Batteries Charge Up For the Electric Grid
INFRASTRUCTURE AND PROJECT FINANCE
US Regulated and Unregulated Utilities
SECTOR IN-DEPTH
Batteries Charge Up For the Electric Grid
24 SEPTEMBER 2015
» TABLE OF CONTENTS Peak-shaving is the most promising application Grid applications include ancillary services and load-following resources Falling costs and regulatory support are fueling growth in electricity storage Batteries are credit negative for merchant generators Batteries are also credit negative for regulated utilities, but less so Other factors will influence the growth of battery installations Appendices Moody's Related Research
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renewables, and fast-response ancillary services.1 Notably, these applications are not based on backing rooftop solar , an application that is a long way off. Northeastern US markets, especially New York City, as well as California and Hawaii will be the first storage markets. Tesla Energy (not rated) sells batteries today for $350-$400/kilowatthour (kWh) and forecasts prices below $200/kWh by 2020. Battery prices have declined more than 50% since 2010.
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Battery prices will come down with volume growth; regulatory support will be key. Support can take the form of energy-storage mandates or subsidies that many states are currently promoting, chiefly California, New York and Hawaii. Federal regulations that permit batteries to provide grid ancillary services in the New York and PJM wholesale markets are another form of support.
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Batteries are credit negative for US merchant generators. Over the long term, merchant generators such as Calpine Corp. (B1 positive), NRG Energy Inc. (Ba3 stable) and Dynegy Inc. (B2 stable) could face lower capacity prices if commercial and industrial demand for power drops during peak hours of the day. Batteries would also lower merchant energy margins by smoothing volatility in the wholesale energy markets and by replacing gas-fired plants that now help integrate renewables into the grid. The timing and magnitude of the credit impact would vary, depending on the extent of battery penetration.
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Batteries are also credit negative for US regulated utilities, but less so. Peakshaving will lower the power bills of commercial and industrial customers of utilities such as Consolidated Edison of New York Inc. (A2 Stable), Pacific Gas & Electric Co. (A3 stable) and Hawaiian Electric Co. (Baa1 negative). In turn, lower revenue would lead regulated utilities to shift costs to other customers. However, we believe that costshifting will in the long run be addressed by changes to the tariff structure.
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Factors other than price could slow down battery adoption. Although price is the most important driver of adoption, other factors such as the customer's load profile, battery reliability, technical specifications and the local utility's tariff structure will also influence battery economics.
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ANALYST CONTACTS Swami Venkataraman, CFA 212-553-7950 VP-Sr Credit Officer [email protected] Toby Shea VP-Sr Credit Officer [email protected]
212-553-1779
Michael G. Haggarty 212-553-7172 Associate Managing Director [email protected] William L. Hess MD-Utilities [email protected]
212-553-3837
If Lithium-ion battery prices continue to fall, many storage applications could become economically viable by the end of the decade. These applications include peak-shaving for commercial and industrial customers, grid storage to integrate
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Peak-shaving by commercial and industrial customers is the most promising application
Utilities typically impose a fixed demand charge on commercial and industrial customers that is based on their peak demand for electricity. These customers could satisfy a portion of their peak demand with a battery that charges at night and is used during peak load hours (see Exhibit 1). The reduction in demand charges that these customers pay to the utility could then be used to recover their investments in battery systems. As we explain in more detail later, this reduction in peak demand could affect the credit quality of merchant generators in the form of lower capacity prices. Lower revenue would also lead regulated utilities to shift costs to other customers, but we believe cost-shifting issues will be addressed through changes to the tariff structure. Exhibit 1
Batteries can lower demand from commercial and industrial customers during peak hours
Note: For illustrative purposes only. Source: Moody's Investors Service
This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on www.moodys.com for the most updated credit rating action information and rating history.
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US REGULATED AND UNREGULATED UTILITIES: BATTERIES CHARGE UP FOR THE ELECTRIC GRID
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Battery Sizing The size of the battery and hours of storage installed would depend on the customer’s load profile. The capital cost* of a battery increases in proportion to the number of hours of storage. The size of the battery (in kilowatts) is thus chosen to offset the few hours of the day in which a customer’s load is significantly higher than the rest of the day. Most load profiles have a four- to five-hour peak period when demand is greater than during other hours, often corresponding to cooling or heating needs. For purposes of our illustration in Exhibit 2, we assume that the customer desires to offset 100 kilowatts of its peak load for four hours. This 100 kilowatt size needs to also consider the load profile of the customer throughout the year to ensure that the battery can provide the customer with demand-charge savings consistently every month. If not, the economics must be based on fewer than 12 months of savings or fewer than 100 kilowatts of savings in certain months. * Note: A battery cost of $350/kWh represents the capital cost of the battery equipment itself and should not be confused with the cost of the energy that is stored in the battery or delivered from it, although these energy costs are also generally expressed in a similar unit, cents/kWh.
Battery Charge-Discharge Efficiency There is some loss of power in the process of storing energy in a battery and withdrawing it, a two-way loss. Tesla Energy has specified that its batteries have roundtrip losses of 8%. In our calculations, we assume that there is a 5% loss each way, or roundtrip losses of 10%. In practice, the hypothetical customer in Exhibit 1 will only be able to extract about 380 kilowatt-hours (kWh) of the 400 kWh stored in the battery, given a 5% discharge loss. However, customer load profiles are not shaped like perfect blocks. Typically, they have a slope both on the way up and on the way down, with some variations during the peak. As a result, the demand profile will not be exactly 100 kW for every minute of the four hours and so 380 kWh of deliverable energy from the battery could be sufficient. If 400 kWh of energy is required to be delivered, then the battery needs to be sized at 420 kWh, which would increase the capital cost in Exhibit 2 by about 5%.
Exhibit 2
Estimated installed cost at which batteries are economically viable for peak-shaving in select utility markets2
Utility
State
Consolidated Edison of New York - Rate I Consolidated Edison of New York - Rate II Hawaiian Electric Co Pacific Gas & Electric Co. Public Service Electric & Gas Co. Southern California Edison Co The United Illuminating Co
NY NY HI CA NJ CA CT
Demand Charge ($/kW-mo)
28.16 36.3 24.34 24.11 19.67 24.78 20.72
Breakeven Installed Cost ($/kWh) No Energy Margin 4c/kWh energy margin
475 612 411 407 332 418 350
542 680 478 474 399 486 417
Sources: the utilities for demand charges; Moody's Investors Service for breakeven installed cost calculation
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New York City stands out as the most economic market for peak-shaving (with potentially the greatest credit impact on merchants and utilities) because of its high demand charges, followed by California, Hawaii and northeastern states, such as New Jersey and Connecticut.
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Based on the price of Tesla Energy's batteries, Solar City Inc. (not rated) has a peak-shaving product priced at an installed cost of about $700/kWh, according to the US Energy Storage Monitor, Q1 2015, published by Greentech Media and Energy Storage Association (see Exhibit 5). At this price, battery installations are only viable with subsidies. However, it is noteworthy that almost 50% of the $700/kWh in installed costs is related to non-battery expenses, which might also come down with economies of scale, ease of permitting or other factors.
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US REGULATED AND UNREGULATED UTILITIES: BATTERIES CHARGE UP FOR THE ELECTRIC GRID
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Grid applications for batteries include ancillary services and load-following resources
There are two distinct grid-based applications for batteries: ancillary services such as voltage and frequency regulation, and loadfollowing resources, which are flexible sources of power that can increase output in lock step with grid demand. Ancillary services: Battery participation in the ancillary services market was enabled by Federal Energy Regulatory Commission (FERC) Orders 890, 755 and 784. Together, these orders allowed (i) “non-generator” resources to compete by selling ancillary services as a stand-alone product; (ii) for speed and accuracy to be considered as parameters in acquiring ancillary resources; and (iii) for increased compensation for “fast response” resources. These applications typically require storage times of only 30 minutes to one hour. Batteries are already commercially viable under FERC rules for ancillary services on a merchant basis, notably in PJM (104 MW) and NYISO (28 MW). Texas is also examining options to allow for greater participation of batteries in its ancillary markets. AES Corp. (Ba3 stable) is prominent among merchant companies in that it owns battery-based ancillary services resources in the US and Chile. This market, however, is not large in absolute terms; only a small amount of capacity is needed, with pumped hydro projects providing 95% of all ancillary services in the US. However, ancillary services can provide some initial growth in volumes that can help drive down battery prices. Load-following resources: Another application is the use of batteries as load-following resources that can provide both capacity and energy to the grid. This application requires batteries of much larger storage capability, usually four hours or more, and can reduce the need for peaking power plants and for transmission and distribution grid upgrades. It also provides utilities with the ability to better integrate the growing share of intermittent renewable energy resources in the power supply mix. The Importance of Regional Transmission Operator (RTO) and Independent System Operator (ISO) Rules Our calculations in Exhibit 3 on the following page assume that batteries as load-following resources will be able to satisfy the technical requirements of RTOs/ISOs and will be able to participate in capacity markets. We have assumed that battery peaking plants will only be required to provide four hours of continuous discharge at peak capacity, which is exactly the requirement that the California ISO imposed on AES Corp. under its 20-year 100 MW peaking contract with Southern California Edison. However, other markets have different rules. For example, battery peakers will not be able to meet the requirements for PJM’s capacity performance product, since the capacity performance product requires availability at any time. Even for the “base capacity” product, PJM outlined in a recent conference call that eight to 10 hours of storage may be required to qualify. This would make economic viability as a load-following resource very far away. As a result, the most likely way for batteries to participate in the PJM capacity market will be in combination with renewables, demand response, or older or less reliable generation assets. PJM’s capacity performance standard does have one benefit for batteries. If a capacity performance asset fails to deliver and a battery steps up to provide energy during those hours, that battery is eligible to receive “overperformance” energy payments. ISO-NE, NYISO and MISO might have different requirements than PJM.
