[Senate Hearing 111-44]
[From the U.S. Government Publishing Office]
S. Hrg. 111-44
NET METERING
=======================================================================
HEARING
before the
SUBCOMMITTEE ON ENERGY
of the
COMMITTEE ON
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE
ONE HUNDRED ELEVENTH CONGRESS
FIRST SESSION
TO
RECEIVE TESTIMONY ON NET METERING, INTERCONNECTION STANDARDS, AND OTHER
POLICIES THAT PROMOTE THE DEPLOYMENT OF DISTRIBUTED GENERATION TO
IMPROVE GRID RELIABILITY, INCREASE CLEAN ENERGY DEPLOYMENT, ENABLE
CONSUMER CHOICE, AND DIVERSIFY OUR NATION'S ENERGY SUPPLY
__________
MAY 7, 2009
Printed for the use of the
Committee on Energy and Natural Resources
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50-240 WASHINGTON : 2009
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COMMITTEE ON ENERGY AND NATURAL RESOURCES
JEFF BINGAMAN, New Mexico, Chairman
BYRON L. DORGAN, North Dakota LISA MURKOWSKI, Alaska
RON WYDEN, Oregon RICHARD BURR, North Carolina
TIM JOHNSON, South Dakota JOHN BARRASSO, Wyoming
MARY L. LANDRIEU, Louisiana SAM BROWNBACK, Kansas
MARIA CANTWELL, Washington JAMES E. RISCH, Idaho
ROBERT MENENDEZ, New Jersey JOHN McCAIN, Arizona
BLANCHE L. LINCOLN, Arkansas ROBERT F. BENNETT, Utah
BERNARD SANDERS, Vermont JIM BUNNING, Kentucky
EVAN BAYH, Indiana JEFF SESSIONS, Alabama
DEBBIE STABENOW, Michigan BOB CORKER, Tennessee
MARK UDALL, Colorado
JEANNE SHAHEEN, New Hampshire
Robert M. Simon, Staff Director
Sam E. Fowler, Chief Counsel
McKie Campbell, Republican Staff Director
Karen K. Billups, Republican Chief Counsel
------
Subcommittee on Energy
MARIA CANTWELL, Washington, Chairman
BYRON L. DORGAN, North Dakota JAMES E. RISCH, Idaho
RON WYDEN, Oregon RICHARD BURR, North Carolina
MARY L. LANDRIEU, Louisiana JOHN BARRASSO, Wyoming
ROBERT MENENDEZ, New Jersey SAM BROWNBACK, Kansas
BERNARD SANDERS, Vermont JROBERT F. BENNETT, Utah
EVAN BAYH, Indiana JIM BUNNING, Kentucky
DEBBIE STABENOW, Michigan JEFF SESSIONS, Alabama
MARK UDALL, Colorado BOB CORKER, Tennesse
JEANNE SHAHEEN, New Hampshire
Jeff Bingaman and Lisa Murkowski are Ex Officio Members of the
Subcommittee
C O N T E N T S
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STATEMENTS
Page
Bingaman, Hon. Jeff, U.S. Senator From New Mexico................ 2
Brown, Garry A., Chairman, New York State Public Service
Commission, on Behalf of the National Association of Regulatory
Utility Commissioners.......................................... 6
Cantwell, Hon. Maria, U.S. Senator From Washington............... 1
Cook, Christopher, Managing Director, Sunworks, LLC, Dunn Loring,
VA............................................................. 10
Kelly, Kevin A., Director, Division of Policy Development, Office
of Energy Policy and Innovation, Federal Energy Regulatory
Commission..................................................... 3
Kowalczyk, Irene, Director, Energy Policy and Supply,
Meadwestvaco Corporation, Glen Allen, VA....................... 20
Weiss, David, President and COO, Energy Services Division, Pepco
Energy Services................................................ 17
APPENDIXES
Appendix I
Responses to additional questions................................ 39
Appendix II
Additional material submitted for the record..................... 55
NET METERING
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THURSDAY, MAY 7, 2009
U.S. Senate,
Subcommittee on Energy,
Committee on Energy and Natural Resources,
Washington, DC.
The subcommittee met, pursuant to notice, at 2:36 p.m., in
room SD-366, Dirksen Senate Office Building, Hon. Maria
Cantwell presiding.
OPENING STATEMENT OF HON. MARIA CANTWELL, U.S. SENATOR FROM
WASHINGTON
Senator Cantwell. This hearing will come to order.
Today's hearing is to discuss a wide range of policies
critical to transitioning our Nation to a cleaner, more
diverse, and more distributed 21st century energy system.
While most of the discussion in this committee recently has
focused on siting of high voltage transmission lines, a number
of members of this committee, including myself and Chairman
Bingaman, are developing legislative proposals intended to
address longstanding barriers that are inhibiting rate payers
in the Nation from reaping the benefits of distributed
generation technologies.
In particular, at today's hearing we will focus on national
net metering and interconnection standards, measures to address
peak demand, the state of distributed generation technology,
and the need to infuse intelligence into the Nation's
electricity grid to increase efficiency, reliability, and to
allow for a more accurate price signal.
As we will hear from today's witnesses, distributed
generation can allow for a wide range of untapped resources to
come online and to meet our Nation's growing energy demands and
reduce our carbon footprint. With the right policies in place,
homes and businesses across the country will be able to own
electricity from solar panels on their roofs or maybe even hook
up a generator in a nearby stream or farms will be able to use
their animal waste to produce electricity, turning a disposal
headache into a new source of income.
The paper and wood products industries will be able to use
their leftover woody biomass to create new sources of carbon-
neutral electricity.
Manufacturing industries will be able to invest in a
combined heat and power technology generation electricity from
process heat that otherwise is just released into the
atmosphere.
Communities will be able to keep more revenue and jobs
locally, and homeowners will be empowered to generate their own
electricity.
So the question before us is, if there are so many direct
and indirect benefits from distributed generation, why is so
little coming online relative to the potential and national
need?
While a number of States are pushing the envelope, the
resulting patchwork of regulations and standards has stifled
development and slowed what would be a robust source of
interstate commerce.
So there may be a role for well thought-out Federal
legislation which is mindful of the historic jurisdictions of
State regulatory commissions, but still provides the certainty,
incentives, and guidance we need to make distributed generation
a reality.
I appreciate that this is a very tricky balance. One of the
first pieces of legislation I introduced, coming into the
Senate in 2001, was a national net metering and interconnection
standard. But as we tried for several years to push that bill
forward, we continually ran into opposition from stakeholders
who benefited from the status quo. Hopefully now with a greater
appreciation of distributed generation and the urgent need to
bring clean energy alternatives online, we will be able to
incorporate the policies we need in the comprehensive energy
bill that the committee is working on.
I know that my colleague, the chairman of the full
committee, is here, and I wondered if he wanted to make any
opening statements.
STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW MEXICO
The Chairman. Thank you very much for chairing this hearing
and thanks to all the witnesses for being here.
This is an issue that I think is very important for us to
try to come to grips with. We thought in the 2005 energy bill
that we had dealt with this to a significant extent, but
obviously, I think history has demonstrated that we did not do
all that needed to be done. So I think this hearing should be
enlightening and help us to understand what additional steps we
can take to facilitate energy production from all sources,
including a lot of these small technology sources that are
becoming more and more capable and cost-effective.
So thank you again for having the hearing.
Senator Cantwell. Thank you, Senator Bingaman.
Now the Energy Subcommittee of the full Energy and Natural
Resources Committee will hear from our witnesses. We are joined
today by Kevin Kelly, who is the Director of the Division of
Policy Development within the Federal Energy Regulatory
Commission. Thank you for being here today.
Garry Brown, Chairman of the New York State Public Service
Commission. Thank you, Mr. Brown, or being here.
Mr. Chris Cook, Managing Director and Co-Founder of
Sunworks from Dunn Loring, Virginia. Thank you for being here.
David Weiss, President and COO of the Energy Services
Division for Pepco Energy Services. You may have had to travel
the least to be here, but thank you anyway for being here.
Irene Kowalczyk--thank you very much for being here--is the
Director of Energy Policy and Supply from MeadWestvaco Company
from Glen Allen, Virginia.
So thank you all for being here, and we will start with
you, Mr. Kelly. If you could, we certainly will take longer
statements from the witnesses, but if you can keep it to 5
minutes, that would be great and that will allow members an
opportunity to ask questions.
Mr. Kelly.
STATEMENT OF KEVIN A. KELLY, DIRECTOR, DIVISION OF POLICY
DEVELOPMENT, OFFICE OF ENERGY POLICY AND INNOVATION, FEDERAL
ENERGY REGULATORY COMMISSION
Mr. Kelly. Yes. Good afternoon, Madam Chairman, Senator
Bingaman. Thank you for the opportunity to speak here today.
My name is Kevin Kelly. I am the Director of the Division
of Policy Development in FERC's newly minted Office of Energy
Policy and Innovation. It just started this week. I appear
before you today as a staff witness, and my testimony is not
necessarily the views of the commission or any individual
commissioner.
I will describe the commission's rules for interconnecting
small generators and its few precedents regarding net metering
and distributed generation.
Obviously, a generator must interconnect to a utility's
transmission or distribution system in order to make its energy
available to customers. The commission regulates certain
generator interconnections under the Federal Power Act. It has
established standard interconnection procedures for both large
and small generators.
FERC's Order No. 2006 established procedures for processing
interconnection requests specifically for small generators. It
provides three ways to evaluate an interconnection request. One
may be used by any small generator, defined as a generator
under 20 megawatts in size. The second is for a generator no
larger than 2 megawatts, and the third is a very simple process
for most very small generators no larger than just 10
kilowatts. All three processes ensure that small generator
interconnections will be studied faster than interconnections
for large generators, and they also ensure that the
interconnections will not endanger the safety of electrical
workers or harm the reliability of the transmission system.
The commission's interconnection standards apply only to
the public utilities FERC regulates and, with limited
exceptions, only to interconnections to transmission facilities
in interstate commerce as opposed to local distribution
facilities.
However, the commission would regulate transmission
interconnections to certain distribution facilities that serve
a FERC jurisdictional function. For the commission's
interconnection rules to apply, the generator must seek
interconnection to a facility already subject to a FERC-
approved open access transmission tariff and intend to make
wholesale sales of energy.
Now, because FERC lacks jurisdiction over most local
distribution facilities, the commission acknowledged in this
rule the limited applicability of this rule for small
generators. However, by developing a national interconnection
rule through a process that sought industry consensus and by
adopting many measures recommended by the National Association
of Regulatory Utility Commissioners, FERC sought to harmonize
State and Federal interconnection practices. FERC intended to
promote consistent nationwide interconnection rules to help
remove roadblocks to the interconnection of small generators.
The commission expressed its hope that States would use FERC's
rule as they formulate their own interconnection rules and
thereby have a de facto national standard for small generator
interconnection.
The same jurisdictional limitations apply to
interconnections for net metering and for other distributed
generation.
Net metering allows retail customers that have their own
generation to get a retail rate credit for delivering their
power output to their local utility. Net metering rules are
subject to State or local rate jurisdiction unless a FERC
jurisdictional wholesale sale of power occurs. FERC has held
that such a wholesale sale does occur under net metering but
only if the generator produces more energy than it needs for
itself and makes a net sale of electric energy to a utility
over an applicable billing period.
If there is a net sale of energy, the net metering
generator or any other distributed generator must comply with
the requirements of the Federal Power Act for wholesale power
sales unless that generator happens to be a qualifying facility
under PURPA, in which case the net sale must be consistent with
PURPA and the commission's PURPA regs.
Thank you and I will be happy to answer any questions.
[The prepared statement of Mr. Kelly follows:]
Prepared Statement of Kevin A. Kelly, Director, Division of Policy
Development, Office of Energy Policy and Innovation, Federal Energy
Regulatory Commission
Introduction and Summary
Madam Chairman and Members of the Subcommittee, thank you for the
opportunity to speak here today.
My name is Kevin Kelly, and I am the Director of the Division of
Policy Development in the Office of Energy Policy and Innovation of the
Federal Energy Regulatory Commission (FERC or Commission). I appear
before you as a staff witness; my testimony does not necessarily
represent the views of the Commission or any individual Commissioner.
My testimony briefly describes the Commission's rulemakings related
to generator interconnection, with emphasis on the rule addressing the
interconnection of small generators. It also describes the Commission's
limited precedent regarding ``distributed generation'' and ``net
metering.''
Generator Interconnection
Before a generator can make its energy available to wholesale or
retail customers, it must interconnect to a utility's transmission or
distribution system. A generator interconnection is the physical and
contractual means by which a generator connects to--and operates as
part of--a transmission or distribution system.
The Commission regulates certain generator interconnections
pursuant to its authority under sections 205 and 206 of the Federal
Power Act (FPA) to regulate the rates, terms, and conditions of
transmission in interstate commerce by public utilities and pursuant to
specific interconnection authorities granted to the Commission in
sections 202(b) and 210 of the FPA. Interconnection authority under
sections 202(b) and 210 is exercised on a case-by-case basis. However,
pursuant to its authority to prevent undue discrimination under FPA
sections 205 and 206, the Commission has acted generically to establish
standard interconnection procedures to be included in the open access
transmission tariffs of public utilities. The interconnection
procedures minimize opportunities for undue discrimination and expedite
the development of new generation. They also strike a reasonable
balance between the competing goals of uniformity and flexibility while
ensuring safety and reliability.
The Commission established its standard terms and conditions for
generator interconnections to the transmission system in three
rulemakings. The rulemakings followed consensus-building discussions
among industry stakeholders regarding the best practices to include in
the interconnection process. Order No. 2003, issued in July 2003,
addressed large generators--that is, generators greater than 20
megawatts in size. Order No. 661, issued in June 2005, addressed
technical issues particular to the interconnection of large wind
resources. And Order No. 2006, issued in May 2005, addressed small
generators--that is, generators less than or equal to 20 megawatts in
size.
Small Generator Interconnection
Order No. 2006 established the procedures for processing and
studying interconnection requests for small generators. It provides
three ways to evaluate an interconnection request. First, there is a
default Study Process that could be used by any Small Generating
Facility. Second, there is a Fast Track Process for a Small Generating
Facility no larger than 2 MW and, finally, there is a 10 kW Inverter
Process for an inverter-based Small Generating Facility no larger than
10 kW. All three are designed to ensure, first, that the proposed
interconnections will be studied more quickly than the procedures
applicable to large generators and, second, that the interconnections
will not endanger the safety of electrical workers or the reliability
of the transmission system.
Order No. 2006 also established the contractual terms to be
included in the interconnection agreement ultimately signed between the
small generator and the public utility. The terms and conditions are
streamlined and simplified versions of the terms and conditions for
interconnecting large generators. But the agreement does not apply to
interconnection requests submitted under the 10 kW Inverter Process,
which uses a very simplified, all-in-one document for study,
construction, and operation of an interconnection.
The Order No. 2006 small generator interconnection standards apply
only to public utilities and, with limited exceptions discussed below,
only to transmission (as opposed to local distribution) facilities used
in interstate commerce. In Order No. 2006, as in Order No. 2003, FERC
concluded that the FPA allowed it to require public utilities to offer
generator interconnections to jurisdictional transmission facilities
and to a very limited number of local distribution facilities on a
nondiscriminatory basis. Local distribution facilities typically are
low-voltage facilities used to deliver energy in one direction to
retail end-users. The FPA expressly exempts local distribution
facilities from FERC authority, except as specifically provided.
Nevertheless, certain local distribution facilities do serve a FERC-
jurisdictional function: for example, the same facilities used to
distribute electric power to retail customers also may be used to
deliver wholesale electric power to utilities. These local distribution
facilities provide the second, FERC-jurisdictional delivery service
under a FERC-approved open access transmission tariff. To determine
whether a local distribution facility may be available for
interconnection under FERC's interconnection rules, FERC asks this
threshold question: is the local distribution facility already
available for FERC-jurisdictional delivery service under an approved
open access transmission tariff at the time the interconnection request
is first tendered? If the answer is yes, and the generator plans to
make wholesale sales of its energy, then the FERC interconnection rules
apply. The Commission's assertion of authority over local distribution
in these limited circumstances was appealed by the National Association
of Regulatory Utilities Commissioners (NARUC) and six state regulatory
agencies, and upheld by the Court of Appeals for the D.C. Circuit on
January 12, 2007. (NARUC v. FERC, 475 F.2d 1299 (D.C. Cir. 2007)).
When the Commission adopted the same approach for small generators
in Order No. 2006 as it had previously for large generators, it
acknowledged the rule's limited applicability in light of its lack of
jurisdiction over most local distribution facilities. It was expected
that many small generators would interconnect to local distribution
facilities not already subject to FERC's interconnection rules.
However, by developing interconnection rules in a process that sought
industry consensus, and adopting many measures recommended by NARUC,
FERC sought to harmonize state and federal interconnection practices
and promote consistent, nationwide interconnection rules to help remove
roadblocks to the interconnection of small generators. To this end, in
Order No. 2006, FERC expressed its ``hope'' that states would use the
rule to formulate their own interconnection rules, and thereby make
Order No. 2006 the de facto national standard for small generator
interconnection.
Net Metering
Net metering allows retail customers that own generation to get
retail rate credit for their output by effectively running the
customer's meter backwards. Net metering rules are subject to state or
local rate jurisdiction unless a FERC-jurisdictional wholesale sale of
power occurs. In precedent established in 2001, FERC held that a
wholesale sale of power occurs under net metering only if the generator
produces more energy than it needs and makes a net sale of energy to a
utility over the applicable billing period. (See MidAmerican Energy
Co., 94 FERC 61,340 at 62,263 (2001)). If there are net sales of
energy--and the generator is not a qualifying facility (QF) under the
Public Utility Regulatory Policies Act of 1978 (PURPA)--the generator
must comply with the requirements of the FPA for wholesale energy
sales. If the generator is a QF, and there are net sales of energy,
that net sale must be consistent with PURPA and the Commission's
regulations implementing PURPA.
When a generator that wishes to engage in net metering seeks to
interconnect to a transmission or local distribution facility, FERC
would use the same analysis it uses to determine if its interconnection
rules apply. In the Order No. 2003 proceeding, FERC clarified that for
its interconnection rules to apply, the net metering customer--at the
time it requests interconnection--must seek interconnection to a
facility already subject to a Commission-approved open access
transmission tariff and intend to make net sales of energy to a utility
(Order No. 2003-A at P 747).
Distributed Generation
Distributed generation, as defined by the Department of Energy, is
electric generation that feeds into the distribution grid, rather than
the bulk transmission grid, whether on the utility side or the customer
side of the meter. Because the generator is connected to the
distribution grid, the Commission's authority over distributed
generation interconnections is limited and would be subject to the same
analysis applied in Order Nos. 2003 and 2006. For the Commission's
interconnection rules to apply, the distributed generation customer--at
the time it requests interconnection--must seek interconnection to a
facility already subject to a Commission-approved open access
transmission tariff and intend to make wholesale sales of energy.
Regardless of whether a distributed generator is interconnected
under FERC's rules, if the distributed generator makes wholesale sales
of energy in interstate commerce and is not otherwise excluded from
Commission jurisdiction by FPA section 201(f) or covered by PURPA, it
must comply with the requirements of the FPA for wholesale energy
sales.
QF Interconnections
A slightly different analysis applies to FERC's authority over
interconnection of qualifying facilities under PURPA. FERC interpreted
PURPA as establishing an obligation to interconnect (Western
Massachusetts Electric Co. v. FERC, 165 F.3d 922 (D.C. Cir. 1999)).
Under the Commission's regulations, when an electric utility purchases
the QF's total output, the relevant state exercises authority over the
interconnection terms and conditions. But when an electric utility
interconnecting with a QF does not purchase all of the QF's output and
instead the QF's owner sells or has a contractual right to sell any of
the QF's output to an entity other than the electric utility directly
interconnected to the QF, FERC exercises its authority over the rates,
terms, and conditions affecting or related to the interconnection.
Thank you again for the opportunity to testify today. I would be
happy to answer any questions you may have.
Senator Cantwell. Thank you, Mr. Kelly, for your testimony.
Mr. Brown, proceed.
STATEMENT OF GARRY A. BROWN, CHAIRMAN, NEW YORK STATE PUBLIC
SERVICE COMMISSION, ON BEHALF OF THE NATIONAL ASSOCIATION OF
REGULATORY UTILITY COMMISSIONERS
Mr. Brown. Thank you. In addition to being the chair of the
New York State Public Service Commission, I am also chair of
the NARUC, National Association of Regulatory Utility
Commissioners' Committee on Electricity.
So in both these roles, I think like much of the Nation, I
have been following the energy and carbon debate that has been
happening in Washington, and I have frequent interaction with
my regulatory colleagues from around the Nation. I am struck by
one thing. Almost everything currently being discussed and
contemplated in the Federal venue, whether it is energy
efficiency standards, renewable portfolio standards, smart grid
initiatives, carbon reduction, net metering, fair
interconnection standards, incorporation of distributed
generation, and more, has really been dealt with at the State
level to some degree or other. In fact, in New York State, we
have addressed every one of these issues or at least started an
initiative to address every one of these issues.
So I think there has been considerable experience that has
been gained at the State level. All States have not taken the
exact same approach at the same exact speed. That is not
necessarily a bad thing. States are not always the same and
circumstances are not always the same.
Our record has been, I think, on the most part, very
supportive of increasing the diversity of supply in the
electricity supply mix. So as you move forward with potential
Federal legislation, I would ask you to please attempt to
balance the need for Federal leadership and consistency with an
awareness that there are many successful efforts at the State
level that could be jeopardized by things that perhaps are
overly restrictive or overly rigid rules that do not fit into a
State's or region's circumstances.
Specifically on the issues that are the subjects of this
hearing, over 40 States and the District of Columbia have
already adopted net metering rules for distributed generation.
Over 25 States have a renewable portfolio standard, with 14 of
those containing specific provisions for solar in distributed
generation. Thirty-five States, the District of Columbia, and
Puerto Rico have adopted revised interconnection standards to
ease the burden of safe interconnection into the electricity
grid.
My written testimony highlights some of the benefits of
increasing the role of distributed generation and net metering,
our actions to address these issues. I think it also highlights
some of the lessons learned along the way.
So the States welcome what I think we would describe is
much needed Federal leadership on these energy issues and
welcome you to the debate. We ask you to move forward with this
leadership, however, with some flexibility. We will achieve our
objectives I believe if we can avoid counterproductive
jurisdictional debates and focus more on moving forward
together to address these very important issues that are
important both to the State and to the Federal Government that
allow States some flexibility in moving forward while setting
some national objectives that I think are very important for us
all to go after.
So with that, I will conclude my testimony.
