Loading...
6.3. ERMUSR 06-14-2005Elk River Municipal 13069 Orono Parkway Elk River, MN 55330 June 8, 2005 To: Elk River Municipal Utilities Commission Jerry Takle John Dietz Jim Tralle From: Bryan Adams Subject: Electric Resource Planning phone: 763.441.2020 Fax: 763.441.8099 Your staff has had a number of discussions recently with Connexus and Great River Energy concerning electric generation resource planning. How Great River Energy as well as most of the electric industry plans for generation capacity is somewhat disturbing. In the organization I was previously associated with, we planned from a generation perspective for our peak day plus the 15% reserve per MAPP guidelines of which 5% of these reserves must be spinning or on line. For example, if your projected peak load is 2000 MW, you must control or have under contract and deliverable, 2300 MW of capacity. The 15% reserve is to ensure the utilities are doing their planning and can meet their projected loads without gaming the other utilities. If your current load is, for example 1000 MW, you must have 1050 MW on line and spinning. The extra 5% is to ensure if a power plant trips off line due to electrical or mechanical failure, there is enough spinning capacity on line to pick up the load thus preventing a major blackout. In today's environment as generations and transmission capacity becomes tight; many of the utilities have been hedging on the 15% reserves due to the cost and desire not to build more power plants. Utilities are also hedging on the peak load. Instead of planning for the peak load, Great River Energy plans for the 90% confidence level not 100% of the possible load. Statistically, they are saying they cannot satisfy the load one day in ten years and either the 15% reserves or market purchases will allow them to satisfy 100% of their load. Due to the way the industry does URGE tests, 15% reserve is more like 5%. 7'he purchased power marked has also tightened up because of shortage of excess generation with limited transmission capacity. In Great River Energy's case, 90% confidence level at time of peak (7:00 p.m. +) is 88°F and 65 MW per degree Fahrenheit. We have also had mild summers with no long sustained hot spells for a number of years. ities This planning process sounds like a receipt for disaster to me. The industry is now saying it is acceptable to have occasional blackouts. The major blackouts in the east a couple of years ago produced a lot of talking but little if any physical changes on how we operate. Attached is an interesting article titled, "Capacity Markets: A Bridge to Recovery?" that is worth your time reading. Capacity Markets: A Bridge to Recovery? A review of the ongoing evolution of market design. BY CRAIG HART ICAP, ICAP, UCAP, NoCAP. Some markets have them, some don't. Where they do exist, no two are equal. California was built without one, as were the markets of Australia and New Zealand. Northeastern U.S. markets all have them, albeit in slightly different variations. MISO will start one of the biggest energy markets in the world without one. PJM, long considered the model market, is debating a major over- haul to its current scheme. Others are considering such changes as well. As the experimentation with whole- sale energy market deregulation contin- ues, anevolutionary trend in capacity market design is becoming apparent in the United States. Most critics now support the conclusion that en re~gy only schemes in price-capped markets do not provide sufficient revenues to rn uce new generation and keep sys- tem-critical, high-cost generation resources in the market. As such, it is likely only a matter of time before energy on y mar ets are extinct. ut, w i e it appears at capacity markets are here to stay, there is little consensus regarding the best design. Markets in the United States are in a state of flux, with debate raging over many different capacity market pricing schemes. The pool-wide, single-price capacity market model utilized by PJM and others now appears too simplistic. New designs are calling for ever-more complicated structures aimed at fine-tuning the location, the timing, and the type of generation resources that capacity markets induce. While the winning recipe has yet to be selected, it is likely that participants in certain markets will witness signifi- cantchanges. In certain load pockets, generators could see a meaningful increase in gross margins if a pricing scheme that compensates generators based on location is adopted. Flexible units may receive an additional bump if changes being considered in PJM are adopted. But, these shifts are likely only to persist in the shoe to medium term. While providing a much needed bridge to market recovery For some, if the mar- kets function properly, price differentials should dissipate over time and bring long-term pricing back to the mean. Background Capacity markets are designed to ensure resource adequary. While various defi- nitions exist, resource adequacy gener- ally refers to the sufficiency of generation resources to meet the peak energy needs and maintain the stability of an electric system. In a traditional, regulated utility world, generation plants are added after resource planners determine the amount of new capacity that will be needed over the coming years to meet demand. While they are determining the actual amount of total installed capacity necessary to ensure resource adequary, resource planners also attempt to optimize the type of capacity that is built in terms of fuel type, technology, and market segment (i. e., baseload, intermediate and peaking). In this way, the best generation mix necessary to meet peak demand is determined through a central planning process. In a deregulated world, the decision to build new capacity is made by indi- vidual market participants instead of through a central planning process. The underlying question becomes how to design a market to properly incen- tivize profit-maximizing participants to develop enough generation capacity to ensure resource adequacy As the theory goes, the answer is that the market must provide adequate compensation so that a new entrant is able to earn rev- enues that are high enough to cover costs and earn a fair return. 