NRRI: PURPA - Options for States
Laura Chappelle, Counsel
Varnum Law
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The Public Utilities Regulatory Policy Act of 1978
(“PURPA”) – A Michigan Perspective
1) PURPA Background
1) Michigan Public Service Commission/Legislative PURPA
• PURPA Technical Advisory Committee
• SB 437
2) IPPC- MI: Importance of PURPA to existing QFs, 20 MW and
under
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PURPA Title II Compliance Manual
March 2014
Prepared by Robert E. Burns and
Kenneth Rose
Click here for link to PURPA Title II Compliance Manual
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PURPA Background - Historical Context
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PURPA was passed as part of a package of legislation known as the
National Energy Act that was intended to address the ongoing “energy
crisis” of the time.
ƒ
Among other goals, PURPA was intended to encourage conservation,
reliability, and efficiency in the delivery and generation of electricity, and do
so with “equitable retail rates for electric consumers.”
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The primary concerns at the time was the increasing amounts of imported
oil and the national security risks that imposes.
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PURPA Qualifying Facilities
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PURPA Qualifying Facilities (QFs) are defined as qualifying cogeneration facilities or
qualifying small power production facilities that have a right to be served by, and sell
to, their host electric utilities at the utility’s “avoided cost.”
ƒ
Cogeneration facilities are those which produce electric energy and steam or forms of
useful energy (such as heat) which are used for industrial, commercial, or cooling
purposes (aka, CHP)
¾ no maximum size limitation for PURPA qualification
¾ EPAct 2005 prohibits PURPA machines, emphasizing that useful energy must
be produced
ƒ
Small power production facilities are facilities which use biomass, waste, or
renewable resources including wind, solar energy and hydro, to produce electric
power; which, together with other facilities at the same site, have a capacity equal to
or less than 80 MW.
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Original PURPA “Must Purchase” Obligation
ƒ
The “Must Purchase Obligation” applies to all electric utilities (not
transmission service area, but utility territory), including IOUs, municipals,
rural cooperatives, PUDs, water districts, the TVA, and each federal power
marketing authority, unless FERC grants a waiver.
ƒ
FERC requires that host utilities must purchase at rates equal to the host
utility’s full avoided cost: “the incremental cost to the electric utility of electric
energy or capacity or both which, BUT FOR the purchase from the QF or
QFs, such utility would generate itself or purchase from another source”
(CFR sec. 292.101(b)(6)).
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EPAct 2005 Changes the “Must Purchase” Obligation
ƒ
EPAct 2005 provided a new section (210(m)) that requires FERC to excuse
host utilities from entering into new purchase or contract obligations if there
is access to a sufficiently competitive market for a QF to sell its power.
ƒ
Specifically, there is no utility must purchase obligation if FERC finds that
the QF has nondiscriminatory access to:
¾ (1) independently administered, auction‐based day ahead and real
time wholesale markets and wholesale markets for long‐term sales of
capacity and energy (e.g., MISO, PJM, ISO‐NE, NYISO), or
¾ (2) an RTO with competitive wholesale markets, or
¾ (3) wholesale markets that are comparable to (1) or (2)
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EPAct 2005 Changes the “Must Purchase” Obligation
ƒ
FERC by rulemaking in Order 688 determined that MISO, PJM, ISO‐NE,
and the NY‐ISO provide wholesale markets which meet the statutory criteria
for member utilities to qualify for relief from the mandatory “must purchase”
obligation.
ƒ
Order 688 also created a rebuttable presumption that QFs of more than 20
MW have non‐discriminatory access to at least one of these competitive
markets.
ƒ
FERC did not terminate the must purchase obligation
¾ electric utilities must file applications for relief and QFs in the above
markets may, under the rule, rebut the presumption of access
because of operational characteristics or transmission constraints
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QFs 20 MW or below
ƒ
FERC Order No. 688 created the rebuttable presumption that QFs with a net capacity
of 20 MW or below do not have nondiscriminatory access to markets sufficient to
warrant termination of the mandatory purchase obligation.
ƒ
The Commission found that some QFs may not have nondiscriminatory access to
markets due to their small size.
ƒ
To overcome this rebuttable presumption that smaller QFs lack nondiscriminatory
access to markets, an electric utility must demonstrate on a QF by QF basis that
each small QF has in fact nondiscriminatory access to the relevant wholesale
markets.