[The prepared statement of Mr. Brown follows:]
Prepared Statement of Garry A. Brown, Chairman, New York State Public
Service Commission, on Behalf of the National Association of Regulatory
Utility Commissioners
Good afternoon Chairman Cantwell, Ranking Member Risch, and Members
of the Subcommittee.
My name is Garry Brown, and I am the Chairman of the New York State
Public Service Commission (NYPSC). I also serve as the Chairman of the
National Association of Regulatory Utility Commissioners (NARUC)
Committee on Electricity.
Today I will be testifying on behalf of NARUC, and where noted the
NYPSC. I am honored to have the opportunity to appear before you this
afternoon and offer the State perspective on net metering and
interconnection standards. I would respectfully request that my written
testimony be entered into the record as if read.
distributed generation
NARUC is a quasi-governmental, non-profit organization founded in
1889. Our membership includes the State public utility commissions
serving all States and territories. NARUC's mission is to serve the
public interest by improving the quality and effectiveness of public
utility regulation.
Our members regulate the retail rates and services of electric,
gas, steam, water, and telephone utilities. We are obligated under the
laws of our respective States to ensure the establishment and
maintenance of such utility services as may be required by the public
convenience and necessity and to ensure that such services are provided
under rates and subject to terms and conditions of service that are
just, reasonable, and non-discriminatory.
NARUC and its members have long supported and encouraged advances
in smaller, cleaner generation options. Distributed generation
technologies are a resource that can function in a manner that results
in a reduction in customer load, much like energy efficiency and load
management technologies, with no export of power to the utility system.
In addition, these distributed generation applications and technologies
have many public interest benefits, such as:
New technologies enhance customer choice;
On-site generation improves customer value through control
of costs and enhanced power quality and reliability;
Distributed generation can enhance the efficiency,
reliability, and operational benefits of the distribution
system;
Access to distributed generation technologies can increase
competition by reducing the market power of traditional power
providers, particularly in transmission and distribution-
constrained regions;
Generation close to load can reduce total electric
generation costs by reducing line losses through the
transmission and distribution system, and associated fuel and
operational costs;
Distributed generation allows utilities to improve the asset
utilization of their transmission and distribution equipment
and associated financial capital and operational expenses;
Distributed generation resources can be permitted, installed
and put into use more quickly than central station generation
or transmission; and
Distributed generation technologies can provide
environmental benefits.
Recognizing the future importance and potential of Distributed
Energy Resources to the nation's energy systems, in 2000, NARUC began
to look at the potential barriers to distributed generation and found
that:
Burdensome distribution system operating and planning
requirements may result in the unfair treatment of non-utility
distributed generation technologies;
Bundled distribution service tariff elements and fees and
charges may present economic barriers to distributed generation
technologies;
Concentrations of market power may restrict the development
of markets that distributed generation technologies could
serve; and
Ambiguous jurisdictional authority may hinder the business
climate necessary for private investment.
Once the barriers where determined, NARUC's members started a
three-year process to develop model interconnection standards for small
generation resources in an attempt to produce a document that would
remove or alleviate most of the access issues and fit the regulatory
systems in the vast majority of the States.
This process, as well as the Federal Energy Regulatory Commission
(FERC) order 2006 process, which had extensive State involvement and
coordination, greatly improved the promise of new and cleaner
distributed generation technologies--like fuel cells, micro-turbines,
distributed wind machines, and photovoltaics--by working to
significantly reduce market barriers that existed due to inconsistent
and outdated grid interconnection standards.
As a result of these activities and passage of the Energy Policy
Act of 2005, today approximately 35 States and the District of
Columbia, including the major load centers in the nation, have
interconnection standards.
In New York, the existing Standard Interconnection Requirements
(SIR) for distributed generation 2 MW and under has separate and
distinct review processes for systems 25 kW or less, and greater than
25 kW up to 2 MW. Systems 25 kW or less will have a streamlined
application process, and systems above 25 kW up to 2 MW will have more
detailed review process.
NYSPSC staff has proposed that utilities be required to implement a
web-based system for providing generator customers and contractors up
to date information regarding the status of their application process.
In addition, the staff has proposed that each utility be required to
allow customers with systems 25 kW and below the ability to submit
their application for interconnection via the Internet. These proposals
are under consideration.
net metering
Net energy metering--an accounting mechanism whereby customers
owning qualifying generators are billed only for their net energy
consumption over a given billing period and obtain a credit for future
billing periods if production exceeds consumption--can provide a
direct, inexpensive, and easily-administered mechanism for encouraging
the customer installation of small-scale renewable energy facilities.
Public preference and customer demand support cost-effective
renewable energy product development and commercialization. The use of
customer-sited, grid-connected, small-scale renewable energy generating
facilities offers many technical and economic benefits to the
electricity system including reduced transmission and distribution line
loads and losses, and/or peak demand reduction.
Approximately 40 States currently require utilities and competitive
energy providers to make net energy metering available, and another
four permit it under voluntary utility programs.
While the capacity limits, and other terms and conditions vary
among States, these differences reflect the programs that work the best
for the consumers of a given State. These variations ensure that the
consumers of each State receive just and reasonable rates, at fair
terms and conditions. In addition, since NARUC began to seriously study
net metering proposals in 1998, the States have made great progress in
this most useful retail rate-design mechanism.
In New York, net metering is legislatively mandated and encourages
the use of small-scale renewable energy systems which provides long-
term benefits to the environment and the economy.
Recently, Governor David A. Paterson announced an expansion of the
state's net metering law, which allows electric customers who generate
renewable energy to sell what they do not use back to the grid. The new
bill expanded net metering to wind and solar PV systems on businesses,
as well increasing the size of eligible systems for residential
customers and for non-residential customers.
New York has a strong legislative history regarding net metering:
1997--Initial legislation providing net metering for small
(up to 10 kW) solar generators
2002--Net metering expanded to include individual anaerobic
digester (farm waste) electric generators up to 400 kW
2004--Net metering expanded to include up to 25 kW
residential and up to 125 kW residential farm service wind
generators
2008--Net metering expanded to provide to commercial solar
and wind generators up to the lesser of the most recent 12-
month peak load or 2MW; residential solar installations
increased from up to 10 kW to up to 25 kW; residential farm
service wind installations increased from up to 125 kW to up to
500 kW; and anaerobic digester (farm waste) installations
increased from up to 400 kW to up to 500 kW.
The overall cap for solar and farm waste generators is 1 percent of
each utility's 2005 peak load on a first-come, first-served basis. The
overall cap for wind generators is 0.3 percent of each utility's 2005
peak load on a first-come, first-served basis.
In New York, customers get credit at retail rates for excess
generation subsequently used by the customer for its own purposes
during a 12-month period. At the end of the 12-month period, for
residential and farm customers, any remaining excess generation is
credited at the market or wholesale rate. For non-residential solar and
wind technologies, any remaining excess generation is rolled over to
the next 12-month period.
As Congress considers what role it might want to play in terms of
net metering policies, perhaps it would be helpful to hear briefly
policy questions we are asking in New York as we weigh the benefits of
potentially expanding net metering even further. These policy questions
include:
Should net metering be provided to customers who also have
non-qualified generators?
Should we expand net metering technologies to include
additional technologies and/or should the sizes of the allowed
technologies be increased?
How should potential impact on non-participants be
mitigated?
What are the possible impacts on transmission and
distribution systems?
We have also learned several lessons in implementing net metering
in New York:
Overly restrictive definitions of the metering
configurations net metering customer must use should be
avoided. A restrictive definition could impede customer efforts
to avail themselves of smart metering options, which could
assist customers in maximizing the benefits of net metering.
The eligibility criteria customers must meet to qualify for
net metering should be developed carefully to avoid unintended
consequences.
In conclusion, states have been a very successful laboratory for
distributed generation and retail rate design policies. Certainly, more
can and will be done in the near future. However, these issues will
affect not only the entities that hopefully will make a profit to
continue the development of renewable generation sources based on these
policies, but also those consumers who will pay these costs.
Thank you for your time and consideration.
Senator Cantwell. Thank you, Mr. Brown. Perhaps we can get
more into that in the question and answer session after the
rest of the witnesses.
Mr. Brown. I would be happy to.
Senator Cantwell. Thank you.
Mr. Cook.
STATEMENT OF CHRISTOPHER COOK, MANAGING DIRECTOR, SUNWORKS,
LLC, DUNN LORING, VA
Mr. Cook. Thank you, Madam Chairman, fellow members of the
committee. My name is Chris Cook. I am a co-founder and
Managing Director of Sunworks, a startup company focused on
bringing photovoltaic manufacturing facilities to the U.S.
I am also here on behalf of SEIA, the Solar Energy
Industries Association, the national trade association for
solar manufacturers, installers, and developers.
My comments today are focused on net metering and
interconnection, but I would be happy to discuss with you
anything about distributed generation. I am honored to have
this opportunity. I have been working on net metering and
interconnection issues for over a decade and have worked with
nearly 20 States on implementing either net metering or
interconnection rules in the State.
My overarching point is it is imperative, if we are going
to meet the President's laudable renewable energy goals to
address these issues, to have a seamless interconnection and
net metering rules across the States that do not create a
barrier for the people like my company who want to install
solar energy systems on rooftops.
I will give you as an example the current state of affairs.
While 42 States have net metering--and there is some debate
over just the precise number of which States do have and do not
have--my former company, Sun Edison, focused on commercial
rooftop installations of 100 kilowatts or larger. When you look
at the details of the State net metering rules and then you
look at that business opportunity or that business plan,
roughly half the States fall out for a net metering opportunity
because they do not allow net metering for systems above 100
kilowatts.
If you then focus on the half that are remaining, an
additional five States fall out because even though they have
good net metering rules, they have interconnection rules that
constitute a barrier for those larger-size systems.
So while at first blush it appears there are 42 States in
which a company like Sun Edison might do a robust business, it
turns out when you actually get into the details of the rules
and the patchwork that you mentioned, there are really only 16
States where a company focused on commercial installations can
do business currently. I think that is an overarching call-out
for some Federal leadership and Federal guidance that provides
a seamless web across all States so that solar energy companies
can do business there.
Elements of a good net metering policy. I think the main
opposition to net metering, a nationwide net metering, is the
proposition that if you put power back onto the grid from your
solar energy system, the people who operate the grid say that
power is not worth the same amount as the power that they
provide you because the per kilowatt hour charge that is
charged to retail customers are fixed costs. Part of the
difficulty then is to say, well, how much is that power worth?
When it comes to solar, there is lots of indirect benefits that
accrue for the power that is put onto the grid.
First, solar is a peak energy generation technology, and
peak generation tends to be much more valuable to the grid than
off-peak generation. So a solar energy producer might have a
125 or 150 percent adder to the value that they are actually
putting to the grid.
Then there is a host of intangible benefits that accrue to
the grid. There is offset need for transmission and
distribution upgrades. There is offset wear and tear on the
grid from the power that goes there. The power is utilized
locally so there are offset transmission charges.
So the issue then comes down to say is it approximately
equal. I would submit to you that it is, that the power of the
solar generators, particularly when you look at the emissions
benefits, put onto the grid is equal and that net metering is a
good approximation for it. That is really the main opposition
to it is the economics behind it.
I think what is needed from a Federal level is a Federal
guide on net metering. While, as Mr. Kelly explained, the FERC
has weighed in and has effectively a Federal guide on
interconnection, there is no Federal guide on net metering. So
States that move forward to adopt their own net metering rules
really do not have an effective Federal leadership guide to say
what constitutes good net metering and what is a core.
I would recommend that the FERC be tasked with the
authority of coming up with a model, having that model at its
core remove the barriers to the net metering issues. States
have the flexibility to aggrandize that or add enhancements,
but FERC then retains the authority to say if a utility adopts
a net metering tariff, it still constitutes a barrier so that
people can install solar on their homes or businesses. The FERC
would have the authority to implement the model rules.
I think a similar structure would work on the
interconnection, and while FERC did a laudable job on that in
2003, I think the rules could use some updating. There was a
segment of the interconnection rules that the working groups
just simply ran out of time and never got around to. Those
could use some updating.
I think it would behoove the FERC to look at some of the
State interconnection proceedings that have gone subsequent to
FERC Order 2006 and adopt some of the consensus best practices
that came out of those State proceedings to update their model
rule and, then again, use that model rule for the States to
roll out so that we can attempt once again to get what I think
FERC articulated in their Order 2006 with a seamless national
web for interconnection standards for small generators.
Thank you.
[The prepared statement of Mr. Cook follows:]
Prepared Statement of Christopher Cook, Managing Director, Sunworks,
LLC, Dunn Loring, VA
Madam Chairman, members of the Subcommittee, thank you for the
opportunity to testify today. I am here on behalf of my company and on
behalf of the Solar Energy Industries Association who is the leading
national trade association for the solar energy industry. SEIA works to
expand markets for solar, strengthen research and development, remove
market barriers and improve public education and outreach for solar
energy professionals. SEIA has over 900 member companies representing
the entire spectrum of the industry, from the small installers to large
multinational manufacturers.
Access to net metering and standardized and streamlined
interconnection standards are critical to the widespread deployment of
customer sited solar and other renewable energy generators. While a
total of 42 states have net metering and every state has some form of
interconnection rules, the rules vary widely. Some encourage the use of
renewable energy generators while others hamper the national deployment
of solar. I will herein describe in Section I the important aspects of
net metering. In Section II I will discuss the need for comprehensive
national standards for interconnection of small generators.
section i: net metering--what is it?
Net metering is an economic arrangement between a customer who owns
or operates their own generator (``customer generator'') and their
local utility to effectuate the operation of the customer-generator's
generator. It is distinguished from interconnection standards which are
the technical and safety requirements needed to connect a generator
that will interact with the utility grid in a mode the industry calls
``parallel operation''. While any generator that will avail itself of a
net metering must be interconnected, an interconnected generator may or
may not operate under a net metering tariff. It is important to
distinguish between the two.
The term ``net metering'' derives from a simple utility metering
system where a single meter spins forwards when a customer is using
more electricity than they are generating and in reverse during those
times when the generator output is greater than the customer's load.
Because the meter spins forwards and in reverse the meter itself
``nets'' excess consumption and generation and the meter reading shows
the net of generation and consumption over any discreet billing period.
Interestingly, the simple meters typically deployed by utilities in
the 1950's and 1960's with the spinning disk would net meter. All of
these meters would simply spin in reverse when a generator on the
customer's side was producing more power than the customer was using.
why is net metering needed?
For renewable generators like solar and wind, the renewable
generator operates when the resource is available and cannot be
throttled up or down to match the load at the customer's home or
business. That means that at any given time there is a high probability
that the generator is either producing more than the customer needs or
less. When the generator is producing more power the customer has three
choices:
1) the customer can install a storage device (e.g. batteries)
and send the excess power to storage to be used later.
2) the customer can turn on more electricity consuming
equipment to use the excess power (not generally encouraged).
3) the customer can send the power to the electric grid for
use by other customers.
Under option 3--the net metering option--the customer is credited
for the power to the grid and can use those credits later to offset
future costs and lower their electric bill. Option 3 is the lowest cost
option for the customer and in the case of solar generators the best
option for the utility grid.
A standard net metering tariff allows the power producer to obtain
full value for all of their power produced without the excess cost of
installing batteries or other storage devices.
why is their opposition to net metering?
The rate that a utility typically charges a customer for kilowatt-
hours (kWh) consumed by the customer includes fixed charges. When a
customer produces their own energy (kWh) and receives a full retail
credit for excess kWh, the utility has a reduced revenue source for the
fixed cost component of providing electric service. These lost
contributions to fixed costs are born by the utility until their next
rate case at which time other customers would pay an incrementally
higher percentage of the fixed costs to make up the loss from the net
metering customers.
This raises the largest question about net metering--whether power
producers that are benefitting from net metering are paying their fair
share of system costs. There is no clear answer and to the best of my
knowledge, no comprehensive study has ever been undertaken to address
and potentially resolve this issue.
Part of the reason the question cannot be answered simply is that
net metering customers provide a host of indirect benefits to other
utility customers. In the case of solar customer-generators these
benefits include:
reducing peak demand,
avoiding environmental damage,
improving grid efficiency,
avoiding upgrades to transmission and distribution grid,
providing local voltage support that can reduce the need for
other utility equipment,
reducing the need for operating and spinning reserves needed
to assure electric reliability,
the ease of deploying solar projects and their short lead
times reduces the risk of forecasting mistakes that can result
in costly power generation overcapacity\1\.
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\1\ From A WHITE PAPER By ED SMELOFF, ``QUANTIFYING THE BENEFITS OF
SOLAR POWER FOR CALIFORNIA''
All of these benefits go to reducing and perhaps eliminating any
subsidy from non net metered customers. In fact, it may be true that
net metering customers are subsidizing other customers.
In case there is a cross subsidy, net metering rules typically
limit the total amount of customers who can net meter. For example, a
state might limit net metering to five percent of the total capacity of
generation on a utility system. This ensures that if there is a net
metering subsidy, any subsidy is tiny and of minimal impact on other
customers.
It is also worthy of note that net metering provides no worse an
economic arrangement for the utility and other customers than the
alternative presented to the customer-generator--storage.
If a customer-generator were to install a storage device for all of
their excess production, they would cease to contribute to fixed costs
for any of the kWh they produced (in an identical way, a customer who
reduces their consumption through energy efficiency also contributes
less to fixed utility costs). For the solar generator with storage, the
situation becomes worse for other customers. Because solar generation
typically occurs during the more costly peak times, the solar customer-
generator is invariably producing excess power during the most costly
periods for grid electricity while consuming excess net metering
credits during off-peak periods. When the solar customer ``net
meters'', the excess peak energy is sent to the grid and other
customers see the benefit of this peak energy generation.
If a solar customer-generator were to instead use storage, they
would be storing peak energy for off-peak usage. This is quite contrary
to all grid storage strategies which store off-peak energy for on-peak
usage. So were net metering not offered and customers were driven to an
on-site storage option, other customers would be worse off than if net
metering is used.
why is a federal standard needed?
While 42 states have some form of net metering in place, no two are
the same. Some state net metering rules are robust and can be said to
encourage a wide array of renewable energy deployment by customers.
Others are quite limited and act as barriers to the widespread use of
solar energy. A ranking of the states showing how they compare against
each other was performed by the Network for New Energy Choices and is
attached to my testimony as Appendix A. It is my understanding that a
grade of ``C'' under this ranking represents a functional standard for
most customers. Lower grades mean the state's rule contains some major
and minor barriers.
A minimal federal standard that allows all customers to use solar
energy for their electricity needs is critical to the growth of the
solar industry. A federal standard will remove barriers that currently
exist in the myriad of state net metering standards. While states
should be encouraged to go beyond the minimal federal standard to
actually promote the use of renewable energy, the industry needs a
federal standard that removes all major barriers nationwide.
Key elements of a functional federal standard:
1:1 ratio of credit to kWh produced. A customer should see
no reduction in the value of the power they produce. Not only
is a lower ratio a deterrent to the use of renewable energy, it
incurs extremely high administrative costs to implement. If
those administrative costs are placed on the net metered
customer, they often lose much of the value of the renewable
energy they produce.
Time of use open to net metering customers at an equivalent
to the time of production and consumption. Where time of use
rates are in place, a renewable customer-generator should get a
peak credit for any excess peak power produced to be used to
offset peak power consumption. The same is true for mid-peak
and off-peak periods. If the peak power costs, for example, 2
times the mid-peak, the net metering customer should get 2 mid-
peak credits in consumption for every peak credit they produce.
Safe harbor provisions. A customer-generator should not be
charged any special fees or other charges to have access to net
metering and should be treated identically in terms of rates
and other conditions of service to a similarly situated
customer that does not have a renewable generator.
recommendation on generator size limits
The size of a customer-generator's generator does not impact the
economic equation related to potential cross-subsidy discussed above.
Therefore the size limitations on net metering generators should skew
to the large to allow all customers to offset a substantial portion of
their electricity needs. While the recent trend among states is to set
the upper limit on the size of generator at 2 megawatts, several states
have gone well above that limit. In addition, the size of solar
generators at customer sites are trending to the larger sizes with the
largest customer sited solar generator at the Nellis Air Force base in
Nevada coming in at 14MW. To allow room for this growth to continue, I
would recommend a 10MW limit on the size of the net metered generator.
recommendation on total capacity
To allow both for sufficient growth in the solar (and other
renewable) industry, I would recommend that the total installed
capacity limit for all net metered generators be set at 5 percent of
the capacity of any individual utility system. This limit ensures that
a cross subsidy, if any exists, is small while at the same time allows
for a decade's worth of growth in the industry. Even if the power
exported to the grid is only worth the wholesale power rate (about half
the net metering credit), that means the total cross subsidy is less
than 2.5 percent. It is less both because of an assumption that the
aforementioned list of benefits are worth something more than zero and
because a capacity limit does not account for the many installations
that will be exporting no power to the grid and hence incurring no
subsidy (many solar installations at commercial and industrial sites
never export to the grid even though they use a net metering tariff).
recommendation on implementation
To avoid supplanting state work on net metering completely, I would
recommend that the Federal Energy Regulatory Commission (FERC) be
tasked with creating a model net metering tariff for states to use that
eliminates all major barriers sometimes buried in net metering rules.
States and utilities will then have a useful guide to creating their
own net metering rules and will have the flexibility to go beyond the
model to adopt rules that promote renewable energy. FERC should have
the authority to order the adoption of the model rules in those cases
where it determines, after hearing, the net metering rules of any
particular utility constitute a barrier to the use of renewable energy.
other points
1) Net metering should address solely the economic
arrangement for renewable customer-generators. Any technical or
safety related issues including the types of equipment needed
to interconnect and the costs for interconnection studies
should be addressed in the interconnection standards.
2) Net metering should not be considered a buy and sell
arrangement between the customer and utility. To simplify the
entire transaction and avoid transactional costs, net metering
should be constructed as a ``swap'' of kilowatt-hours where the
parties receive kWh at a certain point in time to be consumed
at a later point in time. When there is no buy-back or selling
of kWh, there are no checks to be cut and no accounting ledgers
to maintain. In the simplest and perhaps easiest form to
implement net metering, excess kWh credits are simply carried
forward month to month to be used by the customer at some time
in the future. When the customer departs as a utility customer,
any unused credits disappear.
interconnection standards
Interconnection standards, unlike net metering rules, address
technical, safety and contractual issues surrounding operation by a
customer of any type of generator that generates in parallel to the
utility grid. This includes generators sited at a customer's location
that export power to the grid; generators sited at a customer's
location that do not (and in some cases cannot) export power to the
grid; and generators that are not at a customer site but are connected
to the grid and export power. Interconnection standards typically
address the smallest home generators in the kilowatt range to gigawatt
sized generators.