In our view, batteries as capacity or energy resources are further away from being economically viable compared with both ancillary services and even peak-shaving applications. To make economic sense, such investments must either be a part of a utility’s rate base or supported by a contract, one example being the 20-year contract for a 100 MW battery-based peaker that Southern California Edison Co. signed with AES Corp. (Ba3 stable) in 2014. However, because these installations are alternatives to gas-fired peaking plants and because gas-fired peaking plants need to be justified based on capacity and energy revenues, we believe that an assessment of battery economics based on merchant market revenues will be instructive to assess battery economics and to estimate when such installations might become widespread. Exhibit 3 on the next page shows the total installed cost (including land, permits, interconnections and software, for example) at which battery-based merchant power plants will become economically viable in various parts of the country3 (see Appendix D and E for an illustrative calculation for the New York City market).
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Similar to our discussion on peak-shaving, we show the breakeven installed costs both ways — with and without the benefit of an energy margin, based on the difference between peak and off-peak wholesale prices. Depending on the region in the US, we estimate that the installed cost for a battery-based peaker needs to fall to $100/kWh-$300/kWh (at a weighted average cost of capital of 7%) in order to be economic at current capacity prices. Given these low breakeven prices, battery peakers will initially be based either on power purchase agreements, or be a part of a utility’s rate base. Exhibit 3
Estimated installed costs at which battery peakers are economically viable Region
Latest Capacity Price $ / MW-day
NYC NYISO - Zone G-J NE-ISO (SEMA new plant) California* PJM - RTO
510 279 583 493 165
Breakeven Battery Installed Cost ($/kWh) No energy Margin $20/MWh energy margin
248 136 284 240 80
268 155 303 259 100
*California does not have a capacity market. However, new gas plants get a negotiated capacity payment as part of a long-term contract, and we used an estimate of this price for our calculations. Sources: independent system operators (for capacity prices); Moody's Investors Service
Falling costs and regulatory support are fueling growth in electricity storage
Exhibit 4 shows the US Energy Information Administration’s (EIA) battery-price forecast, published in its 2012 Annual Energy Outlook. From an actual price of $1,000/kWh in 2012, the forecast projected a “reference case” price in 2015 above $600/kWh and a “high technology” case of $405/kWh in 2015. Actual market prices, however, appear to have declined faster than even the EIA's optimistic scenario. Tesla Energy, for example, is selling battery packs today at $350/kWh-400/kWh.4 Anecdotal reports from industry participants indicate that high-volume customers might be able to purchase batteries today at prices between $250/kWh-$350/kWh, even from other suppliers. With Tesla Energy indicating5 that it expects prices to be as low as $100/kWh-200/kWh by 2020, this expected trend of falling capital costs suggests that battery applications could become economically viable in three to five years. Exhibit 4
The US Energy Information Administration's battery price forecasts
Source: US Energy Information Administration's Annual Energy Outlook 2012
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Tesla Energy's battery product offerings for utility use are summarized in Exhibit 5 below. The Powerwall product is intended mainly for residential applications, while the Powerpack product is meant for peak-shaving and the grid applications. The Powerpack battery can be integrated into power systems without an inverter and is capable of up to four hours of continuous net discharge. Tesla Energy has not disclosed the price of the Powerpack product, but according to Greentech Media, the Powerpack could cost $250/kWh when Tesla Energy's Giga Factory reaches full utilization6 , further emphasizing the trend of falling prices. Non-residential and utility-scale markets tend to see lower battery prices because of greater volumes. Exhibit 5
Tesla Energy's Battery Product Offering
System Size (kW and kWh) Applications Price Installed system price
Powerwall
Powerpack
2 kW continuous power, 3.3 kW peak power with 7 kWh and 10 kWh options 10 kWh: Back-up/weekly cycling; 7 kWh: Back-up and daily cycling $350/kWh (10 kWh option); $428/kWh (7 kWh option) $714/kWh from Solar City
100 kWh blocks; 2-4 hours storage peak shaving; capacity resource; grid storage $250/kWh Greentech Media Estimate: $700/kWh
Sources: Tesla Energy; Powerpack price and installed system price from US Energy Storage Monitor, Q1 2015 by Greentech Media and Energy Storage Association
Battery price trends must be analyzed taking into consideration that the breakeven costs outlined in Exhibits 2 and 3 are “all-in” installed costs of the battery systems. There are other “balance of plant” (BOP) costs such as land, permitting, and interconnection (for peaking plants), labor and software/control systems. As Exhibit 5 shows, the fully installed system costs still exceed $700/kWh, a 100% premium over the cost of the battery itself. As battery costs fall, achieving BOP cost reductions in tandem will become important for batteries to become competitive. However, the current trend of declining prices appears to point favorably to batteries becoming economically viable in the next three to five years. This is especially the case for peak-shaving applications where current installed costs are only 20%-30% more expensive than the breakeven price in certain states, according to our estimates (see Exhibit 2). Economies of scale will be crucial to spur declines in battery prices. Regulatory frameworks that support battery installations through either rate-base treatment or power purchase agreements will be a key driver of volume over the next several years. For example, the FERC has put in place regulations that support the use of batteries in real-time load-balancing markets. In addition, regulators in California, Hawaii and New York have all either implemented or are proposing regulations that will result in a significant increase in the use of battery-based storage resources in the grid. Appendix F summarizes electricity storage policies in some US states. Other global jurisdictions with significant storage policies include Germany, Japan, Chile and Ontario, Canada. Greentech Media and the Energy Storage Association's growth forecast for the US storage market is in Exhibit 6 below. Exhibit 6
Projected growth in the US storage market
Source: US Energy Storage Monitor, Q1 2015 by Greentech Media and Energy Storage Association 6
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Batteries are credit negative for merchant generators
We believe that a more widespread use of batteries will be credit negative for merchant generators because, all else being the same, it is likely to result in lower capacity prices and lower energy prices. Capacity Prices: Battery-enabled peak-shaving by commercial and industrial customers will reduce peak demand in capacity markets, pressuring capacity prices. Battery-based capacity resources also would effectively increase the supply of peaking capacity if they are allowed to participate in capacity markets. All else being the same, the net impact will be lower capacity prices. Energy Prices: Battery storage will hurt merchant energy margins in two ways: (i) Batteries can store wind energy produced at night or stabilize hourly variability in solar production, thereby offsetting the need for gas-fired peakers that would otherwise be required for this purpose; and (ii) battery storage will help lower the volatility of peak power prices in general, but especially during extreme weather. High peak-pricing is a lucrative and important source of margin for merchant generators. As such hours dwindle or as pricing peaks flatten, merchant profitability will also decline. Although batteries could also be an investment opportunity for merchants, we believe that the potential impact of lower capacity prices and reduced price margins will outweigh the incremental revenue that most large merchant generators will receive from investing in battery plants. There are some markets in which gains and losses may be more evenly balanced for merchants. In California, rising solar production has substantially reduced pricing during the day while increasing pricing during the early evening peak hours. This trend will get more pronounced toward the end of this decade, as seen in California ISO's duck chart in Exhibit 77 . Storage can help pull up the duck’s belly and shorten its neck by storing solar energy produced during the day and using it during the evening hours when actual solar production begins to decline. Although this would reduce evening peak prices, it can also help support prices during the day. Exhibit 7
California ISO's “duck curve”: Growing solar generation is causing the belly and the neck of the duck to expand. Batteries can help flatten both
Source: California ISO
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Batteries are also credit negative for regulated utilities, but less so
For regulated utilities, batteries will cause costs to shift among utility customers. Commercial and industrial customers that use batteries will pay less by way of demand charges, leading to higher demand charges on other customers. Regulators can address this through changes in the tariff structure whenever such cost-shifting becomes material. The use of batteries will reduce the need for certain investments in transmission and distribution infrastructure, which help bring in generation from power plants located far away to meet peak loads. Many regulators expect that the reduction in such expenses, and other benefits such as lower on-peak power prices due to peak shaving will result in overall cost savings to the system and thereby reduce the extent of cost-shifting. Cost-shifting could be addressed by the imposition of straight fixed charges independent of kilowatt peak demand, which is similar to the way regulators in Arizona have imposed a fixed charge independent of kilowatt-hour consumption in order to help ensure that customers with solar panels continue to pay their share of the grid's fixed costs. In this way, rooftop solar and batteries share similarities in that both tend to shift costs from the users of these technologies to other customers, which regulators could remedy through fixed charges. The question for credit quality, if and when cost-shiting becomes a material risk, will be whether regulators will address cost-shifting in a timely and adequate manner even as they meet other public policy objectives, such as supporting the growth of renewable energy and energy storage. Batteries also provide an opportunity for rate base growth for utilities, although this benefit will perhaps be offset by the possibility that certain other transmission or distribution upgrades may become unnecessary.
