Capacity Market Review. Prepared for the Alberta Federation of Rural Electrification Associations. Prepared by. Dave Butler of Bema Enterprises Ltd.

Size: px
Start display at page:

Download "Capacity Market Review. Prepared for the Alberta Federation of Rural Electrification Associations. Prepared by. Dave Butler of Bema Enterprises Ltd."

Transcription

1 Capacity Market Review Prepared for the Alberta Federation of Rural Electrification Associations Prepared by Dave Butler of Bema Enterprises Ltd. With review assistance from Dan Levson and Dustin Madsen of Bema Enterprises Ltd. December 7,

2 Page intentionally left blank 2

3 Index 1 Executive summary for AFREA Purpose of a Capacity Market How a Capacity Market Functions Market Design Issues and Options possible Outcomes Related to Capacity Markets in Alberta Impact of Capacity Market on overal Power Prices How Will Capacity Payments be Paid? The Benefit of Behind-the-Fence Generation

4 1 EXECUTIVE SUMMARY FOR AFREA 1. Alberta is changing from an energy-only market to a market that recovers cost from energy and capacity payments (where capacity is the output of a generating plant at a specified time). 2. It is recommended that AFREA should monitor the development of the Capacity Market and provide input when its interests may be impacted. Here are some specific areas that need to be considered: a. Three mechanisms to allocate costs to loads are being proposed for comment by Alberta Energy and input is being sought from stakeholders on these methods. These three methods are the Coincident Peak method, the Weighted Energy method and the Total Energy method. It is recommended that AFREA study these three methods and provide input to Alberta Energy on their preference(s). The preferred method will depend on a number of factors, including AFREA s position on MicroGen and DCG. b. Advocate for capacity tariffs which will allow REAs to design rates to incent their customers to avoid capacity charges. c. Provide a mechanism to alert customers when to take measures to avoid the capacity charges and educate REA customers regarding the benefits of avoiding capacity charges and what types of actions could be used to do so. d. Consider whether using generation to serve their customers might be advantageous and under what circumstances. For example, if the FortisAlberta Option M is extended to all REAs, the savings under Option M and in reduced capacity market payments could result in economic support for behind-the-fence generation, MicroGen and DCG and possibly REA owned generation. 3. With these considerations outlined above, Bema has prepared the following report to highlight some of the more important aspects of the development of a capacity market. Beyond the recommendations above, Bema has not provided detailed specific recommendations to AFREA at this time on how it should proceed in a number of areas. Additional information would be required, and input received from AFREA s members, to understand their needs and expectations of a capacity market. 4

5 4. Finally, it is important to note that the final design of Alberta s Capacity Market is not yet known. Therefore, in these preliminary stages it is important for AFREA to provide input into the process in an effort to avoid, or at least attempt to prevent, unintended consequences for AFREA s members. 2 PURPOSE OF A CAPACITY MARKET 5. In its simplest form, capacity can be defined as the maximum output of a plant measured in MW. Independent system operators (ISO s) want to make sure they have sufficient capacity available to meet the expected peak demand in a given year. However, not all capacity has the same likelihood of being available during the peak demand. There are numerous reasons why a plant may not be able to provide most of its potential output when demand is greatest on the system. For example: a. The wind may not blow much during the coldest evening of the year; b. Plants go down for planned and unplanned maintenance; c. A hydro system may be frozen in the winter; d. The sun may not be shining to support a solar system during the coldest evening of the year; e. Imports may not be available, and plants may have export commitments; and f. Fossil plants may be derated during the hottest day of the year or may not be able to operate during the coldest day of the year In addition, capacity must be kept in reserve to manage other issues on the system besides supplying energy. For this reason, ISO s must have excess capacity available over and above the forecasted peak demand in a given year. Therefore, ISO s want to make sure that there 1 Capacity Markets Do NOT Incent New Electric Generation. [Online] American Public Power Association,

