers to store significant amounts of energy, whatever generation is available must be used in real-time to constantly balance the demand. Whenever demand or generation varies, system operators must manipulate multiple generation sources to keep the system balanced and prevent outages.

Each balancing authority operator is responsible for maintaining that balance within their area. Operators schedule generation a day in advance based on estimates of resource availability. Then, they adjust those schedules every hour in real time. However, actual generation often does not match what was scheduled, forcing operators to either acquire or curtail other resources to keep the system in balance. In the traditional balancing authority model, the operator can only work with resources located within the balancing authority. The operator must maintain sufficient generation in reserve at all times (or capacity) to be able to balance the variations in load and generation.

Variable energy resources, such as wind and solar power, add even more complexity to the system. Because wind speeds vary and clouds can obscure the sun at any time, their generation can vary greatly within a single day, over a few hours, and often within a single hour. Timing of the generation is a concern as well. For example, the solar peak and peak electrical demand do not necessarily align.

Some see energy imbalance markets as a promising solution to the volatility of variable energy resources. By including a larger geographic area within the EIM, more opportunities for resource diversity arise, as it is more likely that the sun will be shining or the wind blowing somewhere in the footprint of the EIM. Coupled with shortened scheduling and dispatch time lines, many advocates believe that EIMs can optimize operations and result in reduced costs for energy consumers. Also, by including more generating resources in the market footprint, each entity might be able to reduce the amount of generation they have committed to balancing load and generation.

In a process called security-constrained economic dispatch, generators bid the amount and price of generation they have available and load-serving entities bid the amount of generation they require into the market. Through complex software, the market sets the price of electricity for a specified time period by accepting generation bids beginning with the lowest-priced bid up to the last bid needed to supply the power needed for that time period. In the case of the CAISO/PacifiCorp EIM, the real-time dispatch period is five minutes. All sellers then receive the price of the final bid.

Page Last Updated: 7/14/2015 6:56 AM