Other factors will influence the growth of battery installations
Apart from price, other factors will play a role in the growth of battery installations. 1. The customer's load profile. Our calculations assume that the customer has a four-hour period during which its demand is higher than the rest of the day, which is representative of a large number of customers. Batteries would be unsuitable for a customer with a relatively flat load profile, while economics would be better for a customer with a very “peaky” profile — i.e., a customer with very high demand for a short duration and much lower demands for the rest of the day. 2. Battery reliability. Utility demand charges are based on the highest peak demand during any 15-minute period in a given month. Thus, if a customer with a 300 kW peak load reduces it to 200 kW (by using a 100 kW battery), that battery needs to perform at all times. Even if the battery fails for 15 minutes and the customer needs to draw 300 kW during the grid at that time, demand charges for 300 kW are payable for the entire month. Hence, customers need to get comfortable that batteries can perform reliably. 3. Details of the customer's tariff structure. Some utilities (such as Hawaiian Electric) calculate the peak demand based on the average of the monthly peaks during the previous year. Here, the benefits of peak-shaving will only be available from year 2 onward. At Public Service Electric & Gas Co (PSE&G, A2 stable) in New Jersey, the demand charge has two distinct components. One is based on the customer’s own peak demand and the other is based on the customer’s demand that is coincident with the PJM system peak. To the extent that these two are not the same, battery economics need to be calculated accordingly. There are likely to be similar nuances at other utilities. 4. Customer capabilities. Peak-shaving applications require customers to have energy management systems capable of shifting a portion of their demand seamlessly between batteries and the grid. Or a customer might need to pay the battery installer to provide such management services. 5. Technical specifications. Technical specifications of batteries might be important for certain customers. This includes the high ramp rates that might be required in certain industrial applications. Also, the large-scale battery industry is young, and safety standards, such as fire codes for batteries, are still evolving.
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Appendix A Utility customer classes used in our peak-shaving calculations
Utility
Customer class
Other Potential Customer Segments
Consolidated Edison of New York
Other SC9 classes
Hawaiian Electric Co. Pacific Gas & Electric Co. Public Service Electric & Gas Co. Southern California Edison Co.
Service Classification 9 (SC9) General – Large; Low tension service Rate I and Rate II Rate Schedule P Rate Schedule E-20 Large Power & Lighting (LPL) Service - Secondary Rate Schedule TOU-8, General Service – Large
The United Illuminating Co.
Option B, 2 KV to 50 KV service Rate Schedule LPT
Rate Schedule DS Schedules E-19, A-10 Other LPL classes Other General Service – Large classes Rate Schedule GST
Sources: the utilities
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Appendix B8 Estimated breakeven installed cost for peak-shaving without energy margin The table below illustrates the breakeven installed-cost calculation for a large commercial and industrial customer of Public Service Electric & Gas Co. (PSE&G) in New Jersey, where the demand charge is $19.67/kW-month (row “i”). In Row “j,” we calculate that a customer can save $23,600 a year in demand charges by reducing its peak load by 100 kW. In rows “a” through “h,” we calculate that at an installed cost of $331.7/kWh (row “b”), a 100 kW battery system would cost $23,600 per year, at a weighted average cost of capital of 7%. Calculation of Battery System Costs
a
Size of system (kW)
100
b
Battery installed cost ($/KwH)
331.7
c
Depth of discharge discount
20%
d
Storage time (hours)
4
e
Cost in $/kW of deliverable capacity Cost of the 100 kW system ($ '000s) Cost recovery factor
1659
b*d/(1-c)
165.9
e*100/1000
f g h
The size of the system is the size of the peak reduction it delivers. For illustration, this system is 100kW. At any instant, the battery is designed to deliver 100 kW of power as that is the critical requirement to reduce demand charges paid by the customer. Variable in Moody's calculations designed to equate the cost of the battery with that of the grid. It represents the total installed cost of the system, including control systems, wiring and other non-battery costs. Since a battery is used to store energy, the capital cost of a battery is expressed in dollars per unit of energy stored, or $/kWh. This is the typical unit in which the capital cost of battery equipment is represented. It should not be confused with energy prices, where the cost of electric energy is often expressed in cents/kWh. Discussions with a number of utilities and project developers indicate that batteries for commercial applications are usually designed to discharge up to 80% of their capacity. This number will depend on the customer's load profile as described above. Virtually all "behind the meter" batteries are designed to reduce load during the 4 to 5 peak hours of the day.
14.23%
Total cost savings required to pay 23.60 for the battery($ '000s)
Assuming a 10-year life and 7% WACC, NPV calculations show that an investment of $1 million in a battery requires annual savings in utility demand charges of $0.14 million to be economically viable. f*g
Calculation of Demand Charge Savings
i j
Utility demand charge ($/kWmonth) Savings on 100 kW for one year ($ '000s)
19.67 23.60
Demand charge for PSE&G customers i*100*12/1000
When line h equals line j, batteries will reach parity with the electric grid. This calculation assumes that the battery cycles 365 days a year for 10 years to achieve a 100 kW reduction in demand every day.
Source: Moody's Investors Service
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Appendix C Estimated breakeven installed cost for peak-shaving with on-peak/off-peak energy arbitrage (continuing Appendix B calculations) k l
Roundtrip losses of the battery Energy into the battery (kWh)
10% 421
m
Energy available from the battery (kWh) Cost of off-peak input energy (c/ kWh) Price of on-peak power whose purchase is avoided by the battery (c/kWh) Savings per cycle ($) Cycles per year
380
n o p q r s t u
Annual savings from energy arbitrage ($ '000s) Savings from demand charges ($'000s) Total savings from battery ($'000s) Capital cost of battery that can be supported by the total savings in line t ($/kWh)
Assuming a 5% charging loss, the customer needs to purchase 400/0.95 = 421 kWh in order to charge the battery to 400 kWh Assuming a 5% discharging loss, the customer can extract only 400*0.95 = 380 kWh from the 400 kWh stored in the battery Cost of off-peak energy used to charge the battery
5 9
Avoided cost of on-peak energy that would have had to be purchased in the absence of a battery
13.15 365
(m*o-l*n)
4.80
p*q /1000
Assuming the battery is cycled every day of the year. Batteries have a 10-year life but also have a limitation on the number of cycles, typically between 2000 to 6000 per year. This model assumes a life of at least 3650 cycles.
23.60 28.40 399
Same as line j of Appendix B, which calculates the savings in demand charges from a reduction in peak load of 100 kW. r+s Uses the same approach as Appendix B to calculate the installed capital cost of a battery in $/kWh that can be supported by the total savings calculated in row "t."
Source: Moody's Investors Service
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Appendix D Estimated breakeven installed cost of a battery peaking plant in New York City without energy arbitrage Calculation of Battery System Costs
a
Size of system (MW)
b
Battery Installed Cost ($/KwH)
248.3
c
Depth of discharge discount and discharge loss
24%
d
Storage time (hours)
e f
Cost in $/kW Cost for 100 MW system ($ millions) Cost recovery factor
g h
Annual revenue required ($ millions)
100
The size of the system is the size of the peaking capacity it delivers. For illustration, this system is 100 MW. Any instant, this plant can deliver 100 MW of peaking capacity when called on. Variable in Moody's calculations designed to equate the cost of the battery, including capital recovery, to the capacity revenues available in the market. The installed cost includes permitting, land, interconnection, control systems, wiring and other non-battery costs. Since a battery is used to store energy, the capital cost of a battery is expressed in dollars per unit of energy stored, or $/kWh. By contrast, the capital costs of power generation plants are generally expressed in $/kilowatt of capacity. Also, the capital cost of the battery equipment should not be confused with the cost of electric energy used to charge the battery, which is typically expressed in cents/kWh or $/MWh. Only 80% of the battery's capacity can actually be used. Also, 5% of stored energy is lost when discharged. Accounting for both gives an effective delivered energy of 80%*95% = 76% of the capacity of the battery. Thus, in order to achieve a delivered amount of energy in each cycle of 400 MWh, the amount of energy that needs to be stored in the battery equals 421 MWh (due to 5% loss). This would require the designed storage capacity of battery to be 526 MWh (since 20% of the capacity is not usable). The CA ISO recently awarded a 100 MW contract to AES Corp. to build a battery peaking plant that has four hours of storage. We use that as our assumption.