6 is sufficient probability adjusted output to meet peak demand plus a reserve margin of between 15 and 20%. 7. For our purposes, capacity is the amount of power a plant is likely to be able to provide, in MW, when it is needed most by the system. A capacity market is designed to procure this needed capacity. 8. Historically, energy and ancillary services markets tended to provide sufficient capacity because the majority of plants were fossil plants and these plants tended to provide relatively high capacity factors relative to their nameplate output. However, renewables such as wind and solar provide a much lower capacity factor relative to their nameplate output than conventional fossil plants. These renewables effectively tend to offer to sell their power to the Power Pool at $0/MWh. This means that renewable plants will provide energy before conventional ones. As the proportion of energy in the market supplied by renewables increases, this leaves less energy to be supplied by fossil plants. In addition, an increased proportion of renewables tends to suppress the average yearly power price in the energy market. In particular it reduces the number and magnitude of price spikes, which generators rely on to recover capital costs. Therefore, less fossil fuel plants will get built and the proportion of fossil fuel plants in the merit order will decrease. Please see the following resource for more information on how the addition of large amounts of renewables impact the grid With a high proportion of renewable plants in the market, plants provide proportionally less capacity than in previous years and the price in the market is suppressed by these renewables. The AESO realizes that in this situation prices in the energy markets will not be sufficient to incent developers to build the capacity required. There is a missing money problem. In addition, regulatory and market uncertainty of various sorts, related to the phasing out of fossil fuels in favor of more renewables, discourages power developers from investing their capital in conventional plants in Alberta. 2 Electricity markets are broken - can they be fixed? [Online] The Oxford Institute for Energy Studies, Malcom Keay, January

7 10. To rectify this the AESO devised a capacity market to help pay developers to build the new necessary capacity and to help pay for existing capacity. 3 HOW A CAPACITY MARKET FUNCTIONS 11. The ISO conducts an auction and accepts the cheapest set of offers which provide enough capacity to meet what is required. The ISO defines a demand curve for capacity for a specified period. It attempts to purchase sufficient capacity to meet its reserve requirements. That is, forecasted peak demand plus a reserve margin of say 15%. In order to keep consumers from paying what might be considered excessive prices for this capacity the ISO sets a ceiling price for what it is willing to pay. The ISO generally only wants to pay for what may be required to compensate a developer to build a plant. What is required may be the cost to build a plant less profit the developer is likely to recover in the energy and ancillary service markets. The remainder or missing money is called the Net CONE (Cost of New Energy). 12. The ISO estimates the CONE for some form of conventional generation with a high ratio of capacity to nameplate output such as a natural gas combined cycle (NGCC) or simple cycle Peaker. The ISO then estimates what contribution margin this plant is likely to make in the energy and ancillary services market to define the Net CONE. In Figure 1 below, Net CONE is about $340/MW-d. Point b indicates that the ISO is willing to pay this price for sufficient capacity to meet peak demand plus 1% more than its installed reserve margin (IRM) requirement. If people are willing to offer to sell their capacity for less than the Net CONE, then the ISO may be willing to take more of it now for use later. Therefore, Point c shows a price of about 20% of Net CONE or $70/MW-d for IRM +5%. Conversely the ISO may have to offer a higher price than Net CONE to attract investment. Point a has a price of 1.5 x Net CONE or about $510/MW-d. 13. The ISO specifies what types of plants and other arrangements quality to submit offers to sell capacity into an auction process. These other arrangements might include energy storage, demand response, imports or renewables supported or not supported by a PPA. The ISO also specifies the capacity associated with the nameplate output for each type of plant. Fossil plants may have a capacity factor of between 87% and 93%. Wind plants may have a ratio of between 5% and 30% of capacity to nameplate output. Hydro and solar plants in 7