ƒ
Order No. 688 placed the burden of proof on the electric utility to demonstrate that a
small QF has nondiscriminatory access to the markets of which the electric utility is a
member (MISO or PJM, for Michigan).
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How is “Avoided Cost” defined?
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Not the same as incremental system cost of the utility—that is, utility’s
system lambda or energy component of a specific LMP
¾ that would be short term energy only
ƒ
Should reflect the incremental cost of the utility to generate or purchase
itself without the QF or QFs – over the relevant utility planning horizon
¾ that is, long term that takes into account capital expenditures
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Avoided Cost determination methods
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Prior to EPAct 2005, states and non‐regulated utilities always determined avoided
cost, either through administratively determining them or through market‐based
methods.
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Pre‐EPAct 2005 methods of calculating administratively determined/market‐based
avoided costs (still used in regulated states):
¾ Proxy plant method
¾ Peaker method
¾ Partial displacement differential revenue requirement method
¾ Fuel index rates
¾ Auction/RFP Rates
ƒ
Other methodologies include:
¾ Market-based Pricing
¾ For QFs with access to competitive markets
¾ IRP-based Pricing
¾ Relies on state IRP to predict future needs and costs that will be avoided
by QF generation (may also apply other methodologies).
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Avoided Cost (continued)
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Proxy Resource Method: the cost of the host utility’s next planned addition,
typically a CCGT.
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Peaker Method: the value of the QF operated as a peaker.
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Partial Displacement Differential Revenue Requirement: System Revenue
Requirement w/o QF – System Revenue Requirement w/ QF.
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Fuel Index Rates: Uses a variable monthly gas index price plus on‐peak
peaker capacity cost adder.
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Avoided Cost (continued)
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Auction/RFP Rates: The utility issues an RFP; plants are selected according
to price and other explicit factors; successful bidders receive capacity
contracts; unsuccessful QF bidders may sell energy, but not capacity.
ƒ
The avoided costs paid for purchases from QFs can be based upon
estimates of avoided costs over the specified term of a contract or legally
enforceable obligation – therefore, the rates for purchase can differ from the
avoided cost at the time of delivery
¾ alternatively, rates for “as available” power can be based on the time
of delivery
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Standard Offer Rates for Purchases from QFs
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FERC relies heavily on state commissions and non‐regulated utilities to
assure that the host utility pays a QF its full avoided costs or a negotiated
rate for purchased power.
ƒ
FERC regulations require that states and non‐regulated utilities have
standard offer rates for purchases from QFs with design capacity of 100 kW
or less.
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State commissions and non‐regulated utilities may also have standard offer
rates for purchases from QFs with a design capacity of over 100 kW.
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While nothing in FERC’s regulations requires any electric utility to pay more
than its avoided costs for purchases, standard offer rates may differentiate
among QFs using various technologies on the basis of the supply
characteristics of the different technologies.
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Michigan PURPA Background: MPSC/Legislative Actions
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Michigan has not set avoided rates pursuant to the Public Utility Regulatory Policies
Act (PURPA) of 1978 since the early 1980s.
ƒ Most Michigan Qualified Facilities (QFs) have been under long-term contracts
with electric utilities since that time.
ƒ 45 contracts between MPSC regulated utilities, with varying expirations from May
2017 – to 2039.
ƒ Avoided cost methodology, in general, based on a proxy coal plant.
ƒ
On November 4, 2015, several Independent Power Producers brought a complaint
against Consumers Energy alleging violations of PURPA, as implemented by the
MPSC (Case No. U-17981).
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On October 27, 2015, the MPSC directed the Electric Reliability Division to form a
Technical Advisory Committee to consider updated PURPA avoided cost rates.
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MPSC: PURPA Contracts by Technology Type
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MPSC: PURPA Contracts by Contract Capacity
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MPSC PURPA TAC
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Commission Staff held five inclusive meetings, from Dec. 2015 to March 2016, to
accomplish four objectives:
ƒ Develop an on-going, routine Commission administrative process for determining
avoided cost for 20 MW and smaller PURPA projects;
ƒ Research avoided cost methodologies;
ƒ Present recommendations for the administrative process and methodologies in a
final PURPA TAC Report; and
ƒ If there is not consensus, include each recommended methodology in the final
PURPA TAC Report.
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MPSC Staff Final PURPA TAC Report
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Commission Staff issued its final Report on April 8, 2016.