4 1307 130.7
b*d/(1-c) e*100*1000
14.23% 18.60
NPV calculations assuming a 10-year life and 7% WACC. An investment of $1 million requires annual revenues of $0.14 million. f*g
Calculation of Revenue Available from the Capacity Market
i j
Capacity price in NYC ($/MW-day) Capacity revenue available for a 100 MW peaker ($ millions)
510 18.60
i*100*365/1000000
Capacity price for zone J in recent NYISO auction When line h equals line j, battery-based peaking plants will be viable as a merchant investment.
Source: Moody's Investors Service
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Appendix E Estimated breakeven installed cost of a battery peaking plant in New York City with energy arbitrage (continuing Appendix D calculations) k l m n o p q
r s t u
Roundtrip losses of the battery Energy into the battery (MWh) Energy available from the battery (MWh) Cost of input energy ($/ MWh) Price of on-peak power whose purchase is avoided by the battery ($/MWh) Savings per cycle ($ 000s) Cycles per year
Annual margin from energy arbitrage ($ millions) Capacity revenues ($ millions) Total revenues available for the battery ($ millions) Capital cost of battery that can be supported by the total revenues in line "t" ($/kWh)
10%
Same assumption as in Appendix C.
443
There will also be a 5% charging loss. As a result, in order to fill the usable capacity of 421 MWh in each cycle, 443 MWh needs to be purchased. Battery system is designed to deliver 100 MW for 4 hours, or 400 MWh. It is sized to store 421 MWh, so as to deliver 400 MWh after a 5% discharge loss. Cost of off-peak energy used to charge the battery
400 20 40
Wholesale price at which on-peak energy is sold. The important number is the difference between on-peak and off-peak prices.
7.14 200
(m*o-l*n)/1000
1.43
p*q /1000
Assuming 200 days of cycling in a year since market conditions or ISO dispatch instructions may not allow for daily cycling. Batteries have a 10-year life but also have a limitation on the number of cycles, typically between 2000 to 6000 through their life.
18.60 20.03 267.5
Same as line j in Appendix D above. q+r Uses the same approach as Appendix D to calculate the installed capital cost of a battery in $/kWh that can be supported by the total savings calculated in row "t."
Source: Moody's Investors Service
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Appendix F State incentive programs for energy storage Region
Program
Form of Subsidy
Activity thus far
FERC-regulated wholesale markets Arizona
Frequency and voltage regulation ancillary services Contracts, rebates
Improved compensation for “fast response” resources like batteries.
California
Mandate to procure 1,325 MW of storage by 2020 SGIP Incentives
Storage contract with utilities via RFP.
PJM and NY have ~104 MW and 28 MW of battery & flywheel storage, respectively. PJM, MISO, CAISO, NYISO, ISO-NE and SPP have all complied with Order 755. Tuscon Electric - 10 MW solicitation Arizona Public Service: 2 MW of DG solar + storage plus $1 million in rebates SCE has signed contracts for 325 MW
New York
Reforming the Energy Vision (REV)
Texas
Ancillary services market rules + utility investment
Hawaii
PPAs, tax credits
Oregon
Storage mandate
Maryland
Pilot projects
Washington
Grants
Illinois
Rate base
New Jersey
Grants
SGIP incentives for 6.8 MW of “behind the meter” storage. Reserved funding for another 85.5 MW Details being finalized. Broad reform of Plan to add 100 MW of efficiency and storage in NYC to offset utility business model. congestion and risk of Indian Point nuclear plant shutting down. Incentives at $2,100/kW. Rules similar to FERC rules. New ancillary market rules under consideration. No legislation Utility investment will need yet to support Oncor’s storage proposal. changes in Texas regulatory policy for transmission and distribution service providers. Contract with utilities for grid 11 grid storage pilot projects initiated. Looking to obtain up to storage projects; bills introduced for tax 200 MW in Oahu. credits for “behind the meter” storage. Bill to procure at least 5 MW in storage by 2020. Bill introduced to require PSC to implement pilot projects. Four projects received $14.3 million in Two 1 MW projects are operational grants from the state’s clean energy fund. Bill to enable Comed to invest $300 million in six micro-grids. Storage projects paired with renewable $2.9 million for 13 projects totaling 8.75 MW plants.
Sources: US Department of Energy Global Energy Storage Database; Greentech Media; Environment & Energy (E&E) Publishing
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Moody's Related Research Sector In-Depth: »
Batteries are coming but utilities won't go away, Jan 2015 (1001444)
»
Regulatory Response Looks to Stay Ahead of the Distributed Generation Curve, November 2014 (176775)
»
Cloudy Skies and Low Rates Shield Washington State Electric Utilities From Unfettered Rooftop Solar Growth, August 2014 (174242)
»
Regulatory Framework Holds Key to Risks and Rewards Associated With Distributed Generation, April 2014 (165944)
»
Rooftop Solar, Distributed Generation Not Expected to Pose Threat to Utilities, November 2013 (160080)
Issuer In-Depth: »
Arizona Public Service: Getting a Jump on Rooftop Solar Distributed Generation, May 2014 (169745)
Structured Finance Sector Comments: »
California's Utility Residential Rate Reform Increases Contract Risk in Outstanding Solar Securitizations, August 2015 (1007520)
»
Solar Securitization Is Emerging as an ABS Asset Class, January 2015 (SF393653)
»
Risks in Commercial Contracts Differ from Residential, June 2013 (SF333536)
To access any of these reports, click on the entry above. Note that these references are current as of the date of publication of this report and that more recent reports may be available. All research may not be available to all clients.
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Endnotes 1 Peak-shaving is when a customer uses energy stored in a battery to serve a portion of the customer's demand, instead of buying it from a utility. Fastresponse ancillary services include voltage and frequency regulation services with response times as fast as 10 minutes, which help maintain the stability of the grid. 2 The demand charges shown in Exhibit 2 are applicable to specific commercial and industrial (C&I) customer classes for each utility listed in Appendix A. These classes constitute a large share of the utility’s C&I customer base, generally providing at least 10%-15% of the utility’s total revenue. Thus, they are not special cases and represent a large market. 3 In our calculations (see Appendix D), current capacity prices are assumed to continue for the 10-year life of the battery. Also, we ignore operating costs other than the round-trip efficiency, or costs like property taxes (these would be low if the battery is at an existing site). 4 See Tesla Energy's website for pricing specifics. 5 See Tesla Energy's presentation at the 2015 EIA conference, dated June 15, 2015, slide 22, posted on the US EIA's website. 6 See US Energy Storage Monitor, Q1 2015: Executive Summary, May 2015, slide 9, published by Greentech Media and Energy Storage Association. 7 See the California Independent System Operator's website. 8 We have simplified these calculations by eliminating the consideration of whether roundtrip losses associated with charging/discharging batteries will necessitate a larger battery (and hence capital cost). As explained in the sidebar titled, “Battery Charge/Discharge Efficiency,” the Exhibit 2 calculations effectively assume that the customer’s peak demand is not at 100 kW for every minute of the four hours (a reasonable assumption for retail loads and hence for the peak-shaving application) and so the battery does not need to be sized up to account for discharge loses. Calculations in Appendix D, which models a battery as a peaking plant, incorporates the need to upsize the battery to accommodate roundtrip losses.
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AUTHORS Swami Venkataraman, CFA Toby Shea Tiago Ferreira
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US Regulated and Unregulated Utilities
SECTOR IN-DEPTH
Batteries Charge Up For the Electric Grid
24 SEPTEMBER 2015
» TABLE OF CONTENTS Peak-shaving is the most promising application Grid applications include ancillary services and load-following resources Falling costs and regulatory support are fueling growth in electricity storage Batteries are credit negative for merchant generators Batteries are also credit negative for regulated utilities, but less so Other factors will influence the growth of battery installations Appendices Moody's Related Research
2
renewables, and fast-response ancillary services.1 Notably, these applications are not based on backing rooftop solar , an application that is a long way off. Northeastern US markets, especially New York City, as well as California and Hawaii will be the first storage markets. Tesla Energy (not rated) sells batteries today for $350-$400/kilowatthour (kWh) and forecasts prices below $200/kWh by 2020. Battery prices have declined more than 50% since 2010.