8 Alberta may have no capacity attributes at all if peak demand occurs in the winter. 3 Qualified entities submit offers to sell capacity. An offer specifies a price and a capacity quantity in MW. All existing capacity would be required to offer its full capacity. In order to make an offer an entity will need to forecast costs and returns in the highly uncertain energy, ancillary and capacity markets. 14. The AESO will order the offers from least cost to most expensive to create a supply curve. The clearing price is where the supply curve meets the demand curve as shown in Figure 1. All offers less than the clearing price are accepted and would receive the clearing price for a specified term a few years in the future. This allows time for developers to build new generation. All offers with prices greater than the clearing price are not accepted and the entities who made these offers will not receive any capacity payments for their offers. 15. Figure 1 shows a significant amount of capacity offered in at $0/MW-d. These are likely plants which are already built. They likely don t want to offer a higher price because if they do there is a chance they may not receive any payments at all if their offer is not accepted. These plant owners are called price takers. 3 Capacity Payments in Restructured Markets under Low and HIgh Pentration Levels of Renewable Energy. [Online] National Renewable Energy Laboratory, Thomas Jenkin, February Paying Peanuts: Will the British Capacity Market Deliver Security of Supply? [Online] NERA Economic Consulting, October Pan-Canadian Wind Integration Study. Canadian Wind Energy Association. [Online] GE Energy Consulting, October Intregrated Resourse Plan. Board, Nova Scotia Utility and Review. : s.n.,

9 Figure 1: Illustrations of Capacity Market Supply and Demand Curves 4 MARKET DESIGN ISSUES AND OPTIONS 16. There is much controversy regarding whether existing plants should receive capacity payments or to what extent they should receive capacity payments. There will be contention regarding the amount of capacity attributed to the nameplate output of various plant types. There is an issue associated with what type of plant should be used to derive the CONE. There are also issues associated with the assumptions related to deriving the cost of the power plant used to derive the CONE. Likewise, the revenue assumptions related to the energy and ancillary services market used to derive the Net CONE, will be uncertain. There is also the issue of whether historic or forecasted values should be used to derive the Net CONE. The shape of the demand curve and the values which underlie it are also of concern. 17. Some markets allow entities to procure capacity via bilateral arrangements. Some markets allow energy storage to supply capacity. Some markets allow renewables to provide capacity. Some markets allow entities receiving a PPA to supply capacity. Whether imports 9

10 or demand response should be able to participate in the market is also an issue. There is also a concern about the length of the term of the capacity payment. This term ranges from one to fifteen years in other markets. The frequency of capacity auctions is also a consideration. There will be a concern as to whether there will be sufficient time between the auction and when any new plants must be built. There are also several ways to conduct the auction and allow for the submission of offers. The allocation of costs to loads can be accomplished in several ways. Three mechanisms to allocate costs to loads are being proposed for comment by Alberta Energy and input is being sought from stakeholders on these methods. These three methods are the Coincident Peak method, the Weighted Energy method and the Total Energy method. 18. It is recommended that AFREA study these three methods and provide input to Alberta Energy on their preference(s). The preferred method will depend on a number of factors, including AFREA s position on MicroGen and DCG. An in-depth review of these options is beyond the scope of this report. 19. Several auctions have included various rules to attempt to reduce market manipulation. It is important that those determining policy and legislation, along with the AESO, stabilize the rules and operation of the energy and ancillary services markets to preserve the assumptions used by both the AESO to estimate the CONE and developers to determine their offer prices. 20. In addition, there is concern about how to make sure plants are actually available during the periods of peak demand in a year and what types of penalties should apply if they are not available. Please see the following sources for more information in the nature of capacity market designs. 4 4 Capacity Payments in Restructured Markets under Low and HIgh Penetration Levels of Renewable Energy. [Online] National Renewable Energy Laboratory, Thomas Jenkin, February London Economics International LLC. Capacity Market Review, Stakeholder Luncheaon #2, Prepared for: IPPSA Capacity Market Review, Prepared for IPPSA