Interconnection is accomplished by having the local utility
``study'' the impacts on the grid of connecting the proposed generator.
Where the generator is small in relation to the capacity of the grid,
the interconnection may be approved without any grid improvements.
Where the new generator may overload utility protective devices or
lines, the utility, at the generator's cost, will have to upgrade those
devices or lines before the interconnection can be approved. The
interconnection study process for the latter may take months and costs
tens of thousands of dollars to complete.
section ii: interconnection standards--the need for a comprehensive
federal small generator interconnection standard
FERC in its Order No. 2006\2\ (et. seq.) created a small generator
interconnection procedure (SGIP) that all federally regulated utilities
were required to adopt. This standard was the result of a long series
of stakeholder meetings FERC held subsequent to the issuance of its
Notice of Proposed Rulemaking (NOPR) on small generator interconnection
standards. The rules are generally comprehensive but are lacking in
three distinct areas:
---------------------------------------------------------------------------
\2\ Standardization of Small Generator Interconnection Agreements
and Procedures, Order No. 2006, 70 FR 34100 (Jun. 13, 2005), FERC
Stats. & Regs., Regulations Preambles, Vol. III, 31,180, at 31,406-
31,551 (2005).
1) Order No. 2006 does not provide for standardized
interconnection procedures for customer sited generators that
will not export power to the grid. The stakeholder process that
led to Order No. 2006 was limited in time and this aspect of
the procedures was simply left unaddressed because of the time
constraints. Larger combined heat and power generators
typically fall into this category and at present there is no
federal standard that expedites the interconnection of these
generators. With the increasing size of solar generators, they
too may soon find need for the interconnection rules for larger
generators.
2) Updates from state interconnection proceedings. Many
states have undertaken interconnection proceedings subsequent
to issuance of FERC Order No. 2006 many of which have expanded
upon and added refinements to the original FERC Order. FERC
should revisit its Order to include the best practices from the
state proceedings and their interconnection rules.
3) Order No. 2006 is not comprehensive in its application.
While the SGIP addresses any interconnections to federal
transmission facilities and those distribution facilities under
an open access transmission tariff, most of the
interconnections of customer-sited generators are not to these
types of facilities. Not only does this leave potential gaps in
the size of generators that can be interconnected but, like net
metering, the state rules are a myriad of different
regulations. Some state interconnection rules are quite
accommodating to small and renewable generators while others
constitute barriers. Irrespective of the good or the bad, the
patchwork of state rules in this area represent a restraint on
the ability of solar developers and manufactures to freely
conduct interstate commerce. Many manufacturers of
interconnection equipment for solar generators must take into
account these varying state rules which adds costs to the
systems they are trying to stamp out. A universal federal
standard is needed.
what are the key elements of good interconnection procedures from
small generators?
Interconnection rules can be a costly, time consuming, and arcane
set of rules to follow for even the simplest small and renewable
generators. The key to accommodating small generators is to identify a
set of circumstances that allow the generators to be interconnected
quickly and at low cost. Because solar and other renewable generators
often use specialized electronic devices (inverters) to oversee the
generators interactions with the grid, a number of utility safety and
technical concerns are easy to address. Moreover, when the inverter
devices are UL certified, the interconnection process can be nearly
``plug and play''. A series of quick engineering screens can be used
which will either determine that the generator can be approved for
interconnection or that additional study is needed.
The overarching objective in designing good and streamlined
interconnection rules is to avoid unnecessary interconnection studies
that, based on solid electrical engineering principals, do not need to
be conducted. For example, while it may be academically interesting to
see how that single installation affects power flows on a nearby
transmission line for a small solar installation on a residential
rooftop, the likelihood that that would ever occur is nil. Undertaking
an engineering study to confirm that assumption would be both time
consuming and costly for the residential customer. Such a study is
unnecessary and should be excluded from good interconnection
procedures.
Other elements that distinguish good interconnection rules from bad
ones are:
Some element of fixed cost to complete the interconnection
study process that allows a solar developer to have a good idea
of the cost to complete the interconnection study process
Fixed timelines for the utility to complete interconnection
studies so developers can know for certain the latest when
their generator will be approved for operation.
Prohibition on utility requirements to add additional and
unnecessary protection equipment that increases the cost of a
solar installation.
Simplified and standard form interconnection agreements so
each installation does not need to budget for legal counsel to
assist in negotiating an interconnection contract.
Prohibition on requirements for insurance above and beyond
ordinary liability insurance.
A dispute resolution process where a solar installer can
have access to a knowledgeable expert or master who can resolve
quickly and at little cost disputes over the interconnection
requirements. Since solar installers and developers are almost
always less capitalized, and have less expertise on staff, they
may find their interconnection request at the mercy of a
recalcitrant utility who has little interest in seeing the
solar installation progress
The overarching need of the solar community and other generator
project developers is to have comprehensive rules that cover all
generator interconnections. Unfortunately in many instances local rules
act as a major barrier to the use of renewable generation.
current state of interconnection
Unfortunately, while several states have implemented comprehensive
rules on interconnection, according to the NNEC report (Appendix A*),
only 15 states have interconnection rules that can be said to have
eliminated all major and minor barriers to the interconnection of small
generators. Just over half the states continue to have interconnection
rules that constitute, to some degree, a major barrier to
interconnection. This either prevents homeowners and businesses from
using their own solar or renewable energy generator or significantly
increases the time or cost to do so.
---------------------------------------------------------------------------
* Report (Appendix A) has been retained in subcommittee files.
---------------------------------------------------------------------------
This is all the more unfortunate in light of the universal and
functional FERC small generator interconnection procedures and the
directives in EPAct 2005 to address interconnection.
recommendation for comprehensive interconnection rules
I would recommend that FERC be directed to reconvene working groups
to update and complete the Small Generator Interconnection Procedures
contained in FERC Order No. 2006. FERC should look to the state
proceedings to include consensus best practices from recently
promulgated state interconnection rules. A good guide and compilation
of those best practices is found in the Interstate Renewable Energy
Council's (IREC) model interconnection rules (IREC MR-I2005). IREC has
a team of experts that not only work with states on creating
interconnection rules but also update their model rules when a new best
practice is developed.
After FERC has updated the SGIP, it should present that as a model
for states and local utilities to adopt. As with net metering, FERC
would retain jurisdiction and be able to require a utility to adopt the
updated model interconnection rules where the rules otherwise adopted
by the utility represented a barrier to the use of renewable
generation. FERC should be tasked specifically with ensuring
comprehensive and seamless interconnection standards irrespective of
whether the interconnection is local or under traditional FERC
regulation.
Senator Cantwell. Thank you, Mr. Cook.
Mr. Weiss, thank you for being here today.
STATEMENT OF DAVID WEISS, PRESIDENT AND COO, ENERGY SERVICES
DIVISION, PEPCO ENERGY SERVICES
Mr. Weiss. Thank you. Chairman Cantwell, Senator Bingaman,
my name is David Weiss. I am President and Chief Operating
Officer of Pepco Energy. Pepco Energy is an unregulated
subsidiary of Pepco Holdings. We provide retail energy services
and products, including energy efficiency. We develop renewable
energy projects, district heating and cooling projects, and
distributed generation projects.
I am pleased to appear before you this afternoon to discuss
distributed generation's potential to increase clean energy
deployment and to diversify our Nation's energy supply.
Pepco Energy has executed a number of very interesting
projects, and I would like to describe a few of them to you
today because I think it will help you get a feel to how these
work.
In December 2008, Pepco Energy completed an installation of
the largest single rooftop solar project in the country in
Atlantic City. This project covers 266,000 square feet of
rooftop. That is equivalent to five football fields. The 2.37
megawatt DC project at the Convention Center in Atlantic City
includes net metering. The project was made possible by the
fact that there are times during the year where we provide more
electricity to the Convention Center than required, and it is
then exported to the grid through net metering and smart
meters. The project was really made possible by Federal tax
incentives, the State of New Jersey renewable portfolio
standards, the New Jersey net metering regulations, and
interconnection agreements.
Another project we did, which was a distributed generation
project at the NIH, a 2-megawatt co-gen project, did not
require net metering because it produces less than the base
electricity use of the campus.
The third project, or group of projects, is three landfill
gas-to-energy projects up and down the mid-Atlantic region,
including 10 megawatts of generation. All these plants required
separate interconnection agreements because we were in three
different investor-owned utilities.
Finally, we also own a large district heating and cooling
plant in Atlantic City where we deliver chilled and steam water
for heat and air conditioning to many of the casinos of the
boardwalk. At this time, we have no distributed generation in
this 12-year-old facility, but we intend to install it in the
near future. In order to do that, we will either need net
metering capabilities or the capability to send electricity,
along with the steam and chilled water, to an adjacent
property.
With that background in mind, I would like to explain some
of the challenges of these projects and some of the policies
and issues that arise.
Distributed generation and net metering are and can be a
significant, valuable component of our overall energy mix. In
order to promote distributed generation, the market needs to be
confident that the real and perceived barriers of generation
policies with rate decoupling can be accomplished. Rate
decoupling means that the local utility is indifferent to how
much energy it sells. Whether it sells more or less, it still
gets a rate of return on its assets and, therefore, is less
worried about small generation and energy efficiency projects.
A second area is standardization to the greatest degree
possible. Standardization of the interconnection agreements
will very much help the industry move quicker and develop
distributed generation and renewable energy projects quicker.
Each one of these projects out there have their own unique
benefits and constraints, and there are a lot of stakeholders
in these projects, the local utilities, the local customers,
the local citizens. So although a model can address many of the
best industry standards and practices, there has to be some
allowance for local flexibility for safety and also just for
the local stakeholders to make sure that they are comfortable
with the systems.
In closing, Chairwoman Cantwell, I would like to thank you
and the subcommittee for the opportunity to speak here today.
As evidenced by the work we have been doing and continue to do
at Pepco Energy, I feel strongly that the use of energy
resources, diversity in the energy generation and renewable
energy, coupled with strong enabling policies are of extreme
importance to the energy environment in which we now find
ourselves. Thank you.
[The prepared statement of Mr. Weiss follows:]
Prepared Statement of David Weiss, President and COO, Energy Services
Division, Pepco Energy Services
Chairwoman Cantwell and Members of the Subcommittee, my name is
David Weiss and I am the President and COO of the Energy Services
Division of Pepco Energy Services. Pepco Energy is a subsidiary of
Pepco Holdings Inc., one of the largest energy delivery companies in
the mid-Atlantic region.
Pepco Energy provides retail energy products and services,
including comprehensive energy management solutions and renewable
energy projects to a wide range of customers that includes the Statue
of Liberty, the U.S. Capitol, The Empire State Building, the US Air
Force, Army and Navy and many state, municipal, commercial and
industrial customers. Over the last 14 years, Pepco Energy has
developed, implemented and financed over $750 million in energy savings
performance contracts including the single largest one ever awarded by
the federal government. In addition, Pepco Energy is an experienced
developer of renewable energy, district heating and cooling and
distributed generation projects.
Pepco Holdings other subsidiaries serve about 1.9 million customers
in Delaware, the District of Columbia, Maryland and New Jersey
operating as Potomac Electric Power Company (PEPCO), Delmarva Power and
Atlantic City Electric which provide regulated electricity service;
Delmarva Power also provides natural gas service. Pepco Holdings
additionally provides competitive wholesale generation services through
Conectiv Energy.
I am pleased to appear before you this afternoon to discuss
distributed generation's potential to increase clean energy deployment
and to diversify our nation's energy supply, particularly in parts of
the nation, like the mid-Atlantic that are not benefitted with a
tremendous supply of renewable resources. Pepco Energy has executed a
number of very interesting distributed generation projects and I'd like
to take a moment to describe how three of them work.
In December 2008, Pepco Energy completed the installation of the
largest single roof- mounted solar project in the country in Atlantic
City, New Jersey. The project covers over 266,000 square feet on the
roof of the Atlantic City Convention Center. The 2.37 MW-DC solar
generating system includes over 13,400 panels and is designed to
provide approximately 26% of the Convention Center's annual usage. This
project made use of net metering by actual ``smart meters'' that
measure the power being imported to the facility and exported from the
facility. The renewable energy generated avoids the release of
approximately 2,349 tons of carbon dioxide per year. This project
represents a substantial investment by our company in renewable energy,
and could not have been accomplished without the coordination of a
number of different parties; the local utility, various state agencies,
and, of course, the host customer. The project returns were dependent
on the utilization of a number of different policies and programs
including federal tax incentives, the State of New Jersey's Renewable
Portfolio Standards, net metering regulations and interconnection
agreements.
A second project is a 23 MW gas-fired cogeneration plant at the
National Institutes of Health in Bethesda, MD. This project was
completed in 2004, and is one of the largest cogeneration facilities
ever built for the Federal government. Situated in the middle of a
densely populated area, and in an extremely active campus setting with
a significant amount of critical infrastructure to protect, careful
attention had to be paid to the local community concerns, as well as
the safety and reliability of the unit and the existing, surrounding
infrastructure. This output from this unit will result in a significant
amount of savings to NIH, and will reduce carbon dioxide emissions by
approximately 100,000 tons per year over its 20-year life. This project
did not require net metering because the unit produces less than the
base load energy use of the NIH Campus.
A third project-or group of projects-is our landfill gas-to-energy
plants. Pepco Energy has designed, built, owns and operates 3 of these
landfill gas plants in the mid-Atlantic area, with a combined
generating capacity of 10 MW. While the plants use a variety of
technologies to capture, condition and utilize the methane from these
landfills, they each have one thing in common: they take an otherwise
unused, and harmful byproduct of the landfill and turn it into a
valuable and useful commodity that improves and diversifies our energy
mix in the U.S. Each one of these facilities is in a different investor
owned utility's service territory and therefore we were required to
negotiate a special interconnection agreement for each project.
In addition to these projects, Pepco Energy owns and operates a
large district heating and cooling plant in Atlantic City, New Jersey
that delivers steam and chilled water to many of the casinos on the
boardwalk for their heating and air conditioning needs. At this time,
there is no distributed generation included in this 12 year old plant,
but we do have plans to add a cogeneration unit in the near future that
will significantly increase the efficiency of the plant and may require
net metering capabilities.
With that background in mind, please allow me to explain some of
the challenges of these projects, and some of the policy issues that
arise.
Distributed generation and net-metered generating systems are and
can be a significant and valuable component of our overall energy mix.
In order to promote the use of distributed generation the market needs
to be confident that the real or perceived barriers to quick
implementation of projects have been removed. Combining strong pro-
distributed generation policies with rate decoupling will accomplish
this task. Under rate decoupling, utility companies are indifferent to
the volume of electricity that their customers consume, as their
profitably is less likely to be impacted, positively or negatively, by
changes in consumption. By supporting and instituting rate decoupling,
in combination with strong pro-distributed generation policies, I
believe a significant opportunity exists to help strengthen and
diversify our energy mix, whether it's more cogeneration, distributed
generation, renewable generation, or more energy efficiency.
A second area to address is standardization to the greatest degree
possible, across state and utility borders. There is much to be gained
by adopting simplified and standard approaches to distributed
generation related issues. However, it is important to remember that
any distributed generation project, such as those I discussed
previously, brings together and impacts a variety of stakeholders; the
host customer, the local utility, the state, the local citizens, and
often overlooked, the local utilities of other customers. Each project,
each location, each customer has its own unique benefits and
constraints, and any standardization across territories must take this
diversity into account. For this reason, I believe that a federal model
for net-metering and interconnection standards for distributed
generation projects is an extremely important component that needs to
be addressed. This model should be based on industry best practices,
and possibly provide incentives to facilitate the adoption of these
standards. However, I believe the model should allow for the
flexibility in the system, and also allow all the local stakeholders
the opportunity to influence and impact the policies that directly
affect their local area.
In closing, Chairwoman Cantwell, I'd like to thank you and the
Subcommittee for the opportunity to speak with you today. As evidenced
by the work we have been doing and continue to do at Pepco Energy, I
feel strongly that the efficient use of energy resources and diversity
of energy generation sources, coupled with strong enabling policies,
are of extreme importance in the energy environment in which we now
find ourselves.
Thank you and I'd be pleased to answer any questions.
Senator Cantwell. Thank you, Mr. Weiss.
Ms. Kowalczyk, thank you.
STATEMENT OF IRENE A. KOWALCZYK, DIRECTOR, ENERGY POLICY AND
SUPPLY, MEADWESTVACO CORPORATION, GLEN ALLEN, VA
Ms. Kowalczyk. Chairwoman Cantwell, members of the
subcommittee, I very much appreciate the opportunity to testify
before you today. I am employed by MeadWestvaco Corporation, a
global leader in packaging and packaging solutions with $6.6
billion in revenue, 22,000 employees worldwide. We are members
of the Industrial Energy Consumers of America, IECA, a trade
association on whose behalf I am also testifying.
The purpose of today's hearing is to consider policies that
promote the deployment of distributed generation because of the
numerous environmental and other benefits distributed
generation provides. Today I will focus on just one kind of
distributed generation, co-generation, which is also called
combined heat and power, or CHP.
CHP allows a manufacturing facility or a commercial
building to recycle its waste energy to very efficiently
produce power and steam energy. CHP technology produces power
that is at minimum 100 percent more energy efficient than
technology used by the electric utility industry and it
significantly emits less carbon dioxide air emissions and uses
less water. The technology is commercially available and
extraordinarily reliable.
The problem is that over the last several years, Federal
and State barriers have been erected that are preventing the
proliferation of its use. Removing these barriers is of great
importance to MeadWestvaco, the paper and forest products
industry, and all IECA member companies.
MeadWestvaco is a leader in the use of CHP technologies
producing over 70 percent of the power requirements at our
domestic pulp and paper mills through co-generation. But there
is much more potential for its use in the U.S. overall.
A December 2008 Department of Energy report states that
there is a potential for CHP to supply up to 20 percent of the
U.S. electricity generating capacity by 2030. In doing so, we
could avoid 60 percent of the projected increases in carbon
dioxide emissions over this time period. This is a huge
opportunity for the Nation to become more energy efficient, to
reduce greenhouse gas emissions at a reasonable cost. It would
also increase jobs and the competitiveness of the manufacturing
sector.
We have identified nine barriers and solutions for each in
the written testimony. Working in the energy area for over 20
years, I have personal knowledge that the barriers are real,
and my company has experienced firsthand the increased costs,
delays, project cancellations, and significant opportunity lost
from the imposition of these policies.
The first category of barriers includes those associated
with an overall Federal regulatory policy direction which does
not sufficiently distinguish CHP from merchant powerplants.
This is seen in the interconnection rule for facilities larger
than 20 megawatts where CHP units have to go through the same
costly, lengthy, and complicated process that merchant
generators do if they seek full compensation for the power they
may want to sell to the grid.
In addition, under the rules' deliverability standard, a
new CHP unit is not allowed to compete on price with the
incumbent for the use of the grid even though the incumbent may
be a less energy efficient generator. A manufacturer or
developer that wants to locate a CHP unit at a manufacturing
site which is in a transmission-constrained area would be
required to finance transmission upgrades as part of the
interconnection process.
The second category covers more traditional financial
barriers that include the basic cost of the CHP facility, the
lack of a long-term price certainty in wholesale markets which
makes it difficult to finance projects, tax incentives that are
limited to facilities of 50 megawatts and smaller, the threat
of exit fees, life-of-contract demand ratchets in industrial
tariffs, and prohibitive costs for standby and maintenance
power needed by the manufacturer.
Other barriers on our list include environmental permitting
and new burdensome reporting requirements instituted by the
Electric Reliability Organization for interconnected facilities
that make sales to the grid.
A new looming barrier is climate change legislation that
does not recognize the environmental benefits of CHP as
compared to an electric utility powerplant alternative.
It is vitally important that these barriers be addressed.
We look forward to working with members of the subcommittee on
these issues. I would be pleased to take any questions you may
have. Thank you.
[The prepared statement of Ms. Kowalczyk follows:]
Prepared Statement of Irene A. Kowalczyk, Director, Energy Policy and
Supply, Meadwestvaco Corporation, Glen Allen, VA
Barriers to Increased use of Cogeneration, Distributed Generation
and Recycled Energy
MeadWestvaco Corporation (MWV) is a global leader in packaging and
packaging solutions with $6.6 billion in revenue and 22,000 employees
worldwide. We currently have facilities in 30 countries and serve the
world's largest consumer product brands with packaging in healthcare
and pharmaceuticals; cosmetics and personal care; food and beverage;
home and garden; and media and entertainment. Our other leading
businesses include Consumer & Office Products, and Specialty Chemicals,
which uses byproducts of the papermaking process to develop solutions
for air and water purification, asphalt performance additives, and
emulsifiers and dispersants.
MWV is part of the forest products industry which is the leading
producer and user of renewable biomass energy, and is a member of
American Forest and Paper (AF&PA), the national trade association for
the industry. Much of my testimony today is based on my experience as a
member and chair of the AF&PA Energy Committee, leading the industry's
advocacy efforts on energy policy.
Sixty-five percent of the total energy used at AF&PA member paper
and wood products facilities is generated onsite from carbonneutral
biomass. The industry also is a leader in highly efficient cogeneration
of electric power (also called Combined Heat and Power or CHP), much of
it from biomass, both for internal use and for sale to the power grid.
Since 1972, AF&PA member pulp and paper mills have decreased the use of
fossil fuels and purchased energy per ton of product by 56%. From 2004
to 2006, they reduced their use of fossil fuels and purchased energy
per ton of production by 9%. This was mostly achieved by extensive use
of CHP technologies. In 2006, AF&PA member pulp and paper mills
produced more than 28.5 million megawatt hours of electricity. This
represents one third of the industrial CHPgenerated energy in the U.S.
Co-generation or CHP is the sequential or simultaneous generation
of electricity and thermal energy (usually in the form of steam) from
the same fuel for use at a host facility that makes both electricity
and another useful product or service requiring heat. With CHP,
relatively little heat value of fuel is wasted compared to conventional
generating processes. This is the basis for the savings. In general,
CHP is about twice as efficient at using fuel compared to the standard
electricity generating technology. Because CHP systems use less fuel,
they produce fewer emissions to the air; so there is also less
particulate, Carbon Dioxide (CO2), sulphur oxides
(SO2), nitrogen oxides (NOX) and other pollution
emitted than in utility systems using the same fuels. Adding CHP power
generation units widely dispersed throughout the electrical grid also
improves system reliability in that the electrical system is less
dependent upon any single generation unit. Since the power which is
cogenerated is typically used locally, investments needed in
transmission infrastructure are reduced and electric transmission and
distribution line losses are also lower, often as much as 7%.