4 5 7 8 8
»
Battery prices will come down with volume growth; regulatory support will be key. Support can take the form of energy-storage mandates or subsidies that many states are currently promoting, chiefly California, New York and Hawaii. Federal regulations that permit batteries to provide grid ancillary services in the New York and PJM wholesale markets are another form of support.
»
Batteries are credit negative for US merchant generators. Over the long term, merchant generators such as Calpine Corp. (B1 positive), NRG Energy Inc. (Ba3 stable) and Dynegy Inc. (B2 stable) could face lower capacity prices if commercial and industrial demand for power drops during peak hours of the day. Batteries would also lower merchant energy margins by smoothing volatility in the wholesale energy markets and by replacing gas-fired plants that now help integrate renewables into the grid. The timing and magnitude of the credit impact would vary, depending on the extent of battery penetration.
»
Batteries are also credit negative for US regulated utilities, but less so. Peakshaving will lower the power bills of commercial and industrial customers of utilities such as Consolidated Edison of New York Inc. (A2 Stable), Pacific Gas & Electric Co. (A3 stable) and Hawaiian Electric Co. (Baa1 negative). In turn, lower revenue would lead regulated utilities to shift costs to other customers. However, we believe that costshifting will in the long run be addressed by changes to the tariff structure.
»
Factors other than price could slow down battery adoption. Although price is the most important driver of adoption, other factors such as the customer's load profile, battery reliability, technical specifications and the local utility's tariff structure will also influence battery economics.
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ANALYST CONTACTS Swami Venkataraman, CFA 212-553-7950 VP-Sr Credit Officer [email protected] Toby Shea VP-Sr Credit Officer [email protected]
212-553-1779
Michael G. Haggarty 212-553-7172 Associate Managing Director [email protected] William L. Hess MD-Utilities [email protected]
212-553-3837
If Lithium-ion battery prices continue to fall, many storage applications could become economically viable by the end of the decade. These applications include peak-shaving for commercial and industrial customers, grid storage to integrate
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Peak-shaving by commercial and industrial customers is the most promising application
Utilities typically impose a fixed demand charge on commercial and industrial customers that is based on their peak demand for electricity. These customers could satisfy a portion of their peak demand with a battery that charges at night and is used during peak load hours (see Exhibit 1). The reduction in demand charges that these customers pay to the utility could then be used to recover their investments in battery systems. As we explain in more detail later, this reduction in peak demand could affect the credit quality of merchant generators in the form of lower capacity prices. Lower revenue would also lead regulated utilities to shift costs to other customers, but we believe cost-shifting issues will be addressed through changes to the tariff structure. Exhibit 1
Batteries can lower demand from commercial and industrial customers during peak hours
Note: For illustrative purposes only. Source: Moody's Investors Service
This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on www.moodys.com for the most updated credit rating action information and rating history.
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Battery Sizing The size of the battery and hours of storage installed would depend on the customer’s load profile. The capital cost* of a battery increases in proportion to the number of hours of storage. The size of the battery (in kilowatts) is thus chosen to offset the few hours of the day in which a customer’s load is significantly higher than the rest of the day. Most load profiles have a four- to five-hour peak period when demand is greater than during other hours, often corresponding to cooling or heating needs. For purposes of our illustration in Exhibit 2, we assume that the customer desires to offset 100 kilowatts of its peak load for four hours. This 100 kilowatt size needs to also consider the load profile of the customer throughout the year to ensure that the battery can provide the customer with demand-charge savings consistently every month. If not, the economics must be based on fewer than 12 months of savings or fewer than 100 kilowatts of savings in certain months. * Note: A battery cost of $350/kWh represents the capital cost of the battery equipment itself and should not be confused with the cost of the energy that is stored in the battery or delivered from it, although these energy costs are also generally expressed in a similar unit, cents/kWh.
Battery Charge-Discharge Efficiency There is some loss of power in the process of storing energy in a battery and withdrawing it, a two-way loss. Tesla Energy has specified that its batteries have roundtrip losses of 8%. In our calculations, we assume that there is a 5% loss each way, or roundtrip losses of 10%. In practice, the hypothetical customer in Exhibit 1 will only be able to extract about 380 kilowatt-hours (kWh) of the 400 kWh stored in the battery, given a 5% discharge loss. However, customer load profiles are not shaped like perfect blocks. Typically, they have a slope both on the way up and on the way down, with some variations during the peak. As a result, the demand profile will not be exactly 100 kW for every minute of the four hours and so 380 kWh of deliverable energy from the battery could be sufficient. If 400 kWh of energy is required to be delivered, then the battery needs to be sized at 420 kWh, which would increase the capital cost in Exhibit 2 by about 5%.
Exhibit 2
Estimated installed cost at which batteries are economically viable for peak-shaving in select utility markets2
Utility
State
Consolidated Edison of New York - Rate I Consolidated Edison of New York - Rate II Hawaiian Electric Co Pacific Gas & Electric Co. Public Service Electric & Gas Co. Southern California Edison Co The United Illuminating Co
NY NY HI CA NJ CA CT
Demand Charge ($/kW-mo)
28.16 36.3 24.34 24.11 19.67 24.78 20.72
Breakeven Installed Cost ($/kWh) No Energy Margin 4c/kWh energy margin
475 612 411 407 332 418 350
542 680 478 474 399 486 417
Sources: the utilities for demand charges; Moody's Investors Service for breakeven installed cost calculation
3
»
New York City stands out as the most economic market for peak-shaving (with potentially the greatest credit impact on merchants and utilities) because of its high demand charges, followed by California, Hawaii and northeastern states, such as New Jersey and Connecticut.
»
Based on the price of Tesla Energy's batteries, Solar City Inc. (not rated) has a peak-shaving product priced at an installed cost of about $700/kWh, according to the US Energy Storage Monitor, Q1 2015, published by Greentech Media and Energy Storage Association (see Exhibit 5). At this price, battery installations are only viable with subsidies. However, it is noteworthy that almost 50% of the $700/kWh in installed costs is related to non-battery expenses, which might also come down with economies of scale, ease of permitting or other factors.
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Grid applications for batteries include ancillary services and load-following resources
There are two distinct grid-based applications for batteries: ancillary services such as voltage and frequency regulation, and loadfollowing resources, which are flexible sources of power that can increase output in lock step with grid demand. Ancillary services: Battery participation in the ancillary services market was enabled by Federal Energy Regulatory Commission (FERC) Orders 890, 755 and 784. Together, these orders allowed (i) “non-generator” resources to compete by selling ancillary services as a stand-alone product; (ii) for speed and accuracy to be considered as parameters in acquiring ancillary resources; and (iii) for increased compensation for “fast response” resources. These applications typically require storage times of only 30 minutes to one hour. Batteries are already commercially viable under FERC rules for ancillary services on a merchant basis, notably in PJM (104 MW) and NYISO (28 MW). Texas is also examining options to allow for greater participation of batteries in its ancillary markets. AES Corp. (Ba3 stable) is prominent among merchant companies in that it owns battery-based ancillary services resources in the US and Chile. This market, however, is not large in absolute terms; only a small amount of capacity is needed, with pumped hydro projects providing 95% of all ancillary services in the US. However, ancillary services can provide some initial growth in volumes that can help drive down battery prices. Load-following resources: Another application is the use of batteries as load-following resources that can provide both capacity and energy to the grid. This application requires batteries of much larger storage capability, usually four hours or more, and can reduce the need for peaking power plants and for transmission and distribution grid upgrades. It also provides utilities with the ability to better integrate the growing share of intermittent renewable energy resources in the power supply mix. The Importance of Regional Transmission Operator (RTO) and Independent System Operator (ISO) Rules Our calculations in Exhibit 3 on the following page assume that batteries as load-following resources will be able to satisfy the technical requirements of RTOs/ISOs and will be able to participate in capacity markets. We have assumed that battery peaking plants will only be required to provide four hours of continuous discharge at peak capacity, which is exactly the requirement that the California ISO imposed on AES Corp. under its 20-year 100 MW peaking contract with Southern California Edison. However, other markets have different rules. For example, battery peakers will not be able to meet the requirements for PJM’s capacity performance product, since the capacity performance product requires availability at any time. Even for the “base capacity” product, PJM outlined in a recent conference call that eight to 10 hours of storage may be required to qualify. This would make economic viability as a load-following resource very far away. As a result, the most likely way for batteries to participate in the PJM capacity market will be in combination with renewables, demand response, or older or less reliable generation assets. PJM’s capacity performance standard does have one benefit for batteries. If a capacity performance asset fails to deliver and a battery steps up to provide energy during those hours, that battery is eligible to receive “overperformance” energy payments. ISO-NE, NYISO and MISO might have different requirements than PJM.