74vo Basic Models There are essentially two schools of thought when it comes to designing markets that provide adequate revenues to generators: energy only (referred to as "NoCAP") and energy-plus- capacirymarkets.' Many have followed the NoCAP route. In the United States, California, ERCOT, and MISO started without an explicit capacity market. Australia and New Zealand, as well as the markets in Ontario, Alberta and Scandinavia (NORDPOOL) all have functioned without a formal capacity support mechanism. The general belief (hope) in these NoCAP markets is that sufFicient revenues will be earned from the energy markets (plus other ancillary services where applicable) alone to induce an adequate amount of new generation resources. The idea is that the inherent volatility of the energy markets will deliver enough high-priced hours dur- ingsummer- orwinter-peaking periods 24 Pueuc Ununes FoprNiexnr MAV 2005 www.fortnightly.com that a new generator would be fully compensated and earn a fair return. The logic for marginal, system-critical resources is the same: The few high- priced hours when these units are dis- patchedwill provide enough compensa- tion to cover going-forward costs and keep the units from retiring. The other option, of course, is to couple a capacity mazket with the energy market. PJM, ISO New Eng- land, the New York ISO (NY--ISO), and others have used'vaziants of this theme fairly successfully. Energy-plus-capacity markets generally function by compen- sating generators based on total installed, or available, capaciryZ Genera- tors receive a payment that supplements revenues earned in the other markets. The idea is that total revenues should be sufficient to cover going-forward costs at a level that is compazable to what generators eazn from hourly dis- patch in an energy-only market. Bumps fn the Road As deregulated markets collect a histori- cal record that includes the experience of a full boom-bust business rycle, sev- eral shortcomings in existing markets are becoming apparent. For NoCAP markets, it is the institution of price caps that is arguably the most notable contributor to their inability to provide a stable and sufficient revenue stream to generators. Others with capacity maz- kets in place are finding that simply adding generic capacity resources some- wherewithin the market footprint may not be the optimal path to ensuring resource adequacy What started as sim- ply aquestion of how much, has re- cently matured to a question of what, where, and when. Price Caps. In U.S. energy markets, extreme price volatility is unpalatable to the general public. As a reaction to high prices in the Midwest in 1998, PJM in 1999, and California in 2000, many www.fortnightly.com markets created price ceilings (or price caps) to protect the public from extreme energy price volatility. But the problem with this type of protection is that it sac- rifices the prospect oflong-term market stability for the sake ofavoiding adam- agingsummer newspaper headline. This is especially true in NoCAP markets. Marginal generators in NoCAP markets are dependent on the few days when the intrinsically volatile energy mazkets deliver high-priced hours. The ability to capture revenues during these high jpriced times gives mazginal generators the ability to cap- ture a sttfficient level of revenues. But, with price caps in place, generators lose this revenue which tends to dampen the new build signal and undermine the ability of system-critical resources to capture adequate revenues. Location. Many have begun to rec- ognize that the regional diversity of the geographic footprint covered by power pools is such that they need to worry about where generators are encouraged to btuld. Given the constraints of the transmission system, it is critical that new generation be located as close to load as possible. For example, building new generation in western Massachu- setts does not solve the supply situation in southwestern Connecticut. In single-price capacity markets, there is no incentive or price signal pro- vided by the capacity market that encourages new generation to build in an area that benefits the grid. Differ- ences in locational marginal pricing (LMP) encourage generators to build closer to higher-priced locations, but this does not provide enough benefit to marginal generators. .The shortcoming ofnon-location- allybased capacity markets can be wit- nessed in part by the need for many markets to continue to maintain relia- bilirymust run (RMR) programs. RMR payments are designe to com- pensate system-critical resources that are needed to maintain system reliabil- ity. These resources are often older units that run infrequently due to inefficient, out-moded equipment with high heat races. In many cases, these units would not cover their going-forward costs and would be retired if they didn't receive additional monetary support From RMR payments. For example, units like El Segundo on the beach in Los Angeles or Devon on the coast of Connecticut are needed to maintain system reliability. In those areas it is very difficult to site new