Dr. Daniel Matuszak

Clean Coal and Carbon Management

Office of Fossil Energy

U.S. Department of Energy

May 24, 2016

Future Electricity Markets

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1. Foster competition in wholesale power markets by facilitating entry of new generators.

2. Guard the consumer from exploitation by non-competitive power companies.

FERC’s national policy

Competition Regulation

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Infrastructure, key forces that led to restructured markets

Generation Transmission Distribution

vertically integrated utility (originally) Regulated Market

1978 – PURPA. Public Utility Regulatory Policies Act was first to allow competition.

Required utilities to purchase from Qualifying Facilities at avoided cost.

1992 – Energy Policy Act. Promotes competition, provides incentives.

Expanded FERC authority, e.g. allowed ordering a transmitting

utility to provide service and transmitting capacity to an

applicant.

1996 – FERC Orders 888/9. Forced transmission facilities to provide

services on the open market. Established “OASIS”, allowing

customers to schedule and reserve capacity on the regional energy

grids.

Ownership:

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Major ISO/RTO balancing areas

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Remainder of the country

Locally managed by Balancing Authorities (BAs)

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NERC regions, Balancing Authorities

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Energy Imbalance Market started Y14

• Drive to connect the disparate balancing authority areas

• Motivation to make the most of variable generation resources

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Characteristics of markets

Deregulated Energy-only

• ERCOT

Deregulated Energy & Capacity

• ISO-NE

• NYISO

• PJM

Hybrid

• CAISO

• MISO

• SPP

Traditional Regulated

• SERC

• FRCC

• WECC

Stay tuned: the Quadrennial Energy Review (QER 1.2) is in progress and

includes a comprehensive description of markets.

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Forces/themes acting on the system

Generation Transmission Distribution

Clean Power Plan

Paris, 450ppm target

SupportsRestricts

PTC & ITC

State RPS

Demand Response

e-

DER

Microgrids

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Future Capacity Changes

Future capacity additions are mostly solar, wind, and “flexible” capacity (i.e.,

demand response, battery storage, and fast-ramping gas)

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Generation Stack$/M

Wh

mcpearly

early demand

peak demand

mcppeak

Everyone that offers less than the

Market Clearing Price (mcp) shall

generate and receive the mcp as

compensation.

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Effect of a hypothetical RE addition$/M

Wh

mcpearly

early demand

peak demand

mcppeak

original

original

+20GW of RE to serve as an example of short-run impact

More renewable energy (RE)

reduces everyone’s revenue

by suppressing the Market

Clearing Price (mcp).

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Effect of changing generation mix

Retirements of coal plants attributable to the shift in the curves from Y10-12.

Loss of coal plants as a result

of competition with gas plants

makes price spikes more

likely during peak hours.

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Given the projected capacity additions, the day-ahead and real-time energy markets are going to be less welcoming for existing and new coal plants (without an increase in natural gas prices).

New markets are need that monetize coal’s value proposition – not just selling commodity electrons, but providing stability, etc…

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Capacity markets – still need helpPURPOSE: incentivize the buildout of new generation so that energy can be made available during the most demanding times.

ISSUES: • Generation is not being built, or it’s not being built where it is

needed most (i.e. to optimize employment and investment).

• Previously, inexpensive MISO capacity flowed into PJM and depressed prices. Import limits were then set in PJM.

• Minimum offer price rules are deemed unfair and keep the capacity auction prices artificially high.

• Too much price volatility. Capacity revenues are highly discounted by institutional investors.

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Volatility in capacity auction prices

Unstable revenues from capacity auctions leads to 50-70% discount rates

when evaluated by institutional investors.

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States also discounting capacity auctions: Maryland CfD’s program

(Rule of thumb applied w.r.t. FERC’s policy #1: a successful CfDprogram if exploited could create barriers for entry of new generators.)

ISSUE: Maryland lost confidence that PJM’s capacity auctions could incent new generation in Maryland. Launched CfD program.

ACTION: a 20-year contract for differences between a new generator and a Load Serving Entity, which passes costs to customers through retail rates.

RESULT: SCOTUS decided on Hughes vs. Talen on April 19. Courts judged that this conflicts with FERC policies and jurisdiction, “has the potential to seriously distort the PJM auction price signals”.

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AEP & FirstEnergy: “Electric Security Plan” in Ohio

ISSUE: Concerns over challenged coal and nuclear plants that support the local economy and provide fuel diversity.

ACTION: Affiliate PPAs were approved by PUCO. FERC intervened and blocked the PPAs. FirstEnergy just resubmitted a modified plan to PUCO that would place a surcharge on retail rates (based on estimated costs instead of variable wholesale prices).

RESULT: TBD (will it bypass FERC review?)

(Could the successful approach be exploited to create barriers for the entry of new generators? Could the approach be used to exploit consumers by non-competitive power companies?)

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Relevant problems with current markets

Current markets do not provide enough incentive for diversifying the generation fleet. There is zero incentive for low-carbon power: nuclear, coal w/ CCS.

Bilateral markets are seeing a reduction in the rate of PPAs signed. Natural gas plants, at least, have more incentive to remain in the spot energy markets under current conditions.

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“CL&P Electric Rates To Jump 26 Percent Starting In January [‘15]”

SOURCE: http://www.courant.com/business/hc-electric-rates-increase-2015-

20141107-story.html

“The unwelcome spike in electricity generation prices is

a direct result of bottlenecks in natural gas pipelines.”

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Alisso Canyon: worst leak in US History

• Southern California could have up to 14 days of service interruptions this summer to millions of customers.

• Various mitigation efforts are underway in an Action Plan.

• This highlights the value of fuel diversity for reliability and resilience.

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Bilateral market opportunity

Buyers and sellers that could not close on a bilateral agreement felt that the primary obstacle was different expectations regarding future prices and different levels of willingness to accept risk.

Walter Brockway at Alcoa: “We found no supplier willing to discuss supplying us with anything other than electricity priced to reflect peak load generation, as well as placing on us all the risk of transmission congestion.”

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Cost of Uncertainty Example

Max = 316.19Min = 4.32Median = 32.10 Average = 36.37

Contract Price for one month of

service giving the contract’s seller a

Reward/Risk ratio of 2 equals 40.89

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Innovation in futures markets indicates a market need to reduce uncertainty

Products include futures contracts at nodes up to 5 years out

The incumbents offer contracts at the hubs.

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Long term outlook

Energy is required to sustain growth. More opportunities for

bilateral contracting can be expected.

Daniel.Matuszak@hq.doe.gov