In our view, batteries as capacity or energy resources are further away from being economically viable compared with both ancillary services and even peak-shaving applications. To make economic sense, such investments must either be a part of a utility’s rate base or supported by a contract, one example being the 20-year contract for a 100 MW battery-based peaker that Southern California Edison Co. signed with AES Corp. (Ba3 stable) in 2014. However, because these installations are alternatives to gas-fired peaking plants and because gas-fired peaking plants need to be justified based on capacity and energy revenues, we believe that an assessment of battery economics based on merchant market revenues will be instructive to assess battery economics and to estimate when such installations might become widespread. Exhibit 3 on the next page shows the total installed cost (including land, permits, interconnections and software, for example) at which battery-based merchant power plants will become economically viable in various parts of the country3 (see Appendix D and E for an illustrative calculation for the New York City market).
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Similar to our discussion on peak-shaving, we show the breakeven installed costs both ways — with and without the benefit of an energy margin, based on the difference between peak and off-peak wholesale prices. Depending on the region in the US, we estimate that the installed cost for a battery-based peaker needs to fall to $100/kWh-$300/kWh (at a weighted average cost of capital of 7%) in order to be economic at current capacity prices. Given these low breakeven prices, battery peakers will initially be based either on power purchase agreements, or be a part of a utility’s rate base. Exhibit 3
Estimated installed costs at which battery peakers are economically viable Region
Latest Capacity Price $ / MW-day
NYC NYISO - Zone G-J NE-ISO (SEMA new plant) California* PJM - RTO
510 279 583 493 165
Breakeven Battery Installed Cost ($/kWh) No energy Margin $20/MWh energy margin
248 136 284 240 80
268 155 303 259 100
*California does not have a capacity market. However, new gas plants get a negotiated capacity payment as part of a long-term contract, and we used an estimate of this price for our calculations. Sources: independent system operators (for capacity prices); Moody's Investors Service
Falling costs and regulatory support are fueling growth in electricity storage
Exhibit 4 shows the US Energy Information Administration’s (EIA) battery-price forecast, published in its 2012 Annual Energy Outlook. From an actual price of $1,000/kWh in 2012, the forecast projected a “reference case” price in 2015 above $600/kWh and a “high technology” case of $405/kWh in 2015. Actual market prices, however, appear to have declined faster than even the EIA's optimistic scenario. Tesla Energy, for example, is selling battery packs today at $350/kWh-400/kWh.4 Anecdotal reports from industry participants indicate that high-volume customers might be able to purchase batteries today at prices between $250/kWh-$350/kWh, even from other suppliers. With Tesla Energy indicating5 that it expects prices to be as low as $100/kWh-200/kWh by 2020, this expected trend of falling capital costs suggests that battery applications could become economically viable in three to five years. Exhibit 4
The US Energy Information Administration's battery price forecasts
Source: US Energy Information Administration's Annual Energy Outlook 2012
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Tesla Energy's battery product offerings for utility use are summarized in Exhibit 5 below. The Powerwall product is intended mainly for residential applications, while the Powerpack product is meant for peak-shaving and the grid applications. The Powerpack battery can be integrated into power systems without an inverter and is capable of up to four hours of continuous net discharge. Tesla Energy has not disclosed the price of the Powerpack product, but according to Greentech Media, the Powerpack could cost $250/kWh when Tesla Energy's Giga Factory reaches full utilization6 , further emphasizing the trend of falling prices. Non-residential and utility-scale markets tend to see lower battery prices because of greater volumes. Exhibit 5
Tesla Energy's Battery Product Offering
System Size (kW and kWh) Applications Price Installed system price
Powerwall
Powerpack
2 kW continuous power, 3.3 kW peak power with 7 kWh and 10 kWh options 10 kWh: Back-up/weekly cycling; 7 kWh: Back-up and daily cycling $350/kWh (10 kWh option); $428/kWh (7 kWh option) $714/kWh from Solar City
100 kWh blocks; 2-4 hours storage peak shaving; capacity resource; grid storage $250/kWh Greentech Media Estimate: $700/kWh
Sources: Tesla Energy; Powerpack price and installed system price from US Energy Storage Monitor, Q1 2015 by Greentech Media and Energy Storage Association
Battery price trends must be analyzed taking into consideration that the breakeven costs outlined in Exhibits 2 and 3 are “all-in” installed costs of the battery systems. There are other “balance of plant” (BOP) costs such as land, permitting, and interconnection (for peaking plants), labor and software/control systems. As Exhibit 5 shows, the fully installed system costs still exceed $700/kWh, a 100% premium over the cost of the battery itself. As battery costs fall, achieving BOP cost reductions in tandem will become important for batteries to become competitive. However, the current trend of declining prices appears to point favorably to batteries becoming economically viable in the next three to five years. This is especially the case for peak-shaving applications where current installed costs are only 20%-30% more expensive than the breakeven price in certain states, according to our estimates (see Exhibit 2). Economies of scale will be crucial to spur declines in battery prices. Regulatory frameworks that support battery installations through either rate-base treatment or power purchase agreements will be a key driver of volume over the next several years. For example, the FERC has put in place regulations that support the use of batteries in real-time load-balancing markets. In addition, regulators in California, Hawaii and New York have all either implemented or are proposing regulations that will result in a significant increase in the use of battery-based storage resources in the grid. Appendix F summarizes electricity storage policies in some US states. Other global jurisdictions with significant storage policies include Germany, Japan, Chile and Ontario, Canada. Greentech Media and the Energy Storage Association's growth forecast for the US storage market is in Exhibit 6 below. Exhibit 6
Projected growth in the US storage market
Source: US Energy Storage Monitor, Q1 2015 by Greentech Media and Energy Storage Association 6
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Batteries are credit negative for merchant generators
We believe that a more widespread use of batteries will be credit negative for merchant generators because, all else being the same, it is likely to result in lower capacity prices and lower energy prices. Capacity Prices: Battery-enabled peak-shaving by commercial and industrial customers will reduce peak demand in capacity markets, pressuring capacity prices. Battery-based capacity resources also would effectively increase the supply of peaking capacity if they are allowed to participate in capacity markets. All else being the same, the net impact will be lower capacity prices. Energy Prices: Battery storage will hurt merchant energy margins in two ways: (i) Batteries can store wind energy produced at night or stabilize hourly variability in solar production, thereby offsetting the need for gas-fired peakers that would otherwise be required for this purpose; and (ii) battery storage will help lower the volatility of peak power prices in general, but especially during extreme weather. High peak-pricing is a lucrative and important source of margin for merchant generators. As such hours dwindle or as pricing peaks flatten, merchant profitability will also decline. Although batteries could also be an investment opportunity for merchants, we believe that the potential impact of lower capacity prices and reduced price margins will outweigh the incremental revenue that most large merchant generators will receive from investing in battery plants. There are some markets in which gains and losses may be more evenly balanced for merchants. In California, rising solar production has substantially reduced pricing during the day while increasing pricing during the early evening peak hours. This trend will get more pronounced toward the end of this decade, as seen in California ISO's duck chart in Exhibit 77 . Storage can help pull up the duck’s belly and shorten its neck by storing solar energy produced during the day and using it during the evening hours when actual solar production begins to decline. Although this would reduce evening peak prices, it can also help support prices during the day. Exhibit 7
California ISO's “duck curve”: Growing solar generation is causing the belly and the neck of the duck to expand. Batteries can help flatten both
Source: California ISO
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Batteries are also credit negative for regulated utilities, but less so
For regulated utilities, batteries will cause costs to shift among utility customers. Commercial and industrial customers that use batteries will pay less by way of demand charges, leading to higher demand charges on other customers. Regulators can address this through changes in the tariff structure whenever such cost-shifting becomes material. The use of batteries will reduce the need for certain investments in transmission and distribution infrastructure, which help bring in generation from power plants located far away to meet peak loads. Many regulators expect that the reduction in such expenses, and other benefits such as lower on-peak power prices due to peak shaving will result in overall cost savings to the system and thereby reduce the extent of cost-shifting. Cost-shifting could be addressed by the imposition of straight fixed charges independent of kilowatt peak demand, which is similar to the way regulators in Arizona have imposed a fixed charge independent of kilowatt-hour consumption in order to help ensure that customers with solar panels continue to pay their share of the grid's fixed costs. In this way, rooftop solar and batteries share similarities in that both tend to shift costs from the users of these technologies to other customers, which regulators could remedy through fixed charges. The question for credit quality, if and when cost-shiting becomes a material risk, will be whether regulators will address cost-shifting in a timely and adequate manner even as they meet other public policy objectives, such as supporting the growth of renewable energy and energy storage. Batteries also provide an opportunity for rate base growth for utilities, although this benefit will perhaps be offset by the possibility that certain other transmission or distribution upgrades may become unnecessary.
