EECS4460.183.11.21.pptx
Power System Management
EECS 4460/5460-901
Lecture #18
Utility Business Structures and Economics
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Recap: The Historical Power Plant Build
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Prior to the mid-1980s, power plant construction was supported by the state regulatory process
Recall the ratemaking fundamentals
As load tapered off, regulators were less inclined to support rate increases for new plants
Disallowances resulted from prudence reviews and “excess capacity”
PURPA (1978) began an era of non-traditional power plant resources
“To address the Energy Crisis and encourage small power producers and co-generators (QF’s – Qualifying Facilities)
Open access for transmission
State implementation
Utilities had “must buy” provisions
Power Plant Financing has Shifted
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States supported the merchant power plant concept by “restructuring”
Following the deregulation of airlines, telecommunications, railroads, etc.
“Free entry” for merchant plants entering the market
Large amounts of capacity shifted to merchant status - 35% of all U.S. generation by 2012; 50% for nuclear
In most cases, stranded costs were recovered
High reserve margins prevailed in most parts of the country
Many initial merchant power transitions utilized Purchase Power Agreements (PPA’s)
Bilateral agreements between generator and utility
Open access for transmission
State implementation
Plants sold as merchants – “white elephants”
Restructuring Continued Through the 1990s
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As the wholesale power developed, (not PPA’s), the pricing has been driven by natural gas
Historically, based on cost and heat rate, the ”last MWhr” produced was from natural gas plants
Price driven by the producer “at the margin”
Gas prices tripled during the first half of the 2000s
Merchant generation was highly profitable, fueled by $11/MMBtu gas, low-operating costs and previous stranded investment recovery
Some states “rolled back” deregulation
Many utilities had (and still have) both regulated and merchant generation
As gas prices have come down, so has the profitability of merchant generation
Restructuring Results Changed Dramatically in the 2000s; Then Again Recently
Today’s Challenge – the “Market Design”
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Deregulated markets are state by state
Bilateral Contracts (PPA’s)
Assured Revenue Stream
Energy (and Capacity) Markets
Subject to Market Design and Costs
Merchant Generation Today
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Today’s Competitive Market-Design Concepts
Energy Markets
Procure for day-ahead and real-time needs
Driven by the costs “at the margin”
Generally intended to recover variable resource costs
Capacity markets
Procure capacity needs for peak load requirements (PJM: in three-year forward period)
Generally intended to recover fixed resource costs
Ancillary Services
Procure services to maintain high levels of reliability
As a result of several years of regulation changes, today’s environment is completely different.
The basic intent of the competitive markets was to provide the same level of resources at a fair price to consumers as the regulated state construct, recognizing the economic benefit of combining a larger region’s energy needs to minimize over-supply.
The markets were designed so that the sum of all revenues from capacity, energy and ancillary services would be equal to the cost of new entry. This would ensure that accurate price signals would encourage investment in new generation when needed by the market.
Capacity markets were intended to provide for peak load requirements in a three-year future period while energy markets were intended to meet the needs of consumers on a day-by-day basis.
Since capacity is needed during the peak demand period, it should be priced to cover all fixed costs of investment.
These fixed costs and a proxy for pricing the capacity market are commonly referred to as NET Cost of New Entry.