transmission lines, and probably impossible to site a new power plant anywhere near El Segundo, so the system needs to ensure that these units earn sufficient revenues to keep them from retiring. V~'ithout a capacity market that provides additional compensation for these generators (or more modern substitutes), the power pool must continue to prop them up with administrative RMR payments. Operating (and Fuel) Diversity. In addition to issues surrounding location, questions have been raised about the ability of capacity markets to address the operating profile of new equip- ment. The argument is that even if you get enough capacity at the right place, you still need to worry about the type of equipment that is built. The system needs resources that have operating flexibility and also contribute to the fuel diversity of the overall fleet. The "dash-for-gas" witnessed in the recent past created a glut of homoge- nous units. One problem that has sur- faced as a result of this monolithic block of capacity is that supply is very depend- ent on gas prices. Given the correlation of gas prices to heating needs in winter, regions have seen shortages and price spikes when gas-fired generators sold gas into the heating market rather then gen- erating electricity. Inaddition, many of the units have similar operating chazac- Mav 2005 Pueuc Ununes Foerxiexnr 25 ~il~!I /". 6 ~~h' 1!'I teristics. Many believe that capacity markets need to have the ability to rec- ognizefuel and operating diversity to avoid dependenry on one fuel type and to maintain a fleet of resources that is capable of meeting all of the needs of the system operator in terms of ability to start quickly and follow load. Demand Curve. Finally, there has been one other major shortcoming observed in capacity market design that occurs on the demand side of the equa- tion, asopposed to the supply side issues like those already discussed. Most markets have utilized what is referred to as a "vertical demand curve" to date. This term refers to the construction of most markets where demand is set equal to the target reserve margin which, in effect, creates a fixed quantity that is completely price insensitive. While a description of the full dynamic of the pricing structures of demand curves are beyond the scope of this article, the vertical demand curve typically has created very volatile pric- ing. Historical pricing patterns in exist- ing capacity markets have tended to be shaped by boom/bust or floor/ceiling behavior where prices hover near zero when the market is oversupplied and jump to the capped price or deficienry level when the market passes through equilibrium and enters a period of shortage. This binary pricing pattern produces unwanted volatility that reduces the predictability of revenues for suppliers. Reduced predictability undermines new entrant planning or forces builders to raise costs by includ- ing apremium to cover this price risk. Capacity Market Evolution In response to these perceived short- comings, many markets are consider- ing, or already are undergoing, massive overhauls. Some are adding capacity markets for the first time, while others are adding new features to existing mar- kets. These overhauls are~spurring a new round of thinking on calpacity market design that appears to be leading to interesting-and increasjngly com- plex-new designs. While the final direction of the markers t•emalns to be seen, what is becoming a,~parent is a natural evolution in cap city market form and function. I The bottom of the evdlutionary lad- der (see Figure 1) can be defined as begin- ningwith NoCAP markets as seen in California and ERCOT. Given the issues associated with price caps in most mar- kets, this structure appears to be insuffi- cient. From there we move up the evolu- tionaryscale to simple, pool-wide capac- itymarkets like the current form of the PJM installed (ICAP), or unforced 26 Pueuc Ununes Foeneaxnr Mnv 2005 (UCAP), market. But, as discussed above, this relatively simple structure addresses the question ofvolume only. The locational ICAP market (LICAP) structure that follows the rela- tivelysimplistic ICAP/UCAP model adds a locational component to the pricing structure to add criteria for determining where in the pool new resources are constructed. The pro- posed system in New England, as well as the current system in New York, are examples of this LICAP approach. In addition to addressing location, the LICAP phase also has included modifications to the market-demand curve. By constructing what is referred to as a "sloped" or "curved" demand curve, market designers are attempting to fine-tune the timing of the new build signal and eliminate the binary pricing behavior observed in markets with verti- cal-demand curves. The sloped-demand curve attempts to add subtlety to the market signals by producing increas- ingly high levels of compensation for generators when the market moves towards scarcity levels, and by gradually decreasing levels of compensation when resources are adequate. PJM now is considering taking this a step further, to what can be referred to as "LICAP Plus." If the original PJM structure simply addressed the issue of how much, and the New York/New England LICAP markets add function- ality for addressing when and where, the new PJM design also will help determine what type. The scheme under discussion in PJM is designed to address the operational flexibility of the resources that are built. The proposal includes criteria to provide price distinction based on the ability of resources to follow load or provide quick-start functionality. This will help ensure that the generation mix as a whole is diverse enough