Other factors will influence the growth of battery installations
Apart from price, other factors will play a role in the growth of battery installations. 1. The customer's load profile. Our calculations assume that the customer has a four-hour period during which its demand is higher than the rest of the day, which is representative of a large number of customers. Batteries would be unsuitable for a customer with a relatively flat load profile, while economics would be better for a customer with a very “peaky” profile — i.e., a customer with very high demand for a short duration and much lower demands for the rest of the day. 2. Battery reliability. Utility demand charges are based on the highest peak demand during any 15-minute period in a given month. Thus, if a customer with a 300 kW peak load reduces it to 200 kW (by using a 100 kW battery), that battery needs to perform at all times. Even if the battery fails for 15 minutes and the customer needs to draw 300 kW during the grid at that time, demand charges for 300 kW are payable for the entire month. Hence, customers need to get comfortable that batteries can perform reliably. 3. Details of the customer's tariff structure. Some utilities (such as Hawaiian Electric) calculate the peak demand based on the average of the monthly peaks during the previous year. Here, the benefits of peak-shaving will only be available from year 2 onward. At Public Service Electric & Gas Co (PSE&G, A2 stable) in New Jersey, the demand charge has two distinct components. One is based on the customer’s own peak demand and the other is based on the customer’s demand that is coincident with the PJM system peak. To the extent that these two are not the same, battery economics need to be calculated accordingly. There are likely to be similar nuances at other utilities. 4. Customer capabilities. Peak-shaving applications require customers to have energy management systems capable of shifting a portion of their demand seamlessly between batteries and the grid. Or a customer might need to pay the battery installer to provide such management services. 5. Technical specifications. Technical specifications of batteries might be important for certain customers. This includes the high ramp rates that might be required in certain industrial applications. Also, the large-scale battery industry is young, and safety standards, such as fire codes for batteries, are still evolving.
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Appendix A Utility customer classes used in our peak-shaving calculations
Utility
Customer class
Other Potential Customer Segments
Consolidated Edison of New York
Other SC9 classes
Hawaiian Electric Co. Pacific Gas & Electric Co. Public Service Electric & Gas Co. Southern California Edison Co.
Service Classification 9 (SC9) General – Large; Low tension service Rate I and Rate II Rate Schedule P Rate Schedule E-20 Large Power & Lighting (LPL) Service - Secondary Rate Schedule TOU-8, General Service – Large
The United Illuminating Co.
Option B, 2 KV to 50 KV service Rate Schedule LPT
Rate Schedule DS Schedules E-19, A-10 Other LPL classes Other General Service – Large classes Rate Schedule GST
Sources: the utilities
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Appendix B8 Estimated breakeven installed cost for peak-shaving without energy margin The table below illustrates the breakeven installed-cost calculation for a large commercial and industrial customer of Public Service Electric & Gas Co. (PSE&G) in New Jersey, where the demand charge is $19.67/kW-month (row “i”). In Row “j,” we calculate that a customer can save $23,600 a year in demand charges by reducing its peak load by 100 kW. In rows “a” through “h,” we calculate that at an installed cost of $331.7/kWh (row “b”), a 100 kW battery system would cost $23,600 per year, at a weighted average cost of capital of 7%. Calculation of Battery System Costs
a
Size of system (kW)
100
b
Battery installed cost ($/KwH)
331.7
c
Depth of discharge discount
20%
d
Storage time (hours)
4
e
Cost in $/kW of deliverable capacity Cost of the 100 kW system ($ '000s) Cost recovery factor
1659
b*d/(1-c)
165.9
e*100/1000
f g h
The size of the system is the size of the peak reduction it delivers. For illustration, this system is 100kW. At any instant, the battery is designed to deliver 100 kW of power as that is the critical requirement to reduce demand charges paid by the customer. Variable in Moody's calculations designed to equate the cost of the battery with that of the grid. It represents the total installed cost of the system, including control systems, wiring and other non-battery costs. Since a battery is used to store energy, the capital cost of a battery is expressed in dollars per unit of energy stored, or $/kWh. This is the typical unit in which the capital cost of battery equipment is represented. It should not be confused with energy prices, where the cost of electric energy is often expressed in cents/kWh. Discussions with a number of utilities and project developers indicate that batteries for commercial applications are usually designed to discharge up to 80% of their capacity. This number will depend on the customer's load profile as described above. Virtually all "behind the meter" batteries are designed to reduce load during the 4 to 5 peak hours of the day.
14.23%
Total cost savings required to pay 23.60 for the battery($ '000s)
Assuming a 10-year life and 7% WACC, NPV calculations show that an investment of $1 million in a battery requires annual savings in utility demand charges of $0.14 million to be economically viable. f*g
Calculation of Demand Charge Savings
i j
Utility demand charge ($/kWmonth) Savings on 100 kW for one year ($ '000s)
19.67 23.60
Demand charge for PSE&G customers i*100*12/1000
When line h equals line j, batteries will reach parity with the electric grid. This calculation assumes that the battery cycles 365 days a year for 10 years to achieve a 100 kW reduction in demand every day.
Source: Moody's Investors Service
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Appendix C Estimated breakeven installed cost for peak-shaving with on-peak/off-peak energy arbitrage (continuing Appendix B calculations) k l
Roundtrip losses of the battery Energy into the battery (kWh)
10% 421
m
Energy available from the battery (kWh) Cost of off-peak input energy (c/ kWh) Price of on-peak power whose purchase is avoided by the battery (c/kWh) Savings per cycle ($) Cycles per year
380
n o p q r s t u
Annual savings from energy arbitrage ($ '000s) Savings from demand charges ($'000s) Total savings from battery ($'000s) Capital cost of battery that can be supported by the total savings in line t ($/kWh)
Assuming a 5% charging loss, the customer needs to purchase 400/0.95 = 421 kWh in order to charge the battery to 400 kWh Assuming a 5% discharging loss, the customer can extract only 400*0.95 = 380 kWh from the 400 kWh stored in the battery Cost of off-peak energy used to charge the battery
5 9
Avoided cost of on-peak energy that would have had to be purchased in the absence of a battery
13.15 365
(m*o-l*n)
4.80
p*q /1000
Assuming the battery is cycled every day of the year. Batteries have a 10-year life but also have a limitation on the number of cycles, typically between 2000 to 6000 per year. This model assumes a life of at least 3650 cycles.
23.60 28.40 399
Same as line j of Appendix B, which calculates the savings in demand charges from a reduction in peak load of 100 kW. r+s Uses the same approach as Appendix B to calculate the installed capital cost of a battery in $/kWh that can be supported by the total savings calculated in row "t."
Source: Moody's Investors Service
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Appendix D Estimated breakeven installed cost of a battery peaking plant in New York City without energy arbitrage Calculation of Battery System Costs
a
Size of system (MW)
b
Battery Installed Cost ($/KwH)
248.3
c
Depth of discharge discount and discharge loss
24%
d
Storage time (hours)
e f
Cost in $/kW Cost for 100 MW system ($ millions) Cost recovery factor
g h
Annual revenue required ($ millions)
100
The size of the system is the size of the peaking capacity it delivers. For illustration, this system is 100 MW. Any instant, this plant can deliver 100 MW of peaking capacity when called on. Variable in Moody's calculations designed to equate the cost of the battery, including capital recovery, to the capacity revenues available in the market. The installed cost includes permitting, land, interconnection, control systems, wiring and other non-battery costs. Since a battery is used to store energy, the capital cost of a battery is expressed in dollars per unit of energy stored, or $/kWh. By contrast, the capital costs of power generation plants are generally expressed in $/kilowatt of capacity. Also, the capital cost of the battery equipment should not be confused with the cost of electric energy used to charge the battery, which is typically expressed in cents/kWh or $/MWh. Only 80% of the battery's capacity can actually be used. Also, 5% of stored energy is lost when discharged. Accounting for both gives an effective delivered energy of 80%*95% = 76% of the capacity of the battery. Thus, in order to achieve a delivered amount of energy in each cycle of 400 MWh, the amount of energy that needs to be stored in the battery equals 421 MWh (due to 5% loss). This would require the designed storage capacity of battery to be 526 MWh (since 20% of the capacity is not usable). The CA ISO recently awarded a 100 MW contract to AES Corp. to build a battery peaking plant that has four hours of storage. We use that as our assumption.