MWV's three domestic mills co-generated 1.86 million megawatt hours
of power in 2007 which represents almost 70 percent of these mills'
total power requirements. Use of CHP saves millions of dollars in
energy costs annually and reduces our CO2 emissions
significantly compared to purchasing all of our power from the local
utility. In addition, since most of the fuel used in our cogeneration
facilities is biomassbased, our CO2 emission reductions are
further enhanced.
The Department of Energy (DOE) stated in a report issued in
December 2008 that thencurrent use of CHP nationwide avoids more than
1.9 Quadrillion Btu of fuel consumption and 248 million metric tons of
CO2 emissions compared to traditional separate production of
electricity and heat. This CO2 reduction is the equivalent
of removing more than 45 million cars from the road. According to the
DOE, CHP was almost 9% of US power capacity in 2007. In the same
report, the DOE states that if CHP were to supply up to 20% of U.S.
electricity generating capacity by 2030 (241 GW of CHP out of 1,204 GW
total), the projected increases in CO2 emissions would be
cut by 60%.
The many benefits and value provided by CHP was recognized with the
passage of the Public Utility Regulatory Policy Act (PURPA) in 1978.
PURPA sought to encourage cogeneration and small power production as
well as renewable power production by guaranteeing that these
facilities would not be discriminated against when connecting to the
electrical grid, by ensuring that they could get supplemental, backup
and maintenance power at just and reasonable rates and by requiring
that utilities purchase power from facilities that met PURPA
qualifications at the cost the utilities avoided by not having to build
additional power plants or purchase power from the wholesale market.
For 20 years since the law's passage in most parts of the country the
increased use of CHP and power generation from renewable energy sources
was fostered by implementation of these basic principles. Over that
time period cogeneration and power production from renewable resources
increased from 4% to nearly 9% of US power generation.
In certain parts of the country there was continued resistance to
implementing the federal law. As a result, policies were put in place
which continued to provide preferential treatment for utilities' power
plant build options. For example, in some jurisdictions there were no
provisions for mandatory competitive bidding, utilities' true avoided
costs were not transparent and the tariffs established by the state
regulator for PURPA-qualified facilities to sell power to the local
utility did not provide the assurances needed to secure financing for
CHP facilities. Developers asserting their federal PURPA rights at the
state level incurred significant litigation costs. Many ultimately gave
up and developed their projects in more CHP friendly parts of the
country where they could also find the steam hosts they needed to build
these PURPA-based projects.
In some states the Public Utility Commissions required the costs of
purchase power agreements to flow through the fuel adjustment mechanism
at cost. Since the utilities involved were not afforded an opportunity
to earn a return on the capacity component of these agreements, they
resisted entering into PURPA based purchased power agreements. In
contrast, utilities are typically given an opportunity to earn a return
on the equity invested under the self build option. Therefore this
regulatory treatment created a bias against CHP.
Over the last 10 years, regulatory barriers, often in the name of
improving the reliability of the nation's power grid, have negatively
affected the growth in CHP. The problem was further exacerbated with
the passage of the Energy Policy Act (EPAct) of 2005, which
substantially revised PURPA. Under the Federal Energy Regulation
Commission's (FERC) interpretation of this law, utilities are not
required to demonstrate that their markets were functionally
competitive before being relieved of their PURPA mandatory purchase
obligation. In effect, the utility simply has to be a member of an
established Regional Transmission Organization (RTO) or Independent
System Operator (ISO) to be automatically exempt.
In its interpretation of the law, the FERC also placed the burden
on CHP generators to prove discrimination in the implementation of an
Open Access Transmission Tariff (OATT). An OATT is a FERC approved
tariff designed to provide nondiscriminatory open access to the
transmission system. Under the FERC OATT, all nonutility users of the
grid are to be afforded access under the same terms and conditions as
utility users. However, in practice, nonutility users have not received
nondiscriminatory access as was intended by the FERC. This is primarily
because of utilities' right to preserve transmission capacity for
future native load.
In mid-December 2008, the D.C. Circuit Court affirmed the FERC's
decision. These interpretations are important because they effectively
end the purchase obligations for utilities in a large part of the
nation. Although existing contracts were not affected, any qualified
facility seeking a new arrangement for expanded or additional capacity
may find itself with little leverage in negotiating with utilities.
They will have to interconnect with the RTO or ISO and deal with the
barriers associated with doing so, discussed below.
Barrier #1: Interconnection Standards Remain a Deterrent to CHP Entry
Interconnection policy has broad implications for competitive entry
of cogenerators and other forms of distributed generation. FERC has
finalized new generation interconnection rules for both small
facilities with capacity less than 20 MW and for larger generators with
capacity greater than 20 MW. These rules represent an improvement in
many areas of interconnection policy. The FERC standards are the
default only if the RTO or ISO has not set its own unique standard. The
following RTOs or ISOs have been developed in the U.S.: ERCOT ISO,
California ISO, SPP RTO, MISO RTO, PJM RTO, NY ISO and NE ISO.
A significant barrier to entry for cogenerators is a concept called
``deliverability'' which requires generators and CHP seeking to
interconnect to potentially have to finance transmission facility
upgrades. This standard requires that generators have to prove that
their output is deliverable to load and if it is not, then they have to
finance the transmission upgrades necessary to make the power
deliverable. This approach is generally incompatible with competitive
entry into ISO/RTO markets.
The FERC interconnection rule defines a dual approach with two new
types of interconnection services: ``Energy Only Service'' and
``Network Resource Service.'' The standard is based upon the PJM model
of interconnection. Facilities that qualify as a Network Resource
Service are guaranteed a much higher price for their electric power
than Energy Only Service. To obtain Network Resource Service status in
PJM for example, facilities must go through an extensive three prong
interconnection process and pay the cost of upgrading the transmission
system if the studies show that such upgrades are necessary for the
power to be ``deliverable'' to load. Even though this money is refunded
with interest over time in bill credits for transmission service,
facilities seeking to interconnect must put up this money upfront to
fulfill the interconnection requirements. Facilities can only
participate in PJM's auctions to receive a capacity payment from the
administered capacity market if they are fairly far along in the
interconnection process toward becoming a Network Resource.
The ``deliverability'' standard provides for the reduced price paid
to ``Energy Only Service'' providers which do not become ``Network
Resource Service'' providers. This is because these new entrants are
treated as the ``marginal unit'' which must be worked into the mix and
be capable of running simultaneously without disturbing the incumbent
units' ``right'' to run. This preference of Network Resource Service
units over Energy Only Service units is used even when the Energy Only
Service units can provide power at a lower price than Network Resource
Service units. Under FERC's dual Energy/Network interconnection
standard, the concept of ``deliverability'' limits competition from new
entrants who wish to displace higher cost incumbents from the
transmission system.
Another aspect of meeting the ``deliverability'' standard for CHP
facilities in some RTOs is that they must demonstrate that their power
output is ``deliverable'' to the market. In the impact study phase of
the interconnection process the RTO assesses what upgrades are
necessary to deliver power from the CHP to the market without the
industrial load being present. It is virtually impossible for the CHP
to be able to deliver this power if the industrial site to which it is
intrinsically tied is assumed to not exist. Unlike merchant generators,
larger scale CHP facilities cannot be sited to minimize interconnection
costs posed by the deliverability standard as they usually colocate at
the already existing industrial site. As a result, CHP plants
oftentimes limit themselves to making sales into the nonfirm energy
market (Energy Service Only--lower price) in order to avoid the burden
imposed by the deliverability standard.
Barrier #1: Solution
It should not be the responsibility of the new entrant offering a
lower price designed to displace the incumbent's facility for the
benefit of consumers to build transmission facilities in order to
compete for the same load. In a purely physical sense, any unit
connected reliably to the electric grid and capable of delivering
energy to any load is ``deliverable'' to that load. The interconnection
standards which rely on the ``deliverability'' concept are overly
burdensome, but they need not be so. This is evidenced by the approach
taken by the New York and New England ISOs that adopted a non-
discriminatory standard as a regional variation to FERC's rule. This
standard, known as the Minimum Interconnection Standard, maximizes
competitive entry to the grid. In RTOs that have adopted this
alternative standard, any unit which is interconnected to the grid in a
fashion which preserves the reliability, stability and existing
transfer capacity of the grid (without expanding the grid) is entitled
to compete in both the capacity and energy markets. If there is not
enough transmission infrastructure to ``deliver'' the output from both
the new and existing units, then the units are forced to compete on the
basis of price to determine which unit gets dispatched. The current
FERC and PJM concept of ``deliverability'' in the interconnection
standards should be abandoned. The Minimum Interconnection Standard
used in the New York RTO and New England ISO should be adopted by the
FERC as the default and by all the RTOs and ISOs in the nation.
Barrier #2: Discriminatory Treatment of Behind the Meter CHP
RTOs and ISOs have repeatedly attempted to interfere with CHP in
the area of ``Behind the Meter'' pricing. ``Behind the Meter''
generation refers to electricity generated on site at a facility that
is not sold to a RTO or ISO or to another wholesale entity. The RTOs
and ISOs have attempted to charge customers who supply their own needs
with ``Behind the Meter'' generation as if they had taken their entire
power supply from the RTO/ISO-controlled grid. They try to charge for
transmission, ancillary services and administrative fees based upon the
total electrical consumption of a manufacturing facility, rather than
the ``net'' amount actually taken from the grid. This cost allocation
scheme is known as ``Gross Load'' pricing.
Gross load pricing failed in the PJM RTO when an equitable
settlement was reached between PJM and Behind the Meter generators,
most of which were owners of CHP installations. However this issue
continues to be raised in the context of a resource adequacy cases and
in other proceedings. In a rehearing of a MISO case (Dkt. ER08-394-
001), the FERC reversed itself and decided to disallow the netting of
Behind the Meter generation from gross load for purposes of utility
native load forecasting and for calculations of planning reserve margin
requirements. This illustrates that owners of Behind the Meter CHP
facilities must remain continually vigilant in their advocacy efforts
on this issue as the challenges to the appropriate treatment of Behind
the Meter generation is a recurring problem.
Barrier #2: Solution
In order to prevent this issue from being a continual deterrent to
increased CHP implementation, legislative language should be developed
which would ensure that CHP and distributed generators will not be
required to pay for services on a ``Gross Load'' basis and that
services paid for will be based on the ``net'' amount actually taken
from the grid or utility.
Barrier #3: Operational Challenges Faced by CHP in an RTO/ISO
Environment
CHP facilities like those operated by the manufacturing industry
are different than merchant or utility power plants that only have one
purpose which is to produce electricity for sale. While a CHP may elect
to sell power into an electrical transmission grid, its primary
function is to support the host facility by providing electric power
and steam or other useful thermal energy for the manufacturing process.
The FERC program to standardize the use of the grid through the
development of RTOs and ISOs fails to recognize this important
difference.
Generally the operating rules developed by RTOs and ISOs fail to
recognize the significant operational differences between cogenerators
and merchant generators. This is the case even though the FERC has
acknowledged in a California case where the issue was specifically
addressed that qualified CHP facilities differ in purpose and operation
from traditional generators and that reducing the host facility's
control over the curtailment and dispatch of their power could lead to
process, safety and health problem for the host facility.
RTOs and ISOs often require that interconnected generators,
including onsite CHP, be under their control, even if the generator is
not making sales to the market. This requirement allows an RTO to
dispatch a CHP's entire power production capability to other uses based
on the needs of the electrical transmission grid, irrespective of the
needs of the CHP's primary business. This requirement is a significant
disincentive for any industrial CHP facility seeking access to the
grid.
Barrier #3: Solution
The RTO or ISO cannot accommodate the dynamic requirements of CHP's
industrial processes when the first priority of a CHP facility is the
provision of steam or heat to the industrial host. The RTOs and ISOs
should not mandate that CHP facilities comply with all the operational
rules developed for merchant generators listed in their generic tariff
provisions and mandated by execution of their operating agreements.
Instead, they should increase flexibility of the tariff to allow for
the refinement of contract terms to accommodate any particular needs
and concerns with respect to the curtailment and dispatch of CHP. This
accommodation of CHP is warranted in light of the economic and
environmental benefits that accrue from CHP operations.
Barrier #4: Financial Barriers to CHP
CHP projects with power sales to RTOs are much harder to finance
than sales under long term contracts with utilities at avoided cost
under PURPA. This is because power sales agreements with utilities
under PURPA would typically establish a capacity payment for about a 20
year term. In RTOs such as PJM where a separate capacity market exists,
sellers can have price certainty for capacity payments on a three year
maximum forward basis. For example, by the end of May 2009, sellers of
capacity on PJM's system will know what they will be paid through May
2013. The lack of long term price certainty, which was afforded by
PURPA's mandatory purchase obligation, is a major deterrent to
financing the installation of new CHP.
Despite the guidelines provided in PURPA for the design of just and
reasonable utility rates for standby and maintenance power needed for
CHP facilities, some Public Utility Commissions approved very high
rates for these services. This has proven to be a real barrier.
Barrier #4: Solution
Develop a Clean Energy Standard Offer Program (CESOP) as national
policy to reduce the barriers to entry for CHP and recycled waste
energy facilities. The federal government should require states to
offer long term contracts for the purchase of electric power from
facilities that utilize waste energy, recycled energy and other clean
technology. Under CESOP, state regulators determine the cost of
delivering electricity from the best new, electric only power plant
that meets environmental standards and then offers long term contracts
for clean energy at 80% of that cost. Two different CESOP rate
structures are possible depending on whether the power is generated
from industrial waste energy or from new CHP that meets the annual
efficiency tests. Both structures would ensure that the state obtains
clean energy at a cost below what it would pay for power from new coal
fired centralized facilities. Utilities would be allowed to earn a
return on the capacity provided by the new CESOP facility. The contract
term of 20 years would remove the financing problem mentioned above.
Another suggestion for consideration is to provide feedin tariffs
to encourage the development of CHP resources. This approach is being
used in the European Union as part of their cogeneration directive. A
feed-in tariff is an agreement between an electricity generator and a
utility whereby the former is paid an agreedupon rate (could be the
CESOP rate or another rate set by the regulator) for electricity that
is fed back onto the grid. This kind of arrangement can be used to
deliver all of the CHP production to the utility or it can be used to
deliver the excess electricity produced. The over-arching principle is
that it allows for optimization of the CHP facility to ensure maximum
efficiency.
All states should be encouraged to review the design of their
standby and maintenance rates to ensure that they are consistent with
the guidelines provided in PURPA.
Barrier #5: Exit Fees and Life of Contract Demand Ratchets at State
Level
In 1996, the Code of Alabama (37-4-30) was amended to allow
electric utilities to impose exit fees on industrial customers who seek
to serve their power requirements from CHP facilities owned by entities
other than themselves (third-party CHP). The argument used to support
this practice was that utilities incurred ``stranded costs'' due to the
industrial seeking more energy efficient options for their steam and
power supply. The utilities argued that recovering these ``stranded
costs'' through an exit fee on those who obtain power from such CHP
facilities and who leave the utility system is justified since it
protects those customers who remain on the system. Many thirdparty CHP
facilities which should have been built in Alabama to serve industrial
load since 1996 were not built because the threat of an exit fee
significantly affected the economics of the project. This law, which
has not been repealed, protects the utility's franchise, continues to
sanction a highly discriminatory practice and prolongs inefficiency in
the generation of power.
Some utilities throughout the country have life of contract demand
ratchets in their tariffs for large industrial customers. These serve
as a deterrent to increased installation of CHP since the industrial
customer must pay for up to 75% of the demand listed in its contract
regardless of whether it takes the power or not. Many customers faced
with the cost of this potential demand ratchet wait to install or
upgrade their CHP facilities until after the initial term of their
contract has expired. Often the contract can then be cancelled during
an annual rollover period to minimize costs incurred from this demand
ratchet. Sometimes, if the customer will continue to buy any power, the
utility has the discretion under their tariff to decide whether it will
allow the contract to be cancelled. The customer may have to file a
complaint with the state PUC if the utility is unwilling to voluntarily
reduce the contract demand level.
Barrier #5: Solution
It is a national imperative to require State Public Utility
Commissions to remove tariff language which can be a barrier to
increased use of CHP. State legislatures should also be encouraged to
review their Code to ensure that any laws still on their books that are
a barrier to increased use of CHP are repealed as soon as possible.
Federal legislative language should encourage states to not tolerate
any discriminatory practices in either their Rules and Regulations or
in the Code.
Barrier #6: Environmental Permitting
The lengthy and extensive process to secure environmental
permitting for CHP is a barrier to entry. The DOE has stated that 31
states regulate emissions based on heat input levels (lb/MMBtu). Such
approaches do not recognize or encourage the higher efficiency or the
pollution prevention benefits offered by CHP. In addition, major new
emission sources are required to meet New Source Review (NSR)
requirements to obtain operating and construction permits. NSR sets
emission rates for criteria pollutants and requires installation of the
Best Available Control Technology (BACT). New sources are also required
to offset existing emissions in nonattainment areas. As a result of
these environmental deterrents, CHP facilities are often times not
installed because even though they may represent marginal improvements,
they do not achieve BACT or sufficient offsets are not available in
these nonattainment areas for the new facility to get built.
Barrier #6: Solution
Expedited and streamlined permitting procedures for CHP facilities,
which will increase the energy efficiency of an industrial operation,
are greatly needed.
The DOE has rightly pointed out that output based approaches to
regulation that include both the thermal and electrical output of a CHP
process can recognize the higher efficiency and environmental benefits
of CHP. Although some states, primarily in the northwest, have adopted
output based approaches, the majority of the states have not done so.
Legislation could encourage states to move in that direction.
Provisions should be made to allow CHP facilities to get permitted even
if they are not necessarily achieving BACT as some improvement is
better than no improvement at all.
Barrier #7: Treatment of Existing and New CHP in Proposed Climate
Change Legislation
Another potential deterrent to the expansion of CHP looming on the
horizon is in the treatment of existing and new CHP facilities in any
greenhouse gas reduction program. All climate change cap and trade
proposals presented so far provide inadequate recognition of, and
incentives for, CHP in the manufacturing sector. Although producing
power via CHP uses energy more efficiently than producing utility
power, direct (onsite) emissions of a facility using CHP will typically
be higher than if the facility only produced thermal energy and
purchased all electricity from offsite. Since the benefit of a CHP
system is reducing indirect emissions (i.e., from purchased
electricity), a capandtrade program where compliance is measured solely
on reducing direct emissions will not adequately account for the
benefits of CHP. It is critical that the efficiency gains associated
with CHP systems of all sizes be properly recognized in a capandtrade
system. Otherwise industry with untapped cogeneration potential will be
hesitant to install new CHP because they will have to secure allowances
to emit from the new facility while not receiving any credit for the
reduced power consumption.
Another barrier will potentially emerge when developing the
methodology for allocating free allowances in any cap and trade
program. The two most commonly discussed methodologies for allocating
free allowances are based on either: 1. historic direct emissions (not
including purchased power) or 2. a percentage of a product benchmark
within that industry sector.
The problem with the historical emissions approach is that it does
not consider the superior energy efficiency attributes of existing CHP
and treats such facilities similarly to a utility plant. The historical
emissions approach imposes a cost on polluters but provides no
incentive to existing clean energy sources such as CHP. Emissions based
approaches also do not provide an incentive mechanism as its basic
construct for the nation to become as energy efficient as possible
through CHP and distributed generation resources. This will be a major
deterrent to new CHP being developed.
The problem with providing a percentage of a product benchmark
within the industry is that it does not provide any credit for any
industry that has, in order to remain competitive in a global
marketplace, already taken great measures in becoming as energy
efficient as possible through the extensive use of CHP. As a result,
their specific product benchmark will be lower, reflective of the
extent to which this industry has embraced CHP or other energy
efficiency technologies over the years. This is especially true for the
pulp and paper industry that has an exemplary track record in having
embraced and installed CHP technologies. Such industry should be
awarded for that activity, not compared to its own industry benchmark
that by its very construct already reflects that activity.
Barrier #7: Solution
Climate change policies should recognize the benefits of, and
promote investment in, CHP by providing credit for the avoided
emissions associated with an existing and new CHP units. If a cap and
trade program is established, special provisions will need to be made
for CHP systems as current cap and trade approaches provide no credit
for the energy efficiency provided by such systems. Any climate change
proposal should promote investment in CHP by providing credit for the
avoided emissions associated with a CHP unit. The accounting credit for
energy efficiency increases should be equal to the difference in
CO2 emissions generated by a CHP system as compared to the
equivalent CO2 emissions associated with generation of
electricity by utility companies and the separate onsite generation of
thermal energy. Each facility may then deduct those CO2
emissions savings associated with that CHP unit from emissions
regulated under a GHG regulatory program. Any surplus credits generated
by a facility shall be eligible for an emissions reduction credit.
Another option to consider as an alternative to the emissions based
approach for allocation of allowances is an output based approach which
is based on efficient energy production instead of efficient product
production. One such output based approach would award each electric
producer, including a CHP facility, with initial allowances of 0.62
metric tons of CO2 emissions per delivered megawatthour of
electricity. In addition, each thermal energy producer would be
provided with an initial allowance of 0.44 metric tons of
CO2 emissions per delivered megawatthour of thermal energy.
These allowances reflect the 2007 average national emissions for
electric and thermal. The next step requires every plant that generates
heat and or power to obtain allowances equal to its CO2
emissions. This encourages all actions that lower greenhouse gas
emissions per unit of useful output and penalizes above average
pollution per unit of output, thereby unleashing innovation and
creativity. It also would measure an industry based on its efficient
energy production and award those industries that have historically
already undertaken those initiatives.
However, should an emissions based approach be ultimately adopted,
a solution to removing the deterrent to increased CHP would be, as
discussed above, to establish a mechanism for transferring emissions
allocations from a utility, which would see reduced emissions from the
installation of CHP, to a CHP system, which would increase its direct
emissions.
Barrier #8: Lack of Incentives for Large Scale CHP
There is some interest in promoting CHP in climate change proposals
which have been filed to date but unfortunately they only focus on
small CHP facilities. At the present time there are no incentives
whatsoever for large scale CHP facilities, yet these facilities face
the same barriers to entry as do the smaller CHP.
Recognizing the benefits of distributed generation, the American
Clean Energy and Security Act discussion draft renewable energy
provisions provide that distributed generation facilities receive three
renewable energy credits (RECs) for each megawatt hour of renewable
electricity they generate. This legislation defines distributed
generation facility as a facility that: generates renewable electricity
``other than by means of combustion''; ``primarily serves 1 or more
electricity consumers at or near the facility site''; and can be no
larger than two megawatts in capacity.
The Energy Efficiency Resource Standard (EERS) provisions in the
discussion draft, like other EERS bills, define CHP to exclude
facilities with net wholesale sales of electricity exceeding 50 percent
of the total annual electric generation by the facility. This
disincentive for CHP is inconsistent with the EERS policy objectives.