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MPSC PURPA Technical Advisory Committee Final Report
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MPSC PURPA TAC Website
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No consensus was reached on preferred methodology or capacity/energy components.
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Full, administrative, contested case process to determine methodologies and inputs.
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Staff’s Recommended Methodology - Modified Proxy Plant Methodology:
ƒ Utilizes a combination of the proxy unit and market-based pricing methodologies
ƒ Capacity Component:
ƒ Proxy uses a natural gas combustion (CT) value, similar to MISO’s CONE
ƒ Paid to the QF on a monthly basis, rather than spread over MWh of generation
ƒ A ratio (Effective Load Carrying Capability (ELCC), used within MISO) is applied to
accurately value capacity from a variety of differing generation types.
ƒ Fixed Charge Rate (FCR) of 9.3%
ƒ 10-year capacity planning horizon
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MPSC Staff Final Report – Capacity Component
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Capacity Payments
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Full Avoided Cost Capacity Rate
Standard Rate for existing QFs and QFs that are 5 MW and smaller
Three Capacity Payment Options for new QFs larger than 5 MW and no
larger than 20 MW:
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Full Avoided Cost capacity rate discounted for the ELCC for intermittent resources,
regardless of the utility’s capacity needs;
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Full Avoided cost capacity rate discounted for the ELCC for intermittent resources until the
utility demonstrates no additional need for capacity over 10-year planning horizon; or
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QF receives capacity payments, regardless of utility capacity needs, at 75% of the avoided
capacity rate, discounted for the appropriate ELCC for intermittent resources.
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MPSC Staff Final Report – Energy Component
•
MPSC Staff recommends three options for an energy component:
•
Utilize LMP market-based rates
•
Utility forecasts LMPs over the contract period and pays for energy on an hourly
or monthly basis according to the forecast
•
Forecasted variable costs of an NGCC as calculated in the MPSC Staff’s
Transfer Price
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Possible Legislative Directive
• SB 437 contains a new Section 6v, requiring, in part, that the Commission
conduct a contested case proceeding at least every 5 years, to reevaluate
the procedures and rate schedules, including avoided cost rates, for Michigan
QFs 20 MW and under.
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Independent Power Producers Coalition – MI
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IPPC-MI: group of MI IPPs/QFs, 20 MW and smaller, that operate hydroelectric, biomass, wasteto-energy and landfill gas facilities.
•
IPPC-MI members are legacy facilities on utility systems providing long-term energy and capacity
needs to their local communities via interconnections with host utilities.
•
Quantifiable benefits of IPPC-MI facilities include:
• Reliable, renewable baseload capacity;
• Local/state economic development benefits, including:
• Full and part-time employment opportunities
• Meaningful tax contributors
• Research facilities
• Tower Kleber hydroelectric power plant maintains a partnership with the Michigan
DNR and Michigan State University in the development and operation of the Black
River Lake Sturgeon Hatching Facility.
• Recreational benefits
• Stabilization of lake levels
• Ecological benefits
• Forest stewardship
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IPPC-MI PURPA Positions
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Must Purchase/Sell Obligation for QFs 20 MW and smaller must be maintained
•
Rebuttable presumption/requirement of waivers must be maintained
•
“Non-discretionary access to market” is an important qualifier that must be retained
•
Simply being within an RTO does not mean that QFs have “non-discriminatory access” to markets;
•
“Can’t get through the backdoor what you can’t get through the front.”
• Utilities must have waivers for QFs 20 MW and under before state Commissions require “market”
options
•
The requirements to provide supplemental, standby, backup and maintenance power to a QF via
nondiscriminatory rates and terms of service must be ensured by state Commissions.
•
State Commissions must continue to ensure that rates meet PURPA’s original directives:
ƒ “must equal” the utility’s “full avoided costs” and “must not exceed the incremental cost to the electric utility,”
•
“just and reasonable” to the electric customers and in the “public interest” and
•
shall “not discriminate” against cogenerators or small power producers
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Rates cannot be set above a utility’s full avoided cost, but neither can they be set below.
•
Contractual terms must continue to be fair and financeable to a QF, similar to utilities’ need for long-term
rate recovery assurances for new capacity additions.
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Questions/Contact
Questions?
Laura Chappelle
616 / 336-6920
[email protected]
www.varnumlaw.com
Important Notice: This presentation has been prepared by Varnum LLP for informational purposes only and does not constitute legal advice.
Copyright © 2016 Varnum LLP. All rights reserved.
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