to provide the full range of resources www.fortnightly.com needed to meet system needs. So what does all this mean? In terms of market evolution, there is no reason to expect that all of these steps will be fol- lowed inorder byall markets. As experi- encebuilds and historical examples accu- mulate, it is likely that markets will level- jumpfrom NoCAP to LICAP, for in- stance, as is being considered in Califor- nia (see Table 1). Certainly, if a LICAP Plus market appears to work, we may see markets open in the future with that structure used from the beginning. Re- gardless, the current state of the various markets in the United States provides a live example of the progression of thought on how best to ensure resource adequary in deregulated markets. The outcome of the discussions under way in PJM will have a significant impact on the future form of capacity markets. PJM has been viewed for some time as a model market, so others likely will continue to follow its lead and adopt similar market structures. In addi- tion, MISO is under order from the Federal Energy Regulatory Commission to produce a system that is consistent with PJM. Given these developments, within several years the Northeast likely will be dominated by LICAP markets, while LICAP Plus could stretch from the Mid-Atlantic to Montana. Develop- ments in California and ERCOT should add additional momentum to the LICAP model in future years. For market participants, these new structures could have material impacts, at least in the short term. For a generator in Connecticut, for example, the addi- tion of LICAP could mean the differ- encebetween less than $1 /kW-mo. in capacity compensation or $5 or $6/kW- mo. For a generic 600-MW combined- rycleplant, this could add $40 million per year in revenues. To put this in per- spective, anadditional $40 million would increase gross margins from 15 to 40 percent for this typical plant, which I Market Current Future Comment Capacity Market Capacity Market CA None (energy-only) ICAP/LICAP Market Design 2002 (MD02) includes an Available Capacity (ACAP) market that will function like ICAP/ UCAP markets. Also considering adding a LICAP component. ERCOT None (energy-only) Under Discussion Considering various capacity market options as part of overall market overhaul. MISO None (energy-only) LICAP Plus Under FERC order to design a resource adequacy scheme that is consistent with current (and future) PJM system. Started market April 7 without capacity market NY ISO LICAP` No Change New York is a three-zone LICAP market with demand curve. Pricing zones for New York City, Long Island and Rest of State. ISO NE ICAP' LICAP Moving to a 5 zone LICAP market with demand curve, Wiil look a lot like New York. PJM ICAP' LICAP Plus In prtx~ss of designing a new Reliability Pricing Model that will include price adders for location and operating flexibility. Also considering adding a demand curve. 1. Markets calculated based on unforced capacity availability which adJusts available capacity to reflect forced outages. Referred to as ICAP markets that utll¢e UCAP calculation methodology. goes a long way toward covering debt service on struggling merchant plants.] For plants in other parts of NEPOOL, the shift will be less dramatic or perhaps even nonexistent. A plant in the pro- posed "Rest-of--Pool" zone will see little, if any, price appreciation. While price shifts in tight locations like southwest Connecticut and eastern PJM may help struggling generators in the short term, they are unlikely to per- sist over the long term. There are essen- tially three outcomes for the revised markets, all of which should lead to prices that trend toward the mean. First, if the markets function as intended, high prices in load pockets will attract new resources that will alle- viate the shortage and bring the zone back into equilibrium. This will serve to drive prices down in this region over a relatively short time horizon. Another possibility is that new transmission capacity will be built that alleviates constraints within a zone and allows for more import capacity. This outcome also would put the same downward pressure on prices. In fact, some are calling already for NEMA/ SWCT zonal prices in New England to converge on Rest-of--Pool prices within one year of LICAP star because of planned transmission upgrades. Finally, if a new market structure leads to sus- tained high prices for merchant genera- tors, it will be apparent that the market is not working as intended and regula- tors will be forced to reconsider the market structure due to the impact on consumers. Craig Hart is vice president with US Power Generating Co., established fo acquire and manage merchant power projects. He can be reached at chart@uspowergen.com. Endnotes 1. This categorization excludes other ancillary services including spinning reserves, regulation, black-start capability, etc. Nevertheless, it is important to note that it is the combination of energy, ancillary services, and capacity products that provides a total revenue package to gener- ators. But, since these other ancillary services do not differentiate the individual resource ade- quacy markets, a discussion of them is consid- ered out of scope of this article. 2. Many markets account for scheduled out- ages in deterrrtining unit availability. 3. Final market designs may include mecha- nisms for subtracting infra-marginal revenues when determining capacity compensation. If this is ultimately adopted, assuming all else remains equal, the more a generator earns in the energy market the less it will earn in the capacity market. ;, ~, www.fortnightly.com Mnr 2005 IMeuc Ihuntes Foettuextiv 27