All the customer facility savings from electricity generated by CHP
facilities should qualify under any EERS.
The recent revision of tax policy to provide incentives for any CHP
up to 50 MW in size is a positive development but such incentives
should not be size limited. There are many potential cogeneration
facilities at industrial sites which are not eligible for the
investment tax credit because they need to be larger than 50 MW to
capture economies of scale.
There are state practices that are discriminatory towards CHP in
the provision of natural gas delivery services to CHP facilities.
Barrier #8: Solution
As a member of an industry that is a leader in the use of CHP, we
believe that our significant investment in CHP should be rewarded.
Specifically, any climate change or energy bill should provide extra
renewable energy credits (REC) for electricity generated through CHP,
regardless of the size of the generation facility. It is inconsistent
with the policy goals of an RES to limit extra RECs only to small
facilities, as larger facilities provide the same environmental and
greenhouse gas reduction benefits as do smaller facilities. The
strained definition of distributed generation facility is unnecessary
and should not be adopted.
The EERS portion of any proposal whether it is included in a
renewable standard or on a stand alone basis should allow all of the
output of CHP facilities to qualify for energy savings regardless of
the amount of the net wholesale sales of electricity generated by the
facility. A facility should not be disqualified as a ``CHP system'' no
matter how much electricity it sells, and all its electricity should be
eligible for the CHP savings calculation.
All CHP should be eligible for an investment tax credit, regardless
of size.
It may also be appropriate to establish targets for CHP and
recycled energy that increase capacity installation and operation. In
particular, CHP and recycled energy should be declared acceptable to
meet at least half of the requirements in any adopted policy requiring
a percentage of power purchased for resale by utilities to come from
renewable or energyefficient sources of electric generation.
Incentives should be provided for states that adopt, for
jurisdictional utilities, a natural gas delivery tariff that provides
delivery to CHP facilities at rates for transmission and distribution
service no less advantageous than the rate at which natural gas is
delivered to any other gasfired electric generator. This has already
been implemented in much of New York State.
Barrier #9: Burdensome Reporting Requirements
Another deterrent related to CHP interconnection can be found in
the EPAct of 2005 in the establishment of the Electric Reliability
Organization (ERO) to ensure the reliability of the electric power
transmission grid. All interconnected generators, including qualified
CHP facilities must become members of their regional electric
reliability organization if they want to sell any power to the grid.
They must agree to extensive reporting and other requirements imposed
by that reliability organization. Compliance with these new mandatory
requirements is time consuming and expensive and poses another barrier
to CHP connecting to the grid. These additional reporting requirements
being imposed on CHP result from the general policy direction of not
distinguishing between CHP and merchant type facilities.
Barrier #9: Solution
CHP and other distributed generation facilities making net sales to
the grid that are incidental to their main purpose should be exempt
from these new reporting requirements. Legislative language should be
developed to provide such exemptions.
Senator Cantwell. Thank you, Ms. Kowalczyk. Again, thank
you to all the witnesses for being here today and for your work
in this area. I believe--I know the chairman of the full
committee believes--this is a very important policy area and we
appreciate you being here to have this discussion.
One thing that I wanted to just start off with because you
all talked about the importance of net metering in general and
the need for standards. Obviously, we thought in the 2005 bill
that we took a good whack at this, and it did result in States
adopting various policies. But obviously, we are not getting
the full results that we would like to see. So I wanted to talk
about the various things that are out there and the differences
between them.
I know people have proposed model interconnection
standards. Obviously, NARUC has in the Interstate Renewable
Electricity Counsel, which I know, Mr. Cook, you are involved
with this. What are the differences between those standards
that would be potentially a larger national standard? What
could we do to take the best of each of these to create a
national interconnection standard? Whoever wants to start with
that.
Mr. Cook. Thank you, Madam Chairman.
I would say the difference between the model rules that
NARUC has and the model rules that IREC has--first, NARUC's
model rules are focused just on interconnection. It is
important to distinguish the interconnection rules are the
technical rules that allow a generator to interact with the
grid. Net metering is the tariff arrangement, the economic
arrangement, that that generator would have with their local
utility. Correct me if I am wrong, but I do not believe NARUC
has model net metering rules. They have model interconnection
rules, but no model net metering rules.
I think that is part of what has hampered some of the
States. EPAct 2005 also did not really have a specified model
saying these are the elements that make net metering function,
these are the things that you look for in a good net metering
rule that will allow customers of all classes, residents, small
businesses, large businesses, even industrial customers to
utilize, for example, onsite solar systems to offset part of
their electricity.
So there are very few models out there. IREC may be unique
in having the only model net metering rules in place.
With respect to the interconnection rules, NARUC was the
first to come out with model interconnection rules. They
actually predated FERC Order 2006. It was good rules at the
time, but like with FERC Order 2006, there have been a lot of
improvements that have occurred. Lots of debate has gone on in
the States where consensus amongst all the people, small
generators, utilities, the staffs of the local commissions,
have made improvements on the data base or the information that
was available both at the time that NARUC came up with their
model and FERC came up with their model.
So those improvements, I think, are enhancements that
streamline and further aggrandize the ability for small
generators to be interconnected with the grid, and I think
those improvements should be embodied in a national model
whether coming from the Senate and Congress or whether
developed at FERC through the direction of Congress to develop
the model.
Senator Cantwell. Mr. Brown, did you want to comment?
Mr. Brown. Yes. I think he makes an important distinction
between interconnection requirements and net metering.
Interconnection requirements are really about safety and
reliability of the system. If you have power going into the
system, no matter what the fuel source that gets it there,
there are dangers associated with that if you do not properly
interconnect the system. Net metering is a program to try to, I
think, in some ways jump start technologies to remove
institutional barriers that are out there.
I think where you have seen the difference in the systems
again may have to do with where the State sits. Where you have,
for example, restructured electricity markets, there is a
pretty clear distinction between the costs that are associated
with commodities, the fuel used to make the electricity, and
the delivery system, paying for the system that gets the
electricity there. Where you have got more vertically
integrated utilities, that distinction is less clear.
How you set up net metering may, therefore, be dependent
upon whether you are in a restructured State or not, and you
might want to set it up different in those two circumstances.
One size may not fill all in that case.
But interconnection--I think we need to be careful. We
really cannot use interconnection requirements to try to jump
start technologies. What we have to make sure of completely is
that they do not stand in the way of those technologies being
able to get in the system, and that was the case for many
years. A lot of the utility interconnection requirements were
used as much to discourage new technologies as they were to
ensure safe and reliable service.
Senator Cantwell. How about you, Mr. Weiss? Do you think we
should update the FERC Order 2006, so make that the standard?
Mr. Weiss. I think he was absolutely right that it is a
different situation in deregulated environments and fully
regulated environments.
Where we do most of our work is in the mid-Atlantic area in
the PJM area, and I think if we could get to a point where the
rates are fully decoupled and the utilities are neutral to how
much power is being consumed and where it is being consumed, it
will really help.
Interconnection is most definitely a safety issue and a
local system issue, and if the distributor generator owner can
get the full value for its electricity through net metering, it
will most certainly jump start many installations and
technologies.
Senator Cantwell. Ms. Kowalczyk, did you want to comment on
that?
Ms. Kowalczyk. We do not particularly have a point of view
with regard to the net metering for the smaller facilities.
However, I would make a point with regard to the revenue
decoupling discussion. Manufacturers are not in favor of the
revenue decoupling type schemes because we need to see the
savings in our electricity bills in order to implement energy
efficiency projects, be they co-generation or anything else. If
you are decoupling the revenues from the sales of the utility,
it will take away that incentive for the manufacturer to
implement those energy efficiency projects because you are
paying basically the same rate that you would have otherwise
paid, and that is a real problem.
Senator Cantwell. What do you think the California
experience has been? Are you familiar with that?
Ms. Kowalczyk. Somewhat. They do not have an awful lot of
manufacturers in California. We have seen a reduction in the
manufacturing base in California. I think that the electricity
costs are very high in California. They may not have seen the
huge increases in the demands out there because of the
decoupling schemes, but their costs are high.
Senator Cantwell. We will get back to that in a minute. I
want to let my colleague, Senator Bingaman, ask questions.
The Chairman. Thank you very much.
On the interconnection, first of all, I guess I am hearing
a fairly consistent message from folks that there really is no
logical reason for not having uniform interconnection standards
across the country. Is that right, or does somebody have an
argument as to why there should be differences in the
interconnection standards from State to State to State?
Mr. Brown. I am not going to try to pretend to be an expert
about all 50 State systems, but I do know--and while we have
managed to come up with an interconnection standard in New
York, system configurations can differ greatly, for example,
between a New York City type system with the underground
feeders and Upstate New York, fairly rural in character at
certain points. The same rules do not always precisely apply
with those differing sort of systems. I would assume that
probably is even more true as you get into other systems with
very different configurations in the West than we see in the
East. It is not saying--we have managed to come up with a
single interconnection standard that has worked in New York.
Whether that could be applicable everywhere, I do not know.
The Chairman. Part of the argument that I have always
thought made sense for nationwide interconnection standards was
that it would simplify the market for companies that are in the
business of producing the equipment that is needed to do this
kind of thing. If you are a company and you have got to produce
a different configured widget for every State, it complicates
things and I would think discourages them.
Let me just ask Mr. Kelly. From your perspective, you folks
adopted an interconnection standard even for small generators,
as I understand it, but it has not been generally adopted. Is
that right? You sort of went over this in your testimony, but
maybe you could restate what has happened to FERC's efforts to
get an interconnection standard adopted for small generators.
Mr. Kelly. We adopted a standard for small generators that
was very, very close to the standard recommended by NARUC in
the hopes that individual States would adopt something close to
that joint model. We have not tracked that States have adopted
what standard, but I hear anecdotally--and Chairman Brown may
know this slightly better than me--that some States have not
adopted any standards and some States have adopted variations
on this joint NARUC/FERC standard.
The Chairman. What would be wrong with Congress coming
along and saying, OK, you have got 18 months or 2 years or
something to adopt this standard or something comparable in the
view of FERC, or the standard that FERC has adopted is hereby
applicable?
Mr. Kelly. From a technical point of view, I do not see any
difficulty with that.
The Chairman. Would that accomplish a significant amount if
we did that? Mr. Cook, do you think that would be a step
forward?
Mr. Cook. Yes, very much so. I will share my experience,
having been involved in State interconnection proceedings, some
20-odd State interconnection proceedings. Out of those, one
State adopted roughly the FERC language, including if you look
at the text of their interconnection rules and standards, it
mirrors and borrows heavily from the FERC rule. For whatever
the cause or the reasons, States want to go down their own
path, and even if they end up at a place that roughly equates
to what FERC did in its order, it is difficult for the folks
that I represent, the installers and the manufacturers, because
they look at it and it is different language. It may be ordered
differently. It may look like a different standard even if when
you roll back the skin of onion, it is actually the standard.
So very much so it would help to have, to the extent at all
possible, standardizing across all the States to have a
seamless interconnection standard.
The Chairman. Now, to what extent, if we did that, if we
had a standardized interconnection standard along the lines
that FERC has already put out there for consideration, does
that solve any of the problems with combined heat and power?
Does it address your issues at all, or are we talking apples
and kumquats here?
Ms. Kowalczyk. No. It is a different animal because we are
generally looking at the interconnections for the facilities 20
megawatts and larger.
But one thing that perhaps could help is if Congress were
to direct the FERC to abandon the deliverability standard that
I talked about and instead adopt the minimum interconnection
standard that has been successfully used in the New England ISO
and the New York ISO. It would reduce some of the barriers that
I have described.
The Chairman. OK.
Then on net metering, that is sort of a different kettle of
fish. Let me try to understand there. It is your position, Mr.
Cook, that there is a model net metering statute that ought to
be also dealt with the same way, put out there, and everybody
is advised to either adopt it or something very similar to it
by a certain time, or else it is going to be applicable. Is
that your view of how that problem should be fixed?
Mr. Cook. Yes, it is, and I think that would help to
address the broader patchwork, frankly, that exists in net
metering across the States. There is broader patchwork and
differentiation than there is even on interconnection. So I
think the Federal guidance there is even more important to do
roughly the same as you laid out for interconnection, yes.
The Chairman. Thank you. My time is up.
Senator Cantwell. Thank you, Senator Bingaman.
One of the reasons why I think this is so important--I
mean, obviously, infusing more intelligence into the
electricity grid is just that it will help us in trying to
reduce peak power demand as well. According to GAO, 100 hours
of annual peak demand, which is just 1 percent of total yearly
needs, accounts for 10 to 20 percent of the annual electricity
costs.
So to put that into dollars, according to the Brattle
Group, even a 5 percent drop in peak demand can yield
substantial savings in avoiding generation, transmission, and
distribution. So estimated at $3 billion a year or $35 billion
over the next 2 decades.
So I wanted to get into a little bit about this issue of
how building out a smart grid and distributed generation can
help us in peak demand. I know, Mr. Cook, you have had,
obviously, experience here dealing with this. Can you explain
how distributed generation like solar panels combined with the
smart grid helps to lower that peak demand cost?
Mr. Cook. Particularly for solar, solar is what we call in
the industry a peak generating technology. That is really by
happenstance in that in most utility grids or regional
transmission grids, the peak consumption tends to follow
sunlight. You do not tend to find areas where peak consumption
is, say, at 2 in the morning. Solar generally tracks the
demands on that. So it follows the peaks on the system for
consumption. There may be shifts. You know, the solar
production may peak at 1 or 2 in the afternoon, where the
utility peak may be 3 or 4 in the afternoon. But generally,
there is a parallel there. So solar technology, by just the
nature of the way it generates electricity, tends to offset the
peak demands that exist.
The smart meters, I think, go toward trying to reduce
people's consumption. As you and I probably do, we do not
realize that when we are running lights or a dishwasher or
something like that, is it a peak period on the grid? Is every
generator that is out there struggling to meet the demand on
the grid? I think the concept behind the smart metering is if
we can get that information out to customers, perhaps tied with
some price signal that says if you can reduce your demand now,
if you cannot use electric-consuming equipment, there will be
some financial benefit to you as well, people will reduce their
consumption during those peak periods and thereby reduce the
peak demands which, as you note, are the incredibly costly
times to put generation on the grid.
Senator Cantwell. But by reducing peak demand, we reduce
the cost to the ratepayers.
Mr. Cook. Yes. I think that equation probably holds true,
and Mr. Kelly might have some more detailed information on
that. But it is a very small percentage of the hours that leads
to a very large percentage of the total costs that are
incurred. So if you can reduce that consumption during those
few hours, typically 100 or 200 hours a year, it has a
significant impact on reducing the cost of generation. That is
because so many generators, in essence, sit idle waiting for
that peak to occur and they have to earn all their money during
those peak periods because the rest of the 8,500 hours of the
year, they are just simply not needed. So if you can get
consumers of electricity to say we are not going to use during
those critical hours, you can reduce the total costs that are
paid for generation substantially.
Senator Cantwell. Mr. Kelly or Mr. Weiss, did you want to
comment on that?
Mr. Weiss. There is a tie-in between solar net metering and
smart meters. Smart meters really is the technical way that if
we had a smart metering standard where we can measure how much
electricity is going out to the grid from a solar project that
is behind the meter and how much is going to come in, and they
could cancel each other out, which would allow the host
customer, the person who owns the solar project, to gain more
value.
Net metering, being an economic issue, is a much easier
standard to develop and put out there as a goal or as some
legislation because it does not have safety issues related to
it. It just has economic issues related to it. If you tie in a
smart metering standard with a net metering economic benefit,
it will undoubtedly create a lot more solar projects.
Senator Cantwell. Mr. Kelly, did you have a comment on
that?
Mr. Kelly. Just to reiterate a couple of points. Shaving
the peak demand is important. The Nation has made great strides
in doing that over the last few years, and we have plans to
make still greater strides in the years ahead. Congress gave
FERC some assignments to do that, and we are pursuing it
vigorously.
A lot more can be done. I think one way to do that is
through net metering.
But I would like to pick up on a point Chairman Brown said
because I think it is very important. When you are dealing with
interconnection standards, you are dealing with safety. You
want to make sure that the standard is not done in such a way
that an electrical line worker could get electrocuted because
not everything was studied properly and installed correctly.
When you are dealing with net metering, the issue is dollars.
If you are going to have net metering, what is the appropriate
compensation? It is something the States have been dealing
with, not FERC to date. But they are two very different issues:
safety versus dollars.
Senator Cantwell. We have had, I think, several hearings
that have touched on this in a broader way, obviously, with
various panelists. So I am sure we will continue.
But one of the reasons that I think it holds so much
promise besides helping drive down the cost on renewables and
taking advantage of renewables at non-peak time is that just
the combination of all of these things together, distributed
generation, smart grid, efficiency, peak demand technologies,
could be a huge source of savings for us.
In fact, I am interested in--obviously, we are trying to
move energy legislation--what you think the best case scenario
would be here for a percentage of power that could be met
through these sources. I do not know if anybody wants to take a
stab at that. I mean, could we see as much as 30 percent energy
in the future by, say, 2030 if we invested wisely in this area?
Mr. Brown. I think it depends on how wide those words you
used mean.
I was going to comment on your last about reducing peak
demand. That is obviously a tremendous goal of ours. Right now,
the most cost-effective way of reducing peak demand is just
through good old-fashioned energy efficiency programs, what we
call demand reduction programs where people respond to peaks by
reducing their usage.
If you want to combine those sort of traditional energy
efficiency programs with renewable programs--in New York, we
have already got a goal of trying to reduce our electricity
demand by 15 percent by 2015 and having 30 percent of our
electricity produced by renewables by 2015. We call that the 45
by 15 program. I think New Jersey has got a 20 by 20, trying
just on energy efficiency alone. So I think your 30 percent is
very doable if you combine all the potential opportunities that
are out there.
That is why we have to be careful, I think, again trying to
dictate this specific program or this specific technology is
the way to get there because what might work in New York may be
very different in Washington or New Mexico or Texas. The
resources are different. The systems are different. That is
why, I guess, from the States' perspective we say we are trying
to achieve very many of the same goals already on the State
level. If done wrong, Federal policies could hinder our
progress. If done right, it could really, working together,
make it happen quicker.
Senator Cantwell. That is why I think this means it
probably is one of the most significant things that we could do
because if you are saying you really could achieve 30 percent
source from energy efficiency by 2030 by combining all of these
things, smart meter technology and distributed generation, then
you do use the opportunities that exist within each region. So
you are not basically choosing any one region's energy
solutions over another. You are implementing the efficiencies
into the system and driving down costs to consumers. I do not
know anybody else who can come up with 30 percent in that short
a period of time.
In the meantime, you actually create a lot of jobs, I would
assume, by doing this as well. Obviously, the economic model
still needs to be considered.
Mr. Weiss.
Mr. Weiss. Energy efficiency is by far the cheapest way to
produce energy. What I mean by that is the energy not produced
is going to be cheaper than the energy produced. Over and over,
a good energy efficiency program with measured and verified
savings will accomplish more in saving peak energy and energy
off peak throughout the Nation. It is the least expensive,
lowest hanging fruit.
Mr. Cook. I also wanted to weigh in and point out that if
you look at the two most aggressive States with the distributed
solar program, California and New Jersey, and use their year-
over-year growth built into their program, they actually reach
30 percent of their generation from distributed solar by 2030.
Senator Cantwell. Ms. Kowalczyk, did you have a----
Ms. Kowalczyk. I would agree with what David had said.
But just back for a minute to this issue of the smart
meters, there are just so many parts of the country where we do
not have the smart rates that need to be implemented together
with the smart meters. If we cannot get the price signal to the
actual consumer, then all the smart metering in the world will
not be helpful or beneficial.
Senator Cantwell. I wanted to follow up the California
situation. I mean, given what Mr. Cook just said about
California, obviously, there are a lot of things that have been
going on with California energy prices, not just their adoption
of decoupling and moving forward on these technologies. Do you
have the specifics about how much that has impacted the cost of
energy in California?
Ms. Kowalczyk. Not specific to California. We do not have
facilities there. Sorry.
Senator Cantwell. OK.
I would like to know a little bit too from the panelists
what contribution they think renewable generation sources could
play in meeting a Federal standard. So how does a renewable
energy credit help support the market and distributed
generation especially when it comes to homeowners who want to
generate their own electricity? Does anybody have a comment on
that?
Mr. Cook. One of the programs with which I am familiar is
the New Jersey solar program which provides renewable energy
credit or a certificate for every megawatt hour of solar energy
produced, and then the New Jersey regulators, the Board of
Public Utilities, created a market for that by saying that the
people who supply electricity in the State have to include as
part of their portfolio a certain percentage which is
represented by these credits. So if you are selling electricity
in the State, maybe on an annual basis you have to go out and
purchase 200 solar credits whether it is an installation like
Mr. Weiss explained at a large facility or a homeowner can
actually then go out and sell these credits because the market
has been developed for those.
I think the last time I checked, in New Jersey they were
going for a fairly good price which represented what additional
costs it would take to install a solar energy system. That cost
comes down each year as the cost of solar installation goes up
in New Jersey and the incremental cost to install each of those
goes down fairly substantially.
Mr. Weiss. To further demonstrate that, our large solar
installation in Atlantic City basically has three revenue
components that make the returns work for us. Twenty percent
comes from selling the electricity to the host customer at just
slightly below retail rates. 40 percent of the value comes from
Federal tax credits, and 40 percent of the value comes from the
solar rent market.
Senator Cantwell. Yes, Ms. Kowalczyk.
Ms. Kowalczyk. With regard to energy efficiency being a
part of a renewable standard, we believe there should not be
any limitation on the amount of energy efficiency that could
participate in any such program. These energy efficiencies
should be allowed to compete head to head with renewables.
Senator Cantwell. I have one last question about baseload
because--I will let you off the hook on this one, Mr. Kelly,
but Chairman Wellinghoff was recently quoted as saying baseload
capacity is going to be anachronism to where we are going, and
in so many words that smart grid and distributed generation
would allow us to reshape with renewables so that we will not
need fossil fuel.
So do you agree that smart and more distributed generation
could forgo the historical requirements for some level of
baseload power?
Mr. Brown. I have had the occasion to see Chairman
Wellinghoff three times since then. So I have heard him explain
his comments three times. I think when you put them into the
context of what he was saying, it is much more understandable
to be saying.
What he was saying is, one, there is tremendous possibility
for energy efficiency that we just discussed, real savings
there.
Two, there is an incredible amount of potential for all our
renewable resources from off-shore wind, on-land wind, to
solar, to biomass, all these various technologies. So we could
meet a lot of our demand using energy efficiency and
renewables.