11 5 POSSIBLE OUTCOMES RELATED TO CAPACITY MARKETS IN ALBERTA 21. One of the possible outcomes is that a capacity market may not be sufficient to mitigate the market and regulatory uncertainties in Alberta and needed capacity may not be built. Recall that in the future the total compensation for a developer will be predicated on returns from the energy, ancillary and capacity markets. There are numerous things an ISO or policy maker can do to these markets during the period of time required to recover the full costs of a plant. There have been instances where changes made to the energy market rules before a plant was financed caused the developer to ultimately back away from an agreement to provide capacity. The 1.9 GW Trafford power plant in Manchester was not built even though its offer was accepted. (9) A 900 MW plant in the US was delayed as well In addition, it appears from the literature that capacity markets keep being tweaked or redesigned. In addition, the literature highlights issues to avoid when designing capacity markets but the wide variation in market designs suggests that a common set of characteristics to define the best approach has not been settled. Therefore, developers may offer higher prices to compensate for these risks or may not offer at all. 23. Aside from all this are the regulatory risks associated with the transition from fossil fuels to renewables. Changes to the carbon tax and the pace of the addition of renewable energy compared to load growth and other forms of energy provision will change contribution markets in the energy market. In addition, developers are greatly concerned that their natural gas fired generation fleet may become a stranded asset, like their coal assets, either by government legislation, by manipulation of the incentive structures for renewables or the rules in the energy and capacity market. 5 Capacity Markets Do NOT Incent New Electric Generation. [Online] American Public Power Association, Capacity Payments in Restructured Markets under Low and HIgh Pentration Levels of Renewable Energy. [Online] National Renewable Energy Laboratory, Thomas Jenkin, February

12 24. Governments claim that capacity markets provide more revenue certainty. However, a one to three-year capacity contract providing only a portion of the revenue required to support a plant over its twenty-year life may not be sufficient to develop and finance a plant. Several public studies underscore the notion that the prices paid in capacity markets are highly variable. 6 Figure 2 shows how variable capacity prices have been in capacity markets in the US. Figure 2: Capacity Payments in Various US Markets (3) 6 Capacity Payments in Restructured Markets under Low and HIgh Pentration Levels of Renewable Energy. [Online] National Renewable Energy Laboratory, Thomas Jenkin, February London Economics International LLC. Capacity Market Review, Stakeholder Luncheaon #2, Prepared for: IPPSA Capacity Markets Demystified. [Online] VENTYX, Mark Griffith,

13 25. Capacity markets have tended to not provide enough revenue to support a new entry. 7 Figure 3 shows that for the PJM capacity market, capacity payments have tended to be less than that required to pay for a new plant. Figure 3: Fraction of Required Capital Recovery Provided by PJM Capacity Market (3) 26. It should be noted the Government knows how to provide revenue certainty for renewables. That is accomplished by signing twenty-year contracts. The unwillingness of governments to provide long term PPA s for plants which keep the lights on is not comforting. In 2014 less than 5% of new capacity additions in the US were contracted to capacity markets and most of the rest were secured by some type of long term financial arrangement. 8 7 Capacity Payments in Restructured Markets under Low and HIgh Pentration Levels of Renewable Energy. [Online] National Renewable Energy Laboratory, Thomas Jenkin, February London Economics International LLC. Capacity Market Review, Stakeholder Luncheaon #2, Prepared for: IPPSA Capacity Markets Do NOT Incent New Electric Generation. [Online] American Public Power Association,