4 1307 130.7
b*d/(1-c) e*100*1000
14.23% 18.60
NPV calculations assuming a 10-year life and 7% WACC. An investment of $1 million requires annual revenues of $0.14 million. f*g
Calculation of Revenue Available from the Capacity Market
i j
Capacity price in NYC ($/MW-day) Capacity revenue available for a 100 MW peaker ($ millions)
510 18.60
i*100*365/1000000
Capacity price for zone J in recent NYISO auction When line h equals line j, battery-based peaking plants will be viable as a merchant investment.
Source: Moody's Investors Service
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Appendix E Estimated breakeven installed cost of a battery peaking plant in New York City with energy arbitrage (continuing Appendix D calculations) k l m n o p q
r s t u
Roundtrip losses of the battery Energy into the battery (MWh) Energy available from the battery (MWh) Cost of input energy ($/ MWh) Price of on-peak power whose purchase is avoided by the battery ($/MWh) Savings per cycle ($ 000s) Cycles per year
Annual margin from energy arbitrage ($ millions) Capacity revenues ($ millions) Total revenues available for the battery ($ millions) Capital cost of battery that can be supported by the total revenues in line "t" ($/kWh)
10%
Same assumption as in Appendix C.
443
There will also be a 5% charging loss. As a result, in order to fill the usable capacity of 421 MWh in each cycle, 443 MWh needs to be purchased. Battery system is designed to deliver 100 MW for 4 hours, or 400 MWh. It is sized to store 421 MWh, so as to deliver 400 MWh after a 5% discharge loss. Cost of off-peak energy used to charge the battery
400 20 40
Wholesale price at which on-peak energy is sold. The important number is the difference between on-peak and off-peak prices.
7.14 200
(m*o-l*n)/1000
1.43
p*q /1000
Assuming 200 days of cycling in a year since market conditions or ISO dispatch instructions may not allow for daily cycling. Batteries have a 10-year life but also have a limitation on the number of cycles, typically between 2000 to 6000 through their life.
18.60 20.03 267.5
Same as line j in Appendix D above. q+r Uses the same approach as Appendix D to calculate the installed capital cost of a battery in $/kWh that can be supported by the total savings calculated in row "t."
Source: Moody's Investors Service
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Appendix F State incentive programs for energy storage Region
Program
Form of Subsidy
Activity thus far
FERC-regulated wholesale markets Arizona
Frequency and voltage regulation ancillary services Contracts, rebates
Improved compensation for “fast response” resources like batteries.
California
Mandate to procure 1,325 MW of storage by 2020 SGIP Incentives
Storage contract with utilities via RFP.
PJM and NY have ~104 MW and 28 MW of battery & flywheel storage, respectively. PJM, MISO, CAISO, NYISO, ISO-NE and SPP have all complied with Order 755. Tuscon Electric - 10 MW solicitation Arizona Public Service: 2 MW of DG solar + storage plus $1 million in rebates SCE has signed contracts for 325 MW
New York
Reforming the Energy Vision (REV)
Texas
Ancillary services market rules + utility investment
Hawaii
PPAs, tax credits
Oregon
Storage mandate
Maryland
Pilot projects
Washington
Grants
Illinois
Rate base
New Jersey
Grants
SGIP incentives for 6.8 MW of “behind the meter” storage. Reserved funding for another 85.5 MW Details being finalized. Broad reform of Plan to add 100 MW of efficiency and storage in NYC to offset utility business model. congestion and risk of Indian Point nuclear plant shutting down. Incentives at $2,100/kW. Rules similar to FERC rules. New ancillary market rules under consideration. No legislation Utility investment will need yet to support Oncor’s storage proposal. changes in Texas regulatory policy for transmission and distribution service providers. Contract with utilities for grid 11 grid storage pilot projects initiated. Looking to obtain up to storage projects; bills introduced for tax 200 MW in Oahu. credits for “behind the meter” storage. Bill to procure at least 5 MW in storage by 2020. Bill introduced to require PSC to implement pilot projects. Four projects received $14.3 million in Two 1 MW projects are operational grants from the state’s clean energy fund. Bill to enable Comed to invest $300 million in six micro-grids. Storage projects paired with renewable $2.9 million for 13 projects totaling 8.75 MW plants.
Sources: US Department of Energy Global Energy Storage Database; Greentech Media; Environment & Energy (E&E) Publishing
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Moody's Related Research Sector In-Depth: »
Batteries are coming but utilities won't go away, Jan 2015 (1001444)
»
Regulatory Response Looks to Stay Ahead of the Distributed Generation Curve, November 2014 (176775)
»
Cloudy Skies and Low Rates Shield Washington State Electric Utilities From Unfettered Rooftop Solar Growth, August 2014 (174242)
»
Regulatory Framework Holds Key to Risks and Rewards Associated With Distributed Generation, April 2014 (165944)
»
Rooftop Solar, Distributed Generation Not Expected to Pose Threat to Utilities, November 2013 (160080)
Issuer In-Depth: »
Arizona Public Service: Getting a Jump on Rooftop Solar Distributed Generation, May 2014 (169745)
Structured Finance Sector Comments: »
California's Utility Residential Rate Reform Increases Contract Risk in Outstanding Solar Securitizations, August 2015 (1007520)
»
Solar Securitization Is Emerging as an ABS Asset Class, January 2015 (SF393653)
»
Risks in Commercial Contracts Differ from Residential, June 2013 (SF333536)
To access any of these reports, click on the entry above. Note that these references are current as of the date of publication of this report and that more recent reports may be available. All research may not be available to all clients.
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Endnotes 1 Peak-shaving is when a customer uses energy stored in a battery to serve a portion of the customer's demand, instead of buying it from a utility. Fastresponse ancillary services include voltage and frequency regulation services with response times as fast as 10 minutes, which help maintain the stability of the grid. 2 The demand charges shown in Exhibit 2 are applicable to specific commercial and industrial (C&I) customer classes for each utility listed in Appendix A. These classes constitute a large share of the utility’s C&I customer base, generally providing at least 10%-15% of the utility’s total revenue. Thus, they are not special cases and represent a large market. 3 In our calculations (see Appendix D), current capacity prices are assumed to continue for the 10-year life of the battery. Also, we ignore operating costs other than the round-trip efficiency, or costs like property taxes (these would be low if the battery is at an existing site). 4 See Tesla Energy's website for pricing specifics. 5 See Tesla Energy's presentation at the 2015 EIA conference, dated June 15, 2015, slide 22, posted on the US EIA's website. 6 See US Energy Storage Monitor, Q1 2015: Executive Summary, May 2015, slide 9, published by Greentech Media and Energy Storage Association. 7 See the California Independent System Operator's website. 8 We have simplified these calculations by eliminating the consideration of whether roundtrip losses associated with charging/discharging batteries will necessitate a larger battery (and hence capital cost). As explained in the sidebar titled, “Battery Charge/Discharge Efficiency,” the Exhibit 2 calculations effectively assume that the customer’s peak demand is not at 100 kW for every minute of the four hours (a reasonable assumption for retail loads and hence for the peak-shaving application) and so the battery does not need to be sized up to account for discharge loses. Calculations in Appendix D, which models a battery as a peaking plant, incorporates the need to upsize the battery to accommodate roundtrip losses.
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Moody’s SF Japan K.K. (“MSFJ”) is a wholly-owned credit rating agency subsidiary of MJKK. MSFJ is not a Nationally Recognized Statistical Rating Organization (“NRSRO”). Therefore, credit ratings assigned by MSFJ are Non-NRSRO Credit Ratings. Non-NRSRO Credit Ratings are assigned by an entity that is not a NRSRO and, consequently, the rated obligation will not qualify for certain types of treatment under U.S. laws. MJKK and MSFJ are credit rating agencies registered with the Japan Financial Services Agency and their registration numbers are FSA Commissioner (Ratings) No. 2 and 3 respectively. MJKK or MSFJ (as applicable) hereby disclose that most issuers of debt securities (including corporate and municipal bonds, debentures, notes and commercial paper) and preferred stock rated by MJKK or MSFJ (as applicable) have, prior to assignment of any rating, agreed to pay to MJKK or MSFJ (as applicable) for appraisal and rating services rendered by it fees ranging from JPY200,000 to approximately JPY350,000,000. MJKK and MSFJ also maintain policies and procedures to address Japanese regulatory requirements.
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US REGULATED AND UNREGULATED UTILITIES: BATTERIES CHARGE UP FOR THE ELECTRIC GRID
MOODY'S INVESTORS SERVICE
INFRASTRUCTURE AND PROJECT FINANCE
AUTHORS Swami Venkataraman, CFA Toby Shea Tiago Ferreira
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US REGULATED AND UNREGULATED UTILITIES: BATTERIES CHARGE UP FOR THE ELECTRIC GRID