But I think the third point that got lost in his quote a
little bit was if we can have--right now what we have are
powerplants that intentionally are designed to move up and down
to meet the instantaneous changes in load. If we could use the
demand side, if we could use load to balance, if there was
enough sophistication in the system that load could actually
respond in real time, all of our appliances, icemakers could
shut off or shut on depending on the time of the day and the
price. You know, a silly example, but there could be chips in a
lot of different appliances that actually allow you to do that
from a demand side. Then you might not need those sort of
baseload facilities, the standard facilities that we usually
think of, the coal, the nuclear facilities, to do that.
But I think Chairman Wellinghoff would also explain we are
long way off from that, and we better not put all our eggs in
that basket. We better continue the research on coal, nuclear,
and in the near term, we are not going to be eliminating
baseload plants.
So I hope I explained what I heard his view. I agree with
that viewpoint with the ``ifs'' set up, if the efficiency, if
the renewables, if the demand side, then maybe we can change
the paradigm in the future.
Mr. Weiss. We do a lot of energy performance contracts in
large Federal facilities, in hospitals all over the east coast.
We do a lot of load following. I mean, the technology is not
that far away so that you could reduce demand. It is done in
the commercial and industrial sector for years, and I think it
could be applied residentially.
Senator Cantwell. Again, just before we close out, there is
nothing about the introduction of more smart grid technology or
distributed generation that really gives preference over one
energy source or another.
Mr. Brown. I think they all need to be part of the
solution. What we face as State regulators----
Senator Cantwell. But there is no source that takes
inherent advantage of the fact that we would create more of a
national infrastructure here.
Mr. Brown. I think it is energy efficiency that benefits
the most from the smart grid, probably more so than anything,
but also our ability to incorporate technologies like solar and
intermittent technologies like wind. The smarter and more
information there is in the grid, the easier it will be to have
instead of 8 percent of our resources be wind, to have 25
percent of our resources be wind, instead of 2 percent of our
resources be solar, to have 12 percent of our resources be
solar. The intermittency of those technologies can be dealt
better with. So it helps all of the goals I think. It is just
very expensive.
Mr. Weiss. Smart meters and net metering creates
opportunities. It creates opportunities for all renewable
energy and energy efficiency and the control of energy. I think
that is where we are going to get the most benefit in the next
10 years, next decade.
Senator Cantwell. Thank you. I want to thank all the
panelists, again, for being here today. We will keep the record
open so if my colleagues have further questions, they can
submit those and, obviously, get responses from you. But we
appreciate very much you being here today and your testimony on
this important subject.
The Subcommittee on Energy is adjourned.
[Whereupon, at 3:36 p.m., the hearing was adjourned.]
APPENDIXES
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Appendix I
Responses to Additional Questions
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Response of Garry A. Brown to Question From Senator Stabenow
Question 1. I understand the generation of heat and power accounts
for more than two-thirds of U.S. fossil CO2 emissions. I
also understand the efficiency of generating electricity has not
improved from its dismal 33 percent level since the time of President
Eisenhower. Can you describe some of the policy barriers to more
efficient power generation, specifically distributed generation?
Answer. The efficiency of producing electricity from conventional
large base-loaded steam-turbine driven sources is fundamentally limited
by the thermodynamic limitations. There are actually several separate
energy conversions at play in the conventional production of
electricity, each having its own conversion efficiency limitations.
Fuel is burned in a furnace producing heat, which is converted in a
boiler to high-pressure steam, which is then passed through a steam-
turbine producing rotating mechanical energy that spins the generator
producing electricity. Approximately two-thirds of the fuel consumed in
producing electricity by this method is lost in the process, hence the
maximum overall electricity conversion efficiency of about 33
percent.\1\ Efficiency improvement opportunities are available,
however, and have been utilized by re-capturing some of the otherwise
`lost heat' from the conventional conversion process and either using
it directly for onsite thermal energy purposes or recirculation through
a heat-recovery boiler, thereby producing additional steam and
electricity. Recapture of the `lost heat' generally increases overall
conversion efficiencies to the 50 percent-65 percent range. For these
higher efficient technologies to be utilized as distributed generators
by individual customers, however, the customers must have an inherent
onsite opportunity to economically utilize the waste heat. Since many
customers do not have a readily adaptable use for the waste heat,
distributed combined heat and power (CHP) facilities will not likely be
a cost-effective investment option for customers in most cases. And,
where there is an existing onsite use for the waste heat, economics
usually dictate that the optimal CHP system be designed to satisfy the
site's waste heat requirements, which doesn't necessarily result in an
electricity production component that is perfectly matched with the
customer's onsite electricity requirements.
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\1\ The addition of environmental controls that limit the level of
effluents emitted during the fuel combustion process, effectively
reduce overall conversion efficiencies below 33%.
---------------------------------------------------------------------------
Another factor limiting the number of more efficient distributed
CHP installations is fuel prices. CHP units typically require the use
of natural gas as their primary fuel source. While this enables in a
more environmentally compatible outcome than the combustion of other,
less expensive, fossil fuels it also tends to offset some of the
economic gains otherwise achieved from the improved conversion
efficiency.
Hence, despite the improved economics of CHP as compared to
straight conventional electricity production technologies, the bottom
line CHP costs of producing the electricity on site are not always
competitive with electricity prices available from the host utility's
electric grid. Optimization of the operation of a distributed CHP
facility, such that it minimizes the customer's overall cost serving
onsite electric and thermal requirements, requires a real time
knowledge and awareness of coincident utility service prices.
Maintaining interconnected access to the utility grid, therefore,
both enhances the customer's opportunity for minimizing the overall
cost of satisfying onsite energy requirements and assures a back-up and
supplemental supply should the customer's distributed generator fail to
operate. This also obviates the need to install redundant onsite
distributed generator capacity at individual sites to maintain service
reliability.
Responses of Garry A. Brown to Questions From Senator Risch
Question 2. We know that advanced meters allow consumers to be more
aware of how they use energy and how much energy costs at a particular
time. Would allowing the installation of advanced meters also
facilitate the adoption of distributed generation?
Answer. Installation of advanced meters will facilitate the
transfer of more detailed system pricing and operational data
(information) between the utility and its customers, and as such,
likely enhance the integrated operation of the utility's delivery
system with individual distributed generators dispersed within that
delivery system. The development of more accurate, time differentiated,
electric delivery and commodity pricing structures where appropriate,
however, will best enable the full benefits of advanced meters to be
realized by both DG and non-DG customers.
Question 3. Even with distributed generation, the local
distribution company must maintain the lines that allow for the two-way
flow of energy between the distributed generation entity and the grid.
They also must assure that there is back-up energy available in the
event that the distributed generation goes down or under-produces.
Should we devise a financial scheme that allows the local distribution
company to meet these responsibilities without having to shift the cost
to the consumer?
Answer. NARUC does not believe that it is appropriate or beneficial
for Congress to set retail rate design or retail rate policy. While we
agree that there needs to be regulatory action to allocate theses
costs, it should be a tailored decision made at the State level and not
a single federal standard or scheme legislated by Congress. The
financial scheme, however, should be the development of utility tariff
rates that more accurately and appropriately charge customers for the
services they use, regardless of what they chose to do behind-the-meter
in order to improve the efficiency or reduce the cost of meeting their
energy requirements. Ultimate across-the-board implementation of
alternative delivery rate structures stabilizes the local distribution
company's ability to recover the costs needed to meet its service
obligations and obviates the need to invoke what are in effect
discounts for some customers at the expense of other customers.
An alternative utility delivery service rate structure, Standby
Delivery Rates, is presently in place at the New York State utilities.
These rates were designed for the specific purpose of assuring the
utilities continued recovery of legitimate unavoidable fixed delivery
service costs from those customers operating their own onsite
(distributed) generating facilities, thereby mitigating the extent to
which the recovery of such unavoidable delivery service costs get
shifted to other ratepayers. These rates are presently applicable only
for those customers electing to install onsite distributed generators.
Question 4. EPACT 05 attempted to address some of the impediments
to the deployment of distributed energy resources by requiring state
public utility commissions and certain ``non-regulated'' utilities to
consider standards for net metering and interconnection. Does NARUC
believe that Congress needs to legislate a national model, or go even
further and legislate national standards?
Answer. No. I would suggest implementation details, and the tariffs
specifying such details be left to the States. It's neither necessary
nor appropriate to address these details at a national level.
Approximately 35 States currently have interconnection standards and/or
rules and approximately 42 States currently have net metering standards
and/or rules. As I mentioned in my oral remarks and answers to
questions during the hearing, there are fundamental differences between
the delivery systems across the nation (i.e. rural and urban.)
Question 5. Mr. Cook's testimony discusses the need to remove
several existing barriers to distributed generation. In your testimony
you describe a three-year process to develop model interconnection
standards in an attempt to produce a document that would remove or
alleviate most of the access issues and fit the regulatory systems in
the vast majority of the United States. What was the result of this
process? What barriers still exist, in your opinion?
Answer. As I testified, once the barriers were determined, NARUC's
members started a three-year process to develop model interconnection
standards for small generation resources in an attempt to produce a
document that would remove or alleviate most of the access issues and
fit the regulatory systems in the vast majority of the States.
This process, as well as the Federal Energy Regulatory Commission
(FERC) order 2006 process, which had extensive State involvement and
coordination, greatly improved the promise of new and cleaner
distributed generation technologies--like fuel cells, micro-turbines,
distributed wind machines, and photovoltaics--by working to
significantly reduce market barriers that existed due to inconsistent
and outdated grid interconnection standards. The end result of these
processes was the issuance by FERC of a Small Generator Interconnection
Procedures.
This procedure is a model for ISOs and/or States to use in the
development of interconnection procedures. While interconnection
procedures have improved greatly in recent years, we still have to be
vigilant that they are not causing barriers and look to improve the
procedures whenever possible. I believe that State regulators are in
the best position to monitor how interconnection procedures are working
and make the needed revisions consistent with the conditions on the
local distribution systems.
______
Responses of Irene Kowalczyk to Questions From Senator Stabenow
Question 1. I understand many paper-product companies generate
electricity, often using their own waste products or capturing and
recycling their waste heat. Such distributed generation seems to be
saving you money, cutting pollution, and generating power at much lower
cost than to buy the electricity from new centralized power plants. Do
you ever generate more power than you actually use? How much more could
you save if power markets were open and generators were not restricted
in terms of whom they could sell power to apart from utilities? What if
you were allowed to sell your electricity under long-term contracts to
a variety of possible buyers?
Answer. Paper-product companies are leaders in the use of
cogeneration technologies and these facilities often produce more power
than what is needed to serve the facilities' loads. In regulated
markets such facilities have traditionally sold excess power to their
local utilities at avoided cost under PURPA-based agreements. As a
result of the FERC's interpretation of revisions to PURPA in the EPAct
of 2005, utilities that have joined an RTO or ISO and are located in
regulated states are no longer required to purchase output from co-
generators. In deregulated markets these facilities will often sell
energy to the wholesale market directly but they will not sell capacity
because of the onerous interconnection standards discussed in answers
to several of the following questions.
Typically an excess power situation is caused by a process
disruption. An example is where there is a break of the paper on a
paper machine, shutting down the machine and almost instantaneously
reducing the mill's demand for steam and immediately increasing the
steam header pressure. The steam producing power boilers, especially
biomass based boilers prevalent in our industry, cannot react fast
enough to reduce their output so the high header pressure is relieved
by having the steam flow to the turbine generator. Under these upset
conditions more steam flows through the turbine to its condenser and as
a result more power is produced which must be delivered either to serve
plant load, the local or the wholesale grid.
Over the past 10 years many paper machines have been shut down due
to competitiveness issues, but the energy producing infrastructure is
still intact at the site. These mills which previously had cogeneration
systems which were well balanced between their power and steam
requirements now find themselves with excess turbine generator
capacity. In order to utilize these assets fully, a buyer for the power
generated in excess of plant loads must be found.
The economies of scale particular to a specific site should dictate
the size of cogeneration systems. Frequently, however, the systems are
designed to not produce excess power in order to avoid the difficult
and cumbersome issues related to selling excess power, be it to the
local utility or to the wholesale market. This results in cogeneration
systems that are sub-optimally designed and therefore their costs of
installation and operation are higher than they otherwise would be. If
excess power more easily could be sold to buyers under long term
contracts, then the cogeneration systems could be more optimally
designed, could generate more renewable, highly efficient energy, and
could displace more fossil-fuel based energy. In regulated markets this
is virtually impossible as the utilities will ensure no transmission
capacity is available to move the cogenerator's power to the buyer,
through their ability to reserve transmission capacity for future
native load. This is the case even in areas of the country where the
determination of available transmission capacity is made by an
independent entity.
When it comes to sales at the wholesale level, in RTOs and ISOs
which have established separate energy and capacity markets, we
estimate that for every 10 MW of excess power a cogeneration facility
sells as ``energy only'' into those markets today, the facility could
have obtained an estimated $365K in additional revenue per year in
payments for the capacity associated with that energy sale. This is
value usually forgone by the seller.
Question 2. Your testimony and comments at the hearing demonstrated
that while energy-intensive industries and the average family consumer
would both benefit from types of distributed generation, there are
differences between industrial and residential energy needs in a
``smart grid'' electricity framework. You mentioned that smart meters
will only work where electricity rates are ``smart rates,'' meaning
rates that adjust depending on how much is consumed within a billing
period, rather than a flat average rate, because the consumer would
need the price signal to prompt an adjustment in consumption. You also
mentioned at a different point that manufacturers are opposed to
decoupling (a rate design where utilities are paid based on how well
they meet their customers' energy service needs, rather than the
predominant design which focuses on commodity sales) because they need
the price signal of lower energy bills to implement energy efficiency
measures and reduce consumption. How can distributed generation and net
metering be promoted without decoupling?
Answer. Rates with blocks adjust charges based on how much is
consumed within a billing period. For example, a typical declining
block rate will charge a customer a higher rate for the first increment
of power purchased in any month and a lower rate for all incremental
consumption above that first block of power. Declining block rate
design has been the norm as an option for large power consumers for a
long time. ``Smart rates'' do not adjust based on how much is consumed
within a billing period but rather adjust based on the utility's costs
of generating and purchasing electricity at the wholesale level at a
particular point in time. Smart rates can change as often as hourly and
typically they would change the rate more frequently than current time-
of-use rates which change by season and usually two times in a day.
Decoupling is usually promoted as a means of encouraging utilities
to become engaged in promoting energy efficiency but it is really just
a revenue guarantee for utilities. Paying uneconomic ``rents'' to
utility shareholders to prevent them from taking actions harmful to
society (like discouraging CHP, distributed generation or demand
response) should not become accepted public policy. Every consumer will
pay the price for having our nation become more energy efficient and
less dependent on foreign energy sources. Utilities and their
shareholders should not be insulated from sharing in the sacrifices and
adjustments required of every other business in these times. A fair
opportunity for the utility to recover costs and losses should be the
standard.
One of the largest impediments to efficient deployment of CHP and
distributed generation is not utility disincentives, but incorrect rate
designs that intentionally load uneconomic costs on CHP and distributed
generation. Current rate designs often incorporate allocation
mechanisms that include charges in volumetric rates which should be in
the fixed cost component of the rate. As a result the utility loses a
disproportionate amount of revenue when a large customer paying a
volumetric rate reduces or eliminates consumption. If rates were not
improperly weighted towards volumetric recovery of costs, but were
instead properly designed to recover fixed costs through a fixed charge
and variable costs through usage charges, the dislocation would be far
less. Proper rate design removes utility disincentives towards CHP and
distributed generation.
In order for manufacturers to finance and install CHP systems, they
must be able to show savings in power costs to justify the investment.
If the utilities' revenues are decoupled from commodity sales then
manufacturers lose the main incentive for increasing efficiency--the
prospect of lower energy bills. For example a new, more efficient
boiler at a paper mill would consume less energy and cost less to run.
However since decoupling would compensate the paper mill's utility for
lost revenue, that same mill would end up paying a higher rate despite
using less energy.
As mentioned above, revenue decoupling is not needed to promote CHP
or distributed generation if proper rate designs are implemented. As
far as net metering of distributed generation is concerned, the power
which is net metered to the utility reduces the utilities' need to
either purchase power or run their least efficient generating unit,
depending on which resource is on the margin when net metered power
enters the grid. Net metering of power onto the grid affects the
variable or purchased power costs incurred by the utility but does not
affect the utility's ability to recover fixed costs.
If the public policy goal is to promote increased utilization of
CHP and distributed generation, the utilities should adjust their
revenue expectations accordingly and not be kept immune from the
impacts of these policy decisions through revenue decoupling
mechanisms. The utilities should be required to contribute their fair
share in achieving energy security and climate change goals and not be
carved out of making the sacrifices that all consumers will have to
make.
An alternative is to remove administration of energy efficiency
programs like the installation of CHP and distributed generation from
utilities and vest them in an independent agency. Several states, such
as New York and Vermont have already adopted this approach for some or
all energy efficiency and DSM programs. External administration of
programs does not remove the need for properly designed rates, but it
does eliminate the fear that utilities will not be supportive of these
programs.
Question 3. Your testimony says that FERC policy on interconnection
standards make it difficult for companies to build CHP facilities.
Please explain why the FERC policy is a problem.
Answer. The FERC Order on interconnection for large generators was
issued in 2003, the barrier raised related to interconnection has been
a concern for industry for quite some time. The question posed is best
answered by sharing the attached whitepaper prepared by Don Sipe,
outside counsel to AF&PA Energy Resources Committee. The whitepaper
shows that the FERC policy of requiring a deliverability standard in
the interconnection rule, especially as applied to a competitive
market, promotes overbuilding of transmission and discourages new
entry.
Whitepaper Attachment
Interconnection Policy--The Issue of ``Deliverability''
introduction
Interconnection Policy has broad implications for competitive
entry, Resource Adequacy, QF viability, Transmission Pricing
Policy (including Participant Funding) and Demand Response.
Poor or discriminatory Interconnection Policies restrict entry,
increase the cost of interconnection, decrease power supplies
thereby driving up prices, and limit demand response
opportunities. For all of these reasons, in both RTO and non-
RTO regions, influencing these policies is often the most
direct way to lower costs and increase competitive
opportunities.
FERC has recently finalized new generation interconnection
rules. These new rules represent a substantial improvement in
many areas. In one area, however, the rules perpetuate a
potentially discriminatory interconnection standard based on a
concept (adopted from PJM) called ``deliverability''. The
deliverability concept is generally incompatible with
competitive entry into ISO/RTO markets. New York and New
England RTOs had adopted a different, non-discriminatory
standard as a ``regional variation'' on FERC's rule. That
standard, known as the Minimum Interconnection Standard,
maximizes competitive entry to the grid. Since passage of the
Rule in 2007, FERC has required ISO-NE to move back to a dual
interconnection standard with a ``deliverability'' component.
In non-RTO markets, FERC's new Interconnection Policy
represents a significant step forward in relation to the
largely ad hoc rules which prevailed prior to issuance of the
Order. Under the new rules, utilities like Southern and Entergy
are required to interconnect IPPs or other potentially
competing generation ``on the same basis as they connect their
own units''. The Order defines two new types of interconnection
service based upon the PJM model of interconnection: ``Energy
Only Service'' and ``Network Resource Service''. This dual
standard allows some flexibility in markets without competitive
opportunities like those of the Southeast. But in markets based
on competitive principles like ISO's and RTO's, the dual
standard is not only unnecessary, but discriminatory and anti-
competitive.
The problems presented by this policy have become even more
glaring with recent developments. One of the main purposes of
Renewable Portfolio requirements and energy efficiency
legislation is to reduce consumption and displace existing
fossil fuel units with newer, less polluting renewable
resources. Yet, current interconnection policy forbids
displacement and instead requires new renewable entrants to
build transmission as if both they and the older units they
will displace have to keep running to serve load. This is
illogical, anti-competitive environmentally harmful and
economically wasteful. It discourages CHP and renewable
development.
statement of the problem
Transmission systems are built to serve load, not the
aggregate amount of generation on the system. A typical
transmission system will have more generation connected to it
than the total amount of load which is available to take
service from that generation. This is necessitated both by
reserve requirements and by competitive principles. Without
some surplus supply, competition between suppliers is
ineffectual because all suppliers are needed just to serve load
reliably.
In regions without competition, where utilities engage in
Vertically Integrated Resource Planning, there is a more
careful match between utility generation and the expected load.
With the exception of reserve requirements, utilities do not
routinely build more generation than needed to serve expected
load. he situation becomes more complicated, however, under
competition. In order to have competition, there must be a
certain amount of surplus generation. Particularly in a bid-
based market with LMP, market power concerns would be
overwhelming if generation supply ``just matched'' the normal,
vertically integrated utility planning criteria of load plus
reserves.
The two types of system; competition and vertical
integration; also affect transmission planning. In a vertically
integrated system it is much easier to plan transmission based
on the expected flow from particular generation resources to
specific load. Under competition, however, generation may come
from a variety of directions or sources to serve load depending
upon the prices offered. Under either system, however, in order
to take service from a particular generator, the generator must
be able to ``deliver'' to the load. This seems like a very
straightforward requirement. However, utilities in PJM (which
provided the model for FERC's interconnection policy) have
turned the concept of ``deliverability'' into a tool to favor
and protect incumbents against competition from new entrants in
the capacity markets.\1\
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\1\ Again, we should contrast here the situation in non-competitive
markets where insuring deliverability may force the hand of the local
utility to build and fund upgrades which would have the effect of
expanding its system. Although the deliverability concept described and
criticized hereafter might still be used by these utilities to the
disadvantage of new entrants, it is a double edged sword for a utility
like Southern or Entergy who has been extremely successful in closing
down system expansion or any other development necessary to allow
competition.
---------------------------------------------------------------------------
Under FERC's dual Energy/Network interconnection standard,
the concept of ``deliverability'' limits competition in the
capacity markets from new entrants who wish to displace higher
cost incumbents from the transmission system. Under the
``Energy Standard'' of interconnection, a unit can interconnect
in a fashion which meets all the reliability criteria for safe
operation, but will only be allowed to compete in the non-firm
energy market. Such a unit cannot be counted as a capacity
resource. To play in the capacity markets, the unit must be
connected under the ``Network Resource'' standard which
requires a study to prove that output from the unit is
``deliverable''.
By contrast, prior to FERC's ruling, in New England and New
York, any unit interconnected to the grid in a fashion which
preserves the reliability stability and existing transfer
capacity of the grid (without expanding the grid) was entitled
to compete in both the capacity and energy markets. If there
was not enough capacity on the transmission system to
``deliver'' the output from both the new and existing units,
then the units were forced to compete on the basis of price to
see who gets chosen as a capacity provider. Whoever wins the
bidding war is dispatched and is obviously ``deliverable'' to
the load. If the system needs to be expanded so that more
generation in total can be delivered from, say, a low cost to a
high cost area, that decision is made by the Independent System
Operator, and the expansion is made part of the transmission
plan. New entrants are not forced to expand the system so
incumbents who they have underbid can continue to ``deliver''
to load who would rather buy from the new, cheaper source
anyway.\2\ This pro-competitive notion of deliverability,
however, is not the concept embodied in the FERC Network
Interconnection Policy. Under the Network Resource Standard,
deliverability means insuring enough transmission is built to
protect incumbents from being displaced.