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Akron, Ohio • June 12-13, 2014
Generation Leadership Meeting
Ancillary Services Support Reliability
Regulation and reserves
are primary products
Regulation covers
small mismatches
Reserves cover load
surges or loss of
generation
Less than 1% of price
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An Example of Load Following
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The Time Scale for Market Products
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Sample of PJM Market Components
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Merchant Generation Profitability in the Market
Traditional “Unregulated” Model:
Earnings = Revenues - Expenses
For Merchant Plants, revenues are from three sources:
Energy Market Prices @ $/MWhr
Capacity Market Price @ $/MW day
Ancillary Services @ $/MWhr
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Market Design Concepts
Conceptually, the entire process would assure that there is adequate
and reliable capacity, with margins, day-to-day
Conceptually, the entire process would assure that there are adequate
mechanisms to ensure new capacity is being built when needed
In areas where generation is unregulated, the financial hurdles
to build new plants have been challenging
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Recall from Lecture 10: LCOE for Dispatchable Technologies ($/MWhr)
| Capacity Factor (%) | Levelized Capital Cost | Levelized Fixed O&M | Levelized Variable O&M | Total LCOE | |
| Combined Cycle | 87 | 7.78 | 1.61 | 26.68 | 37.11 |
| Combustion Turbine | 10 | 45.41 | 8.03 | 132.38 | 194.87 |
| Advanced Nuclear | 90 | 50.51 | 15.51 | 2.38 | 69.39 |
| Geothermal | 90 | 19.03 | 14.92 | 1.17 | 36.40 |
| Biomass | 83 | 34.96 | 17.38 | 35.78 | 89.21 |
| Battery Storage | 10 | 57.98 | 28.48 | 23.85 | 119.84 |
| Coal | NB | NB | NB | NB | NB |
Total Includes Transmission Costs, excludes tax credits for Nuclear and Geothermal . Source: EIA February 2021 Update
For Units Entering Service in 2026
Recall from Lecture 10: LCOE for Non-Dispatchable Technologies ($/MWhr)
Total Includes Transmission Costs
Source: EIA 2021 Update For Units Entering Service in 2026
| Capacity Factor (%) | Levelized Capital Cost | Levelized Fixed O&M | Levelized Variable O&M | Total LCOE | Tax Credit* | LOCE w/ Tax Credit | |
| Wind, Onshore | 41 | 27.01 | 7.47 | 0.0 | 36.93 | -6.1 | 30.83 |
| Wind, Offshore | 44 | 89.20 | 28.96 | 0.0 | 120.52 | -12.9 | 107.62 |
| Solar, PV | 29 | 23.52 | 6.07 | 0.0 | 32.78 | -14.3 | 18.48 |
| Solar with storage | 28 | 31.13 | 13.25 | 0.0 | 47.67 | -14.3 | 33.37 |
| Hydro | 55 | 38.62 | 11.23 | 3.58 | 55.26 | NA | 55.26 |
*Current tax credits (ITC and PTC) shown – most expire before 2026, but will likely renew
Margin
Margin
Nuclear Fleet Revenues, Costs & Margins Three Scenarios Illustrating Industry Averages
Year A Lower Capacity and
Lower Energy Prices
Year B Medium Capacity and Higher Energy Prices
Year C Higher Capacity and Lower Energy Prices
$22
$1,104
$782
$232
$315
Energy Capacity Fuel O&M CapEx Margin
$44
$1,419
$183
$1,104
0
200
400
600
800
1000
1200
1400
Margin
$133
($ Millions)
($204)
$782
$232
$315
($44)
$782
$232
$315
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Series 1 Revenue Cost 1419 232 Series 2 Revenue Cost 44 782 Series 3 Revenue Cost 0 315 Column1 Revenue Cost 20
Series 1 Revenue Cost 1104 232 Series 2 Revenue Cost 183 782 Series 3 Revenue Cost 315 Series 4 Revenue Cost
Recent Coverage of Exelon’s Illinois Plants*
*S&P Global Market
Intelligence
21 Sept 2020
Prices Vary Among the Regions
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Accounting for patterns of load, generation, and the physical limits of the transmission system
Usually caused by congestion
Called Locational Marginal Pricing (LMP’s)
For example, the New England ISO has over 1000 pricing nodes (locations) on the bulk power grid
LMP’s are a “load zone” weighted average of all nodes within a zone
LMP’s are typically both day-ahead and real-time
Wholesale Prices Also are a Function of Location on the Grid
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LMP’s: A MISO Example (2011)
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A typical day in the ERCOT market (3/11/21)
Wholesale Prices with “Regional Spikes in 2018
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Recap: The ISO’s and RTO’s
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On Building New Generation ...
Who pays and who makes money?
In the Regulated Model:
Demonstrated need
Least cost plan/prudent decisions
Rate treatment
Shareholders earn return
Customers pay through rates
In the Merchant Model:
Investors pay and earn return on investment
Customers pay through charges
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Business Structures and Economics
(Continued)
Renewable Generation
Business Structures
Utility Financial Profiles
Current Utility Strategies
Technologies
Business and Financial
Next Lecture(s)
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