14 27. Alberta is a relatively small market. Most other capacity markets have been designed to manage capacity additions required to support load growth. However, in Alberta if 50% or more of the fleet capacity is destined to retire by about once the plants converted from coal to gas retire and coal plants retire, there is a concern that the capacity market may not be able incent both the development of new plants to support load growth and to develop plants to replace 50% of capacity that has been retired. 28. In addition, if the contract term is for one or two years, the load growth associated with this period may be too small to incent the development of large efficient NGCC plants. Please see the following reports for more information on other issues IMPACT OF CAPACITY MARKET ON OVERAL POWER PRICES 29. Since the market design has not been completed it is hard to forecast the impact on overall prices. One of the more recent developments in the Alberta market is the announcement of more than 2,500 MW of coal plants to be converted to gas. The cost to convert a plant from coal to gas is likely to be significantly less on a $/MW basis than building new gas fired capacity. This allows these plants to offer relatively low offer prices in their first capacity market auction. In some years, they may receive revenues in the capacity market sufficient to incent the development of new natural gas fired generation. This will provide additional profit to these plants for many more years to come. Therefore, these converted plants may suppress the price of power in the capacity markets since less new capacity will be required between now and However, the marginal cost of production from a plant converted from coal to gas will increase. The marginal cost of power from a coal to gas plant will be roughly 10 GJ/MWh 11 times the gas price and this is much higher than new gas fired generation at say 7 GJ/MWh 9 Based on Alberta provincial requirements to shut-down the coal units by 2030 and Federal Government emissions requirements on plants converted from coal to gas. 10 London Economics International LLC. Capacity Market Review, Stakeholder Luncheaon #2, Prepared for: IPPSA Capacity Market Review, Prepared for IPPSA Bowring, Joseph. Capacity Markets in PJM. s.l. : Economics of Energy & Enviroment Policy, Vol 2, No. 2, Based on a reasonable approximation of heat rates for Alberta coal fleet. 14

15 times the gas price, which might otherwise have been built. In addition, the carbon tax on coal to gas plants will be greater than on new gas fired generation. For this reason, the price in the energy market is likely to increase. These higher energy prices may however suppress prices in the capacity market. 31. Initially the Alberta government had hoped that much of the reduction in coal capacity before 2030 would be replaced by renewables. However, much of this capacity may not actually go away until about 2035 if it is converted from coal to gas. If these converted plants operate rather than new gas fired generation, the price of power may go up in the energy market. This may however, be offset to some extent because less money may need to be paid to renewables under their contracts for differences due to higher energy prices. 32. Coal to gas plants will need to purchase a significant amount of gas which may be difficult to forecast the day before. Recall coal to gas plants will have a higher marginal cost than most conventional gas fired generation and will therefore dispatch on and off more often and may also need to ramp up and down more often. The ability of the gas supply system to manage this may be constrained. For this reason, some developers may need to procure gas for the day ahead and may need to offer at $0/MWh to consume all the gas. This may suppress energy market prices, which may drive up capacity market prices. 33. If a capacity market arranges for a higher reserve margin than one would otherwise expect without a capacity market, this will result in more capacity being built. This means that there will be more competition to derive revenue in the energy market during peak periods. This will have the effect of reducing peak prices and the average power price in a given year London Economics has provided the IPPSA with a presentation on capacity markets. That report on page 31 indicates that a capacity market may in fact lead to slightly lower total costs for power than for an energy only market. 13 Recall that the plan is to make sure that the sum of energy, ancillary and capacity markets revenue is enough to just pay for a new 12 Capacity Markets Do NOT Incent New Electric Generation. [Online] American Public Power Association, London Economics International LLC. Capacity Market Review, Stakeholder Luncheaon #2, Prepared for: IPPSA