---------------------------------------------------------------------------
\2\ For a thorough discussion and critique of the FERC's dual
interconnection standard and problems it creates for competitive
markets, see Motion to Intervene, Protest and Comments of the
Industrial Energy Consumer Group, Docket No. ER04-433-000 which can be
made available upon request if there is interest in a more in-depth
discussion.
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the concept of deliverability as misused by the pjm standard
In a purely physical sense, any unit connected reliably to
the electric grid and capable of delivering energy to any load
can deliver both energy and capacity with no further
modification of the electrical system. This physical idea of
deliverablity, however, is not the test applied under the FERC
Network Resource Standard.
To illustrate, we offer a simplified example. The diagram*
below represents a system composed of a single transmission
line connected to a 100 MW load. At the other end of the line,
interconnected to the line in an electrically indistinguishable
fashion, are two 100 MW generators.
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* Graphic has been retained in subcommittee files.
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The load has the option of choosing either of the generators
to serve it. Whichever one it chooses, the system is capable of
delivering the output (both capacity and energy) of the
generator to the load. While it is true that, both generators
cannot run simultaneously (for one thing there isn't enough
load to absorb them both) it is obviously true that as a matter
of electrical engineering, either could run (or each could run
at \1/2\ output) to serve the load. It is the load which, in a
competitive market, would generally get to decide what
combination of generation serves it. Under the
``deliverability'' standard of FERCs Interconnection Policy,
however, that is not the test (at least with regard to
capacity). Rather, the test for deliverability will produce the
anomalous result that, even though both generators are
absolutely equivalent from an electrical point of view, one of
them could be considered ``deliverable'' and one of them might
not be. The choice will not be made based on any economic or
engineering rationale, but simply on the basis of who was there
``first''.
Under the deliverability test in FERC's Rule, a new unit must
be connected so that ``the aggregate of generation can be
delivered to the aggregate of the load''. Obviously, this is a
highly imprecise standard which, depending on the details and
assumptions in the study, can be used to discriminate in a
variety of ways. For instance, in any existing system, it is
obviously not possible to deliver all (i.e. ``the aggregate'')
of the generation simultaneously to load, since there is always
more generation than load. It is always some subset of
generation that is serving load. The usual manner of applying
the deliverability standard is to first choose the
``preferred'' subset of incumbent generation which is
dispatched to serve load. After this preference has been
established, the new entrant is treated as the ``marginal
unit'' which must somehow be worked into the mix and be capable
of running simultaneously without ``disturbing'' the preferred
units' ``right'' to run at any level they choose. Despite all
the convolutions of the study protocol, this is simply a matter
of favoring the incumbent units and treating new entrants as if
they are the ``marginal'' unit.
In our simple example, if A were the incumbent, the study
would dispatch A at 100MW, and then see if there were any room
for B (the new entrant). Since A and B can't both run, B is not
``deliverable'' and is not allowed to compete for the loads
business as a capacity resource.
deliverability to or from a constrained region
Deliverability can be used by incumbents as an excuse to
create a ``straw that broke the camel's back'' argument which
requires the last new entrant to fund major transmission
upgrades to relieve constraints which the incumbents have
neglected to remedy in the past. For instance, going back to
our simple model of two identical 100 MW generators (``A'' and
``B'') connected to a 100 MW line. Presume that on the end of
the line there is 200 MW of load, but there is still only 100
MW of transfer capability. It is true that if Generator B comes
on line, it is not possible to deliver any additional MW to the
load at the other end without an upgrade. However, there can
still be significant benefits (to at least 100 MW of the 200 MW
load) if B is offering a substantially lower capacity or energy
price. However, in order to protect incumbents, the
deliverability test will be structured such that B will not be
considered deliverable because there are already 100 MW of
``network resource'' (i.e. unit A) on line and 100 MW is all
that can be delivered over the line. Thus, unit B will face a
major interface expansion in order to be deliverable to the 200
MW load even though he could underbid the incumbent and deliver
both capacity and energy at a lower cost by displacing him.
The argument usually advanced for this type of discrimination
is that ``it is sending the wrong signal to the Generator'' to
allow it to locate in a place where it does not increase the
total capacity available to load. This, of course, ignores the
fact that Generator A will be insulated from competition if the
incumbent utility doesn't want to build enough transmission to
serve load in the constrained pocket. We would argue that the
correct ``signal'' to the Generator is to allow it to compete
for the 100 MW of transmission capacity. If it is unsuccessful
in competing to displace the incumbent unit, it has made a bad
business decision, but that is its own risk. Further, if a new
unit truly wishes to provide additional service it can always
request and pay for an upgrade. If a new entrant succeeds in
displacing the incumbent and the incumbent still wishes to
deliver power, it is free to expand its system to do so. It
should not be the responsibility of a new entrant offering a
lower price or a cleaner resource to correct the failures of
transmission system planning of the incumbent utility before it
is allowed to compete for load in the capacity market.
For all of these reasons, competitive principles require
variations to the FERC's dual Interconnection Standard in any
region where competition is the prevailing model. The Minimum
Interconnection Standard once approved in New England and New
York can serve as the basis for a non-discriminatory, pro-
competitive approach which will lower barriers to entry and
increase competition. Interconnection under that standard
should permit a new unit to compete as both a capacity and
energy resource. Further, even where competition is not the
norm, the purpose and goals of any Renewable Portfolio Standard
will be frustrated if interconnection policy is not revised to
allow new cleaner units to displace older, fossil fired units
on the transmission system.
Question 4. We will be addressing climate change legislation again
this year and we need cost effective ideas to help us significantly
reduce greenhouse gas emissions. I can see that CHP technology offers a
tremendous opportunity to help the environment and help our
manufacturing industries increase competitiveness and jobs. How could
CHP facilities receive recognition for their efficiency and how would
you do so under cap and trade?
Answer. Although producing power via CHP uses energy more
efficiently than producing utility power, direct (onsite) emissions of
a facility using CHP will typically be higher than if the facility only
produced thermal energy and purchased all electricity from off-site.
Since the benefit of a CHP system is reducing indirect emissions (i.e.,
from purchased electricity), a cap-and-trade program where compliance
is measured solely on reducing direct emissions will not adequately
account for the benefits of CHP. It is critical that the efficiency
gains associated with CHP systems be properly recognized in a cap-and-
trade system.
Climate change policies should recognize the benefits of, and
promote investment in, CHP by providing credit for the avoided
emissions associated with a CHP unit. The credit should be equal to the
difference in CO2 emissions generated by a CHP system as
compared to the equivalent CO2 emissions associated with
generation of electricity by utility companies and the separate on-site
generation of thermal energy.
Given the range of configurations of CHP systems and fuel
combinations used, each facility would calculate the emissions savings
provided by their CHP system according to an established standardized
methodology. Each facility may then deduct those CO2
emissions savings associated with that CHP unit from regulated
emissions under a GHG regulatory program. After subtracting CHP savings
credits from the facility's regulated (direct) emissions, any surplus
credits generated by a facility shall be eligible for an emissions
reduction credit in any carbon market created by the system.
To illustrate the impact of CHP on GHG emissions and energy
consumption of a hypothetical 1000 air dry ton (adt) per day integrated
Kraft pulp mill, it was assumed that the mill consumes 7,000,000 GJ of
steam and 400,000 megawatt-hours (MWh) of electricity per year. It was
further assumed that the boiler-based CHP system was designed to
satisfy the mill's steam demand, with CHP-generated power offsetting
about half of the needed electricity with the rest purchased from the
grid.
TABLE 1.--ANNUAL GHG EMISSIONS AND TOTAL ENERGY (SAMPLE P&P MILL) WITH
AND WITHOUT CHP
------------------------------------------------------------------------
With CHP Difference
(Wood/Oil Without (impact of
Boiler) CHP CHP)
------------------------------------------------------------------------
Direct emissions (onsite, tonne 363,000 328,000 +35,000
CO2 eq.)
Indirect emissions (offsite, 147,000 270,000 -123,000
tonne CO2 eq.)
Total emissions (sum onsite plus 510,000 598,000 -88,000
offsite, tonne CO2 eq.)
Total fuel energy (sum onsite 12,800 13,500 -772
plus offsite, TJ HHV)
------------------------------------------------------------------------
From the information presented in Table 1 it is obvious that,
although direct GHG emissions increase upon employing CHP, total
emissions decrease to a greater extent. Total fuel consumption (onsite
plus offsite) also decreases. The total emissions savings from use of
this CHP system amount to 88,000 metric tonnes CO2 eq. per
year. The method proposed to eliminate CHP disincentives in GHG cap and
trade programs would be to allow the facility operating the CHP system
to deduct this amount from its direct emissions (compliance
obligation).
AF&PA has developed the following potential legislative language
based on H.R. 2454 ``The American Clean Energy and Security Act'' which
would encourage the use of Combined Heat and Power Systems to Reduce
GHGs.
``(5) INDUSTRIAL STATIONARY SOURCES.--For a covered entity
described in section 700(12)(E), (F), or (G), 1 emission
allowance for each ton of carbon dioxide equivalent of
greenhouse gas that such covered entity emitted in the previous
calendar year, excluding emissions resulting from the use of--
``(A) petroleum-based or coal-based liquid or gaseous fuel;
``(B) natural gas liquid;
``(C) renewable biomass;
``(D) petroleum coke; or
``(E) hydrofluorocarbons, perfluorocarbons, sulfur
hexafluoride, nitrogen trifluoride, or any other fluorinated
gas that is a greenhouse gas purchased for use at that covered
entity.
(F )combined heat and power systems in accordance with section (F)1
1) EMISSIONS SAVINGS DEDUCTION FOR COMBINED HEAT AND POWER (CHP)
SYSTEMS--combined heat and power greenhouse gas emissions savings shall
be calculated for each CHP system according to an established
standardized methodology which takes into account an individual CHP
system's configuration and fuel use. Each CHP system will deduct from
their total direct emissions compliance obligation the greenhouse gas
emissions savings calculated as the difference in CO2
emissions generated by a CHP system compared to the equivalent
CO2 emissions associated with generation of electricity by a
utility and the separate on-site generation of thermal energy. Any
surplus credits generated by a facility shall be eligible for an
emissions reduction credit.
Question 5. In your testimony, you say that ``exit fees'' are a
barrier for manufacturing to build CHP facilities. Would you explain
what exit fees are and why they are a barrier?
Answer. An exit fee is a charge that can be assessed to a
manufacturer that chooses more energy efficient options for their steam
and power supply that would reduce electricity demand. The local
utility may charge the customer the non-fuel component of the utility
power cost for some specified period of time. Exit fees are a barrier
because the cost of this charge or simply the threat of such a charge
adds massive costs to a potential buyer of the project's electric
output. The higher costs affect the viability of the project even
before it gets off the drawing board. The net effect of exit fees is
the reduction in the potential pool of buyers for the project's power
output.
Question 6. In Michigan we have lots of industries that would be
ideal places to utilize Combined Heat and Power. Refining, and the
production of metals, glass, ethanol, chemicals, cement, pulp and
paper, and food processing could all ideally operate at lower cost and
reduced emissions with effective CHP systems. As one example, Guardian
Industries is a Michigan-based company that produces flat glass in
large furnaces that use 1.5 billion cubic feet of natural gas annually
in each of their 8 production lines around the country. Since the
furnaces operate at 2,900 degrees Fahrenheit, a lot of heat has
typically gone up the stack. I know that Guardian recently rebuilt a
furnace at a plant of theirs and are in the process of installing
equipment to use that lost heat for generating electricity. This should
reduce the plant's electricity demand from the utility by a little over
10%. Most CHP incentives support using waste heat after that heat is
first used to generate electricity. Would S.989 [introduced by Sen.
Menendez on May 6] support harnessing waste heat that is first used for
a different purpose, such as melting sand in glass production?
Answer. S. 989 clearly encompasses the harnessing of waste heat
that is first used for industrial purposes, such as melting sand in
glass production. Although the bill provides for net metering of such
generating facilities, the bill contains no significant incentives to
promote projects using waste heat. These projects require financial
incentives such as investment tax credits and grants due to the high
capital cost. Although the size limitation of 10 MW may not be an issue
for the glass production industry, it is a major concern to other
manufacturers, such as those in the business of calcined petroleum coke
production or steel production, that have huge potential to utilize
their waste heat. Most of the opportunity in manufacturing to use waste
heat and CHP would be in facilities greater than 10 MW so this bill
does not address their concerns at all. In addition, S. 989 also
provides for the removal of existing barriers to the installation of
CHP systems potentially for use in industrial parks but unfortunately
the 10 MW limitation will remain a deterrent to many such facilities
being built because the limit on size is too low.
The bill states that backup and standby rates should be based on
``actual cost''. This generic term may become subject to varied
interpretations by the states as what are costs should be included in
backup and standby rates. Some PUCs may decide to include utility lost
revenue in ``actual costs'' for standby service. Due to the lack of
specificity, this language is not really an improvement over the
original language included in the PURPA law of 1978 that required
standby rates to be designed to a ``just and reasonable'' standard.
Implementation of the original PURPA language over the past 20--30
years has shown that what is just and reasonable to one party may be
onerous to another. PUCs have been generally receptive to utility
arguments that it is just and reasonable for standby rates to reflect
full retail contract demand costs.
The vague language in S. 989 will enable utilities to argue that
they incur the full retail rate as the ``actual cost'' and the barriers
to increased use of CHP will not be reduced, as intended. Therefore
additional guidance should be provided in the bill so that standby
rates are designed based on quantifiable metrics reflective of the
benefits of CHP. Consideration should be given to the fact that standby
service is needed when a customer's power plant sustains a process
disruption or forced outage which is unlikely to occur coincident with
the utility's peak periods. Such an approach would support the case
that CHP should have lower, not higher standby and backup rates. One
way to achieve this in S. 989 would be to specify the percentages of
utility generation and transmission revenue requirements which should
be attributable to and used for the design of backup and standby rates.
More progressive states have found that just and reasonable standby and
backup rates can be developed by assigning 15 to 20% of the per unit
costs of providing generation and transmission service. The proposal
for the design of standby rtes in S. 989 can be improved by
substituting these percentages as a proxy for the term ``actual
costs''.
Responses of Irene Kowalczyk to Questions From Senator Risch
Question 7. I was surprised that your testimony made no mention of
the Industrial Energy Efficiency provisions enacted by Congress in the
2007 Energy Independence and Security Act. In that Act, we created a
recoverable waste inventory program within EPA, along with a grants
program, and directed the states to consider standards for sales of
excess power. How have these provisions assisted the Combined Heat and
Power (CHP) industry?
Answer. EPA has not yet issued the proposed rule which will provide
criteria for facilities to be included in the inventory, so we have no
experience with its actual implementation.
Fellow IECA members have pointed out a concern with the wording of
the provisions which will limit its ability to enhance the use of CHP
and waste heat recovery systems. EISA 2007 says that a waste heat
capture project will not be listed if the project was developed for the
primary purpose of making sales of excess electric power. This limits
applicability for those manufacturers with waste heat stacks on
existing plants who are stranded from a steam host as they have no
support for energy capture. A mandated purchase is the most important
aspect of any stranded waste heat project as electric power export is
the only practical outlet for the energy.
Many manufacturers seek developers to install energy efficiency
projects on their premises and the manufacturer purchases energy
commodities from the project through supply contracts. In regulated
states the developer cannot sell power to the retail customer so the
only outlet is to sell power to the utility. Therefore the language in
the bill limits developers from entering this business entirely in
regulated states. As a result the well intended provisions of the bill
will do little to reverse the nation's trend toward continued energy
inefficiency where wasted heat is concerned.
Question 8. You have identified a number of barriers to the CHP
industry. Has your industry filed any complaints with FERC? If not, why
not? If so, what were the results of your efforts?
Answer. The paper industry has been extremely active at FERC in
arguing for better interconnection standards. The original case in New
England, Bucksport,\1\was filed by a Cogen project which was being
denied entrance to the grid because of the deliverability standard then
incorporated in New England's interconnection standard. The paper mill
at issue, the then Champion Mill in Bucksport, Maine, successfully
litigated at FERC and won an improved interconnection standard known as
the Minimum Interconnection Standard. That Standard spurred a huge
growth in interconnected resources in New England.
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\1\ Champion International Corporation and Bucksport Energy, L.L.C.
v. ISO-New England, Inc., New England Power Pool, and Central Maine
Power Company, 85 FERC 61,142 (1998).
---------------------------------------------------------------------------
The Minimum Interconnection Standard which we advocate, was used
successfully for several years in both New England and New York, but
came under increasing pressure from system planners, large utilities,
and incumbent generator interests who recognized it as a threat to
their incumbent status. The Minimum Interconnection Standard allows new
entrants to 1) come on to the transmission system in a fashion which
preserves the reliability, stability and existing transfer capability
of the system and thereafter 2) to compete on the basis of price with
all other units to serve load. This is the proper model for a
competitive market which assumes that more efficient competitors will
``displace'' less efficient competitors from the transmission system.
An industrial trade group in New England (which included paper
companies) intervened and filed extensive comments in FERC's
Interconnection Rulemaking, attempting to preserve the Minimum
interconnection Standard in New England and make it the law of the
land. However, because of the entrenched interests of utilities and
incumbent generators, and the preferences of system operators who find
truly competitive markets difficult to manage on a central planning
basis, the Minimum Interconnection Standard in New England and
elsewhere was eroded by continuing pressure to re-establish
deliverability rules. The current standard, even in New England, erases
many of the competitive gains achieved under previous litigation.
Finally, in the context of FERC's recent ANOPR on Competition in
Organized Markets, AF&PA filed extensive comments on the deliverability
issue, explaining the damage done to competition generally by the rule.
Prior to filing these comments, AF&PA held several informal meetings
with FERC Staff and representatives of PJM, explaining our concerns and
discussing the details of the issue with PJM system planners. The FERC
did not act upon AF&PA recommendation to eliminate deliverability in
its final Rule.
While over-building the transmission system in this way makes it
very easy for system operators to plan, it makes no more sense than
forcing every new trucking company who wants to compete with existing
firms to build separate lanes on the interstate before they are allowed
to offer freight service at a lower cost. In addition, there are new
imperatives now that make a transition back to a more competitive
interconnection process even more vital. There is a recognized need to
displace existing, less-environmentally friendly units with new CHP and
renewable technologies that will lower emissions. Putting competitive
and financial barriers in front of these new projects that are intended
to displace existing, less-environmentally friendly units, does not
make sense. We do not need to expand the system to allow all the old
dirty units to continue to run when competitors with cleaner, newer and
more efficient units are coming on line to displace them.
Question 9. You testified that one barrier to CHP seeking to
interconnect is that you may have to pay to finance transmission
facility upgrades. Why should your industry be exempt from such
payments? Aren't you benefitting by being able to put your power on an
electric transmission line?
Answer. It is not a question of whether or not a CHP facility
seeking to interconnect should have to finance facilities needed to
interconnect, but rather how much transmission is needed to do this. A
CHP facility should not be required to finance more facilities than are
needed to connect the CHP facility in a manner which preserves the
reliability, transfer capability and stability of the grid. Current
FERC policy often mandates that CHP facilities do more than this before
they are allowed to compete in capacity markets. Current FERC rules
require that they finance facility upgrades sufficient to keep
incumbent generators free from competition for use of the transmission
system.
If Congress intends to encourage the use of CHP as an alternative
to less-efficient or more environmentally harmful fossil fuel
facilities, it will be wasteful for CHP facilities to have to fund
transmission upgrades so that, existing, less environmentally friendly
facilities, can continue to run at their accustomed output even after
new CHP units come on to displace them. If FERC persists in this
policy, then CHP will not be a viable replacement for existing less-
environmentally friendly units because of the added unnecessary
transmission costs. Secondly, CHP units that are built to displace
fossil fired units will have built wasteful duplicative transmission
facilities that are not needed once that displacement occurs.
Clearly, if CHP begins to serve a large segment of load currently
served by existing units (which is the intent of Congress), and then
existing less-environmentally friendly resources can, and hopefully
will be retired. This means that they will not need to have
transmission available to serve them because the load will be taking
service from renewable or distributed resources instead. Regardless of
how much generation is built, the country only needs enough
transmission to serve the load that is on the system. Congress is
trying to encourage CHP and other renewable technologies to displace
existing less-environmentally friendly units in order to reduce carbon
emissions. No one benefits by building more transmission than necessary
to serve load in order to preserve the ``deliverability'' of old fossil
fired units we hopefully will no longer need. The correct result is to
allow CHP to ``displace'' older, less-environmentally friendly units on
the transmission system, not to duplicate or expand transmission
facilities beyond the needs of the load to be served.
Therefore, CHP and other renewable or distributed units should be
required to build only the transmission capacity which is necessary to
connect them reliably in a fashion which preserves the existing
transfer capability and stability of the system. They should not be
required, as under current deliverability standards, to build more
transmission than is necessary to accomplish this purpose.
Question 10. You advocate for Congress to require states to offer
long term contracts for the purchase of CHP power. Isn't this matter
more appropriately argued at the state level, where there is
responsibility for retail sales?
Answer. It is up to Congress to set national energy policy. The
strength of the state review system is in keeping costs down, and so
states should definitely have a role in determining which renewable
contracts should be signed and with whom. But absent Congressional
direction, the political process will make it extremely difficult for
states to abandon existing less environmentally preferable coal fired
and other units in favor of available renewable and distributed
technologies. The easy answer for states, politically, is usually to
stand pat. In the past that may have been an acceptable strategy. But
climate change and the national security implications of our dependence
upon foreign oil have combined to render reliance upon state discretion
a less effective means to achieve national objectives. Congress needs
to set policy that requires the financial underpinning necessary to
achieve a significant penetration of renewable and distributed
generation into state portfolios is available.
Question 11. You identify securing environmental permitting for CHP
as a barrier to entry. How can you possibly advocate for such a broad
exemption, particularly when CHP is often located in rural areas?
Answer. The written testimony speaks of expedited or streamlined
permitting procedures, but not necessarily exemptions to environmental
permitting. Facilities engaged in CHP understand that regulatory
structures must be in place to ensure that ambient air quality
standards are protected and that appropriate emissions controls are
installed and operated.
CHP projects typically result in improved efficiency, which can
result in additional electrical production for the same amount of fuel
input or else result in reductions in fuel consumption. Both of these
types of changes result in lower emissions. However, due to current
regulatory structures many of these changes trigger NSR permitting
which is generally a very cumbersome process. It should be noted that
certain reforms have taken place that have eased this situation a bit,
such as the allowance of ``actual-to projected actual'' emissions
accounting, but additional measures could be taken. It can take from 6
months to 24 months to obtain permits for construction and process
modifications. This serves as a deterrent to moving these projects
forward to market. The current permitting structure can also require
Best Available Control Technology (BACT) for existing equipment. While
BACT has the potential to reduce emissions, it also adds significant
costs to projects, which often times cancels implementation of the
project. One change that would help these projects succeed would be to
allow them to continue to use their existing control equipment as
opposed to having to upgrade to the very latest technology as required
by BACT. A streamlined approach could offer a solution that allows more
marginal environmental benefits for these projects, while realizing the
benefits that CHP can offer for better energy efficiency.
______
Response of Kevin A. Kelly to Question From Senator Stabenow
Question 1. I understand the generation of heat and power accounts
for more than two-thirds of U.S. fossil CO2 emissions. I
also understand the efficiency of generating electricity has not
improved from its dismal 33 percent level since the time of President
Eisenhower. Can you describe some of the policy barriers to more
efficient power generation, specifically distributed generation?
Answer. I agree that if policy barriers to distributed generation
were removed, the increased use of distributed generation could
contribute to more efficient power generation. Some studies indicate
that using distributed generation to provide both electricity and heat
(for space or water heating, process heating, or even cooling) can
increase total system efficiency from 33-50 percent in a typical modern
central station generating plant to as high as 80 percent in a
distributed generation combined heat and power system.
Many policy barriers to increased use of distributed generation,
however, are found at the state and local levels. For example,
manufacturers and prospective users of distributed generation equipment
have expressed concern about the lack of reasonable, standardized
interconnection requirements. Most interconnections of distributed
generators are jurisdictional to states or local retail regulators, not
the Commission. Therefore, the above-noted concerns remain despite the
Commission's issuance of regulations that standardize interconnection
procedures for small generators whose interconnection is subject to the
Commission's jurisdiction. The Commission has encouraged state and
local regulators to use the Commission's regulations as a common
guideline for their own regulations.
In addition, in some cases, distributed generators have been
charged exit fees by utilities to protect their other customers from
the costs of past utility investments intended for the customer that
later develops his own generating capability. Further, local barriers
to distributed generation include such policies as local siting and
permitting requirements and building electric codes for onsite
generation such as rooftop solar.
More broadly, prospective users of distributed generation equipment
have expressed concern that policies that make it difficult for
distributed generation to be compensated commensurate with its full
value constitute significant barriers to its increased use. For
example, many states require (to the extent of the state's authority)
that when distributed generation produces more electricity than is
needed by its host user, the excess output can be purchased only by the
local distribution utility. In such situations, the user of distributed
generation may have little ability to negotiate a sale price with the
local distribution utility or to sell the output to a neighboring
utility customer at the retail rate and, therefore, will usually
receive compensation at or near a wholesale average rate that fails to
reflect all value associated with the distributed generation (e.g.,
producing electricity close to load, avoiding transmission and
distribution losses and investment, and providing other reliability or
environmental benefits to utility systems). Thus, typical compensation
from the distribution utility may make investment in distributed
generation less attractive than it might be.
Responses of Kevin A. Kelly to Questions From Senator Risch
Question 2. With regard to net metering, what are potential impacts
on the transmission and distribution system?
Answer. Net metering can have significant positive impacts on the
transmission and distribution system. For example, distributed
generation dispersed within the distribution system can provide voltage
support for the system and lessen the amount of additional distribution
and transmission investment that will need to be made, thus reducing
costs for all consumers on the system. In addition, targeted
distributed generation can relieve local transmission congestion and
thereby lower electric market prices to consumers.
Widespread deployment of net metering may also call for other
system upgrades. For example, distribution lines may require
modifications to accommodate power flowing in the opposite direction
from that for which the lines were designed.
Question 3. FERC currently has limited authority with regard to net
metering and distributed generation interconnection standards--it only
applies to facilities that are already subject to the Commission's
jurisdiction (wholesale facilities). Is FERC advocating the expansion
of its current authority under the Federal Power Act with regard to
these standards?
Answer. No.
______
Responses of Christopher Cook to Questions From Senator Risch
Question 1. In your testimony, you state that meters installed in
the 1950s and 1960s by utilities would net meter, simply spinning in
reverse when a generator on the customer's side was producing more
power than the customer was using. How can we simplify and streamline
the existing framework for net metering?
Answer. Any funding for utilities to replace meters with smart
meters or any meter upgrade should include a requirement that the new
meters provide net metering. Some new electronic meters are designed in
such a way that they do not spin in reverse while others are designed
to provide for net metering and reverse spin and registration.
Utilities should only install meters that will spin in reverse and
provide net metering so as to avoid the added cost of replacing a meter
when a customer adds a wind or solar system to power their home or
business.
There should be a minimal national standard for net metering that
embodies the fundamental premise that if a customer generates a
kilowatt-hour of energy from their own renewable energy system, they
receive a full kilowatt-hour credit for that generation to be used
against future consumption. There should be no set-offs or reduction in
value through fees or charges imposed on customer-generators. Federal
guidelines on the allowable size of systems would help streamline and
create a national seamless standard for net metering.
Question 2. You note that one of the most prominent questions about
net metering is whether power producers that are benefitting from net
metering are paying their fair share of costs. Why shouldn't a net
metered customer be responsible for the administrative costs associated
with net metering?
Answer. Net metering should be implemented in the simplest and
least cost manner. If undertaken with this direction, administrative
costs should be minimal to non-existent. Where utilities have in place
meters that can net meter (meaning the utility has not replaced the old
fashioned meters with a version that no longer net meters) the meter
does all of the administrative work spinning forwards when the
customer's generator is less than their load; spinning in reverse when
the generator is greater than the load and at all times showing the
``net'' amount of consumption. When the utility meter reader reads the
meter monthly (or other billing period) the meter shows the net of
production against consumption and the customer is billed like any
other utility customer. In this case there are no administrative costs.
Where the meter shows an excess, the utility can just issue a zero bill
for that month and subsequent months until excess credits are used up.
There is no need to track the excess as again the meter keeps an
accounting. There may be minimal administrative costs for reconciling
annual excess energy under the rules where a customer is paid annually
for excess at avoided cost. The simpler and less costly option is to
either eliminate excess credits at the end of the year or allow for
continued carry forward. In the former case there is some
administrative cost but the utility is getting free kilowatt-hours that
help to defray that cost. In the latter case, there should be minimal
to no administrative costs as billing continues like it would for any
other customer.
Where administrative costs tend to be greater than an insignificant
amount are in the cases where a utility has undertaken a meter
replacement and the new meters no longer provide the net metering
function. In those cases the burden of meter replacement cost or using
a dual meter arrangement (which requires monthly accounting) rightly
falls on the utility since one may question the judgment of a meter
replacement that eliminated the simple net metering function.
Question 3. You noted in your testimony that if a customer/
generator could use storage, they could store peak energy for off-peak
usage. What kind of storage are you referring to? What kind of storage
for solar energy is commercially available today?
Answer. Batteries; compressed air and thermal storage\1\ are the
most common forms of storage available today. Flywheels and
electrolysis hydrogen production/ fuel cells have future potential as
storage devices. In most cases and under system operator rules for the
grid, the additional cost of storage is not economical.
---------------------------------------------------------------------------
\1\ electrical energy is used to make heat or ice and stored for
later heating or cooling of a building.
---------------------------------------------------------------------------
Moreover, using solar power that is typically produced during grid
peak times and putting it into storage is not good for the electric
grid, as the grid can best utilize this valuable energy. It is better
to have the solar customer-generator put excess peak power into the
grid (and not into storage), receive a credit for the power put into
the grid and then have that customer use off peak power when the sun is
no longer shining. This is more economical and better for the electric
grid than taking that excess peak solar energy and putting it into
batteries and then drawing from the batteries when the sun is not
shining.
An example: Grid peak capacity = 1000MW. Total capacity of solar
generators = 50MW.
On a peak load day during the daytime when load reaches 1000MW, the
grid teeters on the brink of a blackout. If the 50MW of solar
generation is put onto the grid through net metering, the total load is
reduced to 950MW reducing the critical level of the peak load.
Conversely, if there is no net metering and customers are putting their
excess power into batteries, the 50MW is not available to the grid
(that generation is all going to storage) and the grid continues to
struggle with a peak load that has reached the capacity of the grid
generators.
______
[Responses to the following questions were not received at
the time the hearing went to press:]
Question for David Weiss From Senator Stabenow
Question 1. FERC has fairly narrow jurisdiction over the
regulations that affect distributed energy. Could you talk a bit more
about the federal options beyond regulation? The challenges we're
hearing about today will require lots of creativity to overcome. In
particular, what authorities does the Department of Energy have to
encourage the deployment of distributed generation-both small-scale
wind and solar as well as industrial-scale Combined Heat and Power? Can
these authorities be made more effective?
Questions for David Weiss From Senator Risch
Question 2. In your testimony, you advocate for rate decoupling.
Can you explain further how you think this would strengthen and improve
the use of distributed generation?
Question 3. As you stated in your testimony, subsidiaries of Pepco
serve customers in Delaware, the District of Columbia, Maryland and Jew
Jersey. Please describe some of the pros and cons of different
frameworks from state to state, as well as why you believe there should
be a federal model, as opposed to a national standard, that allows for
flexibility across state lines and also allows local stakeholders the
opportunities to shape their own policies.
Question 4. Feed-in tariffs are an incentive structure whereby
utilities are obligated to buy electricity (typically renewable) at
above-market rates set by the government, encouraging rapid consumer
growth. What is your position on feed-in tariffs?
Appendix II
Additional Material Submitted for the Record
----------
Statement of the American Forest & Paper Association (AF&PA)
introduction
The American Forest & Paper Association (AF&PA) appreciates this
opportunity to present its views for the hearing on purpose of the
hearing ``net metering, interconnection standards, and other policies
that promote the deployment of distributed generation to improve grid
reliability, increase clean energy deployment, enable consumer choice,
and diversify our nation's energy supply.'' AF&PA is the national trade
association of the forest products industry, representing pulp, paper,
packaging and wood products manufacturers, and forest landowners. Our
companies make products essential for everyday life from renewable and
recyclable resources that sustain the environment. The forest products
industry accounts for approximately 6 percent of the total U.S.
manufacturing GDP, putting it on par with the automotive and plastics
industries. Industry companies produce $200 billion in products
annually and employ approximately 1 million people earning $54 billion
in annual payroll. The industry is among the top 10 manufacturing
sector employers in 48 states.
af&pa members' energy profile and greenhouse gas reductions\1\
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\1\ AF&PA member performance metrics are from 2008 AF&PA
Environmental, Health & Safety (EHS) Verification Program Biennial
Report, 2008 (http://www.afandpa.org/Content/NavigationMenu/
Environment_and_Recycling/Environment,_Health_and_Safety/AF&P
A_EHSReport08_final5web.pdf. Industry statistics on cogeneration are
from: 2007 energy cogeneration data from the Energy Information Agency
(http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html.)
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Overall Efficiency
AF&PA members have steadily increased their energy efficiency,
while also increasing reliance on carbon-neutral renewable biomass
power, and reducing fossil fuel use. Overall, total energy use per ton
of production at member pulp and paper mills has decreased by 26.6
percent since 1972, and by 11 percent between 1990 and 2006.
Combined Heat and Power
One of the ways in which members have increased their efficiency is
through the use of combined heat and power (CHP), which is the practice
of using exhaust steam from electrical generators for heat in
manufacturing processes or for space heating. Based on U.S. Department
of Energy (DOE) data from 2007, the forest products industry is a
leader in the use of CHP-generated energy--99 percent of the pulp and
paper mills that generate electricity employ cogeneration technology.
The forest products industry represents one third of the industrial
CHP-generated energy in the U.S.
Renewable Biomass Energy
The forest products industry also is the leading producer and user
of renewable biomass energy in the U.S. In fact, the energy we produce
from biomass exceeds the total energy produced from solar, wind, and
geothermal sources combined. Sixty-five percent of the energy used at
AF&PA member paper and wood products facilities is generated from
carbon-neutral renewable biomass.
Fossil Fuel and Purchased Energy
Our increasing efficiency and greater reliance on biomass energy
has enabled AF&PA members to significantly reduce the use of fossil
fuel and purchased energy, much of which also is generated from fossil
fuel. From 1972 to 2006, the fossil fuel component of the AF&PA member
mill energy mix decreased by over 55 percent, and the use of both
fossil fuel and purchased energy has decreased by 56 percent.
Greenhouse Gas (GHG) Reductions
Our commitments to energy efficiency, CHP, renewable biomass
energy, and other actions have enabled AF&PA members to achieve
significant reductions in GHG emissions. Since 2001, working together
AF&PA members voluntarily reduced their carbon dioxide (CO2)
emissions intensity by 13 percent. From 2000 to 2006, our members
collectively reduced their direct greenhouse gas emissions 34 percent.
Approximately half of this reduction can be attributed to improvements
in greenhouse gas emissions, such as efficiency improvements or reduced
fossil fuel use, and half can be attributed to decreases in production
and changes in the baseline from the year 2000.
The Benefits of CHP
CHP is the sequential or simultaneous generation of electricity and
thermal energy (in the form of steam) from the same fuel for use at a
host facility that makes both electricity and another useful product or
service requiring heat. CHP is more efficient because it generates both
thermal energy and electricity concurrently rather than generating
thermal energy onsite and electricity at utility generators remotely.
By producing electricity and process heat, relatively little heat value
of fuel is wasted to the environment compared to conventional utility
generating processes; this is the basis for the savings. In general,
CHP is about twice as efficient at using fuel as is utility technology.
This relative energy efficiency of CHP results in decreased emissions
of carbon dioxide to the atmosphere. CHP generation of electricity
emits only half as much GHG as non-CHP electricity. Furthermore, by
reducing electricity demand from the grid, CHP reduces the
corresponding transmission and distribution inefficiencies which are
typically 7 percent. Numerous studies have documented these benefits of
CHP and the role that increased CHP can play in helping the nation
reduce greenhouse gas emissions, thereby also helping the nation meet
its renewable energy, and energy security goals.
Barriers to Increased Use of CHP
While the industry is a leader in the use of industrial
cogeneration technology, there are numerous policy barriers to
increasing the use of that technology in our industry, in other
industries, and in other settings, as is evident from the testimony
provided for the hearing. In particular, we would like to highlight the
testimony of Irene Kowalczyk, MeadWestvaco Corporation (MWV). MWV is a
member of AF&PA and Ms. Kowalczyk's testimony presents a comprehensive
compilation of existing and potential future barriers to increased use
of CHP in the forest products industry. We would like to highlight a
few energy policy issues from her testimony that have negatively
affected numerous AF&PA members:
Interconnection Standards: Unlike merchant generators, whose
purpose is to generate and sell electricity, forest products
industry CHP facilities' primary purpose is to provide thermal
energy for its host manufacturing facility. Policies such as
interconnection standards for facilities larger than 20 MW
require CHP units to go through the same costly, lengthy and
complicated process that merchant generators do if they seek
full compensation for the power they sell to the grid. In
addition, under the rule's ``deliverability standard'' a new
CHP unit is not allowed to compete on price with the incumbent
for the use of the grid, even though the incumbent may be a
less energy efficient generator. Finally, a CHP unit at a
manufacturing site which is in a transmission constrained area
would be required to finance transmission upgrades as part of
the interconnection process before being permitted to
interconnect.
Discriminatory Treatment of Behind the Meter Generation:
``Behind the Meter'' generation refers to electricity generated
and used on site by the manufacturing facility and not sold to
a utility or an Regional Transmission Organization (RTO) or
Independent System Operator (ISO). Nonetheless, RTOs and ISOs
have repeatedly attempted to interfere with CHP in the area of
``Behind the Meter'' pricing, for example, by attempting to
charge customers who supply their own needs with ``Behind the
Meter'' generation various fees and prices for services as if
they had taken their entire power supply from the RTO/ISO--
controlled grid, rather than only the ``net'' amount actually
taken from the grid. This cost allocation scheme is known as
``Gross Load'' pricing and is a barrier to increased CHP use.
PURPA Rules: The Energy Policy Act (EPAct) of 2005,
substantially revised the Public Utility Regulatory Policy Act
(PURPA) of 1978 to allow utilities to be relieved of their
mandatory obligations to purchase electricity from Qualifying
Facilities if the utility could demonstrate that it was
operating in a competitive market. Under the Federal Energy
Regulation Commission's (FERC) final order implementing the
law, however, utilities are not required to demonstrate that
their markets were functionally competitive before being
relieved of those obligations. In effect, the utility simply
has to be a member of an established RTO or ISO to be exempt.
This rule will make it much more difficult for CHP units to
negotiate fair power purchase contracts in the future. AF&PA
challenged the final order, but in a mid-December 2008 ruling,
the D.C. Circuit Court affirmed the FERC's decision.
These are just a few of the policy barriers to increased CHP use
that forest products and other industry facilities have faced. As
Congress develops energy (including renewable energy) and climate
change legislation, it should seek opportunities to provide incentives
and promote the use of CHP. Thank you for your consideration of this
Statement.
______
Statement of Suzanne Watson, J.D., LL.M., Policy Director, American
Council for an Energy-Efficient Economy (ACEEE)
introduction
ACEEE is pleased that the subcommittee is exploring interconnection
and other policies that promote clean distributed generation. One form
of distributed generation, called combined heat and power (CHP), offers
the promise of significant increases in energy efficiency and
reductions in harmful emissions in a number of applications and
sectors. Waste heat recovery, which can take the form of CHP, offers
similar benefits and is affected by many of the same policies and
regulations as CHP. A variety of policy and regulatory issues affect
the deployment of CHP and waste heat recovery systems (hereafter
referred to simply as ``CHP''), including interconnection standards,
output-based emissions standards, standby electric rates, natural gas
rates and financial incentives.
ACEEE regularly assesses a number of these policies for each U.S.
state, and ranks states according to their CHP policies in the annual
ACEEE State Energy Efficiency Scorecard. Below is a brief discussion of
the policy and technical issues associated with CHP, what constitutes
``good'' policies in some of these categories, and a ranking of states
based upon their CHP policies. What is important to note is that these
policies vary dramatically among states, leaving CHP project developers
with a heterogeneous policy and regulatory landscape in which to work.
Each state has different rules, processes, forms, timelines and fees
associated with a number of these policies, which serve to add to the
overall administrative cost of a project being done in an unfamiliar
area. Some states have very user-friendly policies, while others have
policies actively hostile toward significant CHP deployment.
Streamlining some of these policies to provide a more homogeneous
policy and regulatory landscape for projects would serve to reduce
administrative cost, provide greater degrees of certainty to project
developers, and encourage CHP in areas that have policies and
regulations that discourage CHP.
what is combined heat and power?
CHP systems generate electricity and useful thermal energy
concurrently in a single, integrated system. CHP is not a single
technology, but an approach to applying new and existing technologies.
It is a form of distributed generation, generally located at or close
to the point of consumption, unlike traditional centralized generation.
So rather than purchase electricity from the grid and then burn fuel
onsite in a boiler, the owner of a CHP system can get both electricity
and thermal energy from one energy-efficient system.
The average centralized electric power generation plant is 35% fuel
efficient, losing most of its useful energy as waste heat at the point
of generation. A CHP system captures this heat and repurposes it to
meet onsite thermal requirements for heating (or cooling, using
additional cooling technologies). And while an additional 3-10% of
typical centrally generated electricity is lost in the course of being
transmitted and distributed to end-users, CHP boasts very few
transmission and distribution losses, as the energy is generated very
close to the point of consumption--often in the same building. All
together, CHP systems are typically about 60-80% fuel efficient.
CHP systems can be powered by a variety of fossil and renewable-
based fuels, and are found in a variety of places, including industrial
facilities, large institutional campuses, hospitals, multi-family
housing complexes and commercial buildings. CHP currently represents
about 8.6% of all U.S. electricity generation capacity. DOE estimates
that figure could rise to 20% by 2030 if a suite of ``pro-CHP''
policies was implemented.\1\
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\1\ http://www1.eere.energy.gov/industry/distributedenergy/pdfs/
chp_report_12-08.pdf
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benefits of combined heat and power
Since less fuel is required to produce the same amount of useful
energy, and little energy is lost as it moves to its point of
consumption, CHP systems provide environmental and economic benefits.
They also provide benefits to the electricity grid at large. In
general, CHP produces electricity at about $0.06-$0.08/kWh, while the
current retails cost of electricity from centralized generation is
nearly $0.10/kWh.\2\
---------------------------------------------------------------------------
\2\ http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_b.html
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Today's existing fleet of CHP systems provides the country with 85
GW of electricity capacity--replacing the need for about 2 Quads of
centrally-generated energy on an annual basis. This current CHP fleet
yields:
An annual reduction of 248 MMT of CO2 (about 45
million cars off the road)
Reductions of over 50% in energy costs at facilities that
use CHP
Significant reductions in costly congestion on transmission
and distribution lines
If CHP were aggressively supported by national policies, growing
its role to 20% of all U.S. generating capacity by 2030, the benefits
would be pronounced. At 20% of all electricity generation, CHP would
replace the need for about 5.3 Quads of centrally-generated energy
annually. This amount is equivalent to about half of the amount
consumed the by U.S. residential sector each year. A 20% scenario
would:
Provide an annual reduction of 848 MMT of CO2
(154 million cars off the road annually)
Create 936,000 net jobs
Stimulate the economy with an influx of CHP-related
investments of $234 billion
Avoid 60% of the expected increase in total U.S.
CO2 emissions between now and 2030\3\
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\3\ http://www1.eere.energy.gov/industry/distributedenergy/pdfs/
chp_report_12-08.pdf
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existing barriers to greater adoption of chp
Despite its cost-effectiveness and potential for significant
environmental benefits, significant hurdles remain that limit
widespread use of CHP. As a result, less-efficient separate heat and
power systems still predominate. Three areas that pose significant
challenges to the increased deployment of CHP are:
Interconnection standards
A major barrier to CHP is the lack of national business
practice standards for the interconnection of CHP to the local
electric utility grid. Interconnection is the process of
connecting a CHP system to the transmission and distribution
grid, and is necessary if the facility wishes to purchase
backup power from the grid or sell electricity back to the grid
if desired. The lack of national uniform interconnection
standards results in a patchwork of regulatory models that vary
from state to state. About half of the U.S. states have no
interconnection standards for CHP at all. CHP system