16 conventional power plant. In a well-functioning energy only market, competitive forces would likely drive prices to just pay for new conventional plants as well. Therefore, there should be no difference in costs between an energy-only market and a capacity and energy market (including ancillary services in both markets). Clearly, the Alberta energy market will no longer be a well-functioning competitive market as a capacity payment will now be required to support new generation. Furthermore, ratepayers will also be required to pay for out-of-market renewable power plant generation costs through the renewable auction processes, which is outside of the capacity market. 7 HOW WILL CAPACITY PAYMENTS BE PAID? 35. All load participating entities in the Wholesale market will be required to purchase capacity. The AESO already has a methodology for charging customers for the fixed cost of the transmission system through demand charges. The final methodology being proposed by the AESO to pay for capacity costs is currently unknown. Demand charges are used to allocate the fixed costs of the transmission system to customers based on their peak consumption. Loads are required to pay for their fair share of the system they use. In the capacity market loads are required to pay for their share of the capacity to serve peak demand. The allocation methodology for serving peak demand may be different than for transmission charges because peak demand is so time sensitive in the hourly energy market. In addition, if capacity payments are based on forecasted or historic demand values, this may make it difficult for a given customer to reduce costs particularly if the market doesn t pass on these charges in a way that incents consumers to change behavior to avoid them. 36. It is assumed going forward that the energy market cannot supply prices high enough to incent the development of new conventional generation to provide capacity. Therefore, it is difficult to contrast an energy-only market with fundamental flaws 14 with a new capacity and energy market. 14 Inclusion of out-of-market renewables supported with subsidies, in combination with a significant overhang of generation supply under the existing energy-only market and large amounts of PPA generation under control of the Balancing Pool has led to serious problems with the energy-only market. 16

17 37. If a load has a very low load factor, then it may end up paying more for capacity and energy than it might have paid in an energy only market. Likewise, a load with a high load factor might end up paying less in an energy only market (since a large of amount of its energy is consumed at night) than it will pay with a capacity market since its capacity payment may be relatively high. A load which can shift energy out of high demand periods might end up paying very little capacity payments and might come out ahead. Currently, during peak periods, curtailing 1 MW for an hour may save $1,000. If the capacity charge is $8/kWmonth, curtailing 1 MW during peak demand may save $96, Therefore, the ability to predict peak demand might be helpful in an effort to avoid paying capacity payments and correspondingly high energy prices. Further systems and rates designed to help one avoid consumption during the peak demand might be helpful as well. It all depends on the way the costs for capacity are allocated to load serving entities and then to their customers. 39. Therefore, is it recommended that AFREA: a. Advocate for capacity tariffs which will allow them to design rates to incent their customers to avoid capacity charges; b. Provide a mechanism to alert customers when to take measures to avoid the capacity charges; and c. Educate their customers regarding the benefits of avoiding capacity charges and what types of actions could be used to do so. 8 THE BENEFIT OF BEHIND-THE-FENCE GENERATION 40. It might be in the interest of load serving entities like AFREA to develop their own capacity, behind the fence, to avoid both the consumer transmission charge and energy and capacity payments. Recall the capacity payment is supposed to be roughly the cost of an NGCC (energy revenue fuel and O&M costs). 15 Calculated as $8/kW times 12 months times $

18 41. Let s assume revenue is $50/MWh in energy market. a. Fuel is $20/MWh for NGCC. b. O&M is $5/MWh. 42. This nets to $25/MWh. If the capital cost and fixed O&M costs of a new NGCC is $50/MWh, then the capacity payment would be effectively $25/MWh. 43. Therefore, consumers pay $50/MWh in energy market and $25/MWh in capacity market or $75/MWh (The cost of a new NGCC). If the consumer transmission charge is $45/MWh, then the total cost is $120/MWh. The CONE is based on the expected capacity factor when the plant runs. It is not likely to run all the time. However, a behind-the-fence generator could run all the time. If it did, then its capital cost could be spread over more hours than assumed in the CONE. That is the cost of a new plant even if it is relatively small, is likely to cost less than $120/MWh if base-loaded. If the plant uses some form of biofuel, it could avoid all or part of the carbon tax as well. This plant may qualify to submit offers into the Emission Reduction Alberta process or the AESO s renewable power calls. In addition, there may be funding for energy efficiency or efficient communities available. 44. Therefore, it is recommended that the AFREA consider whether using generation to serve their customers might be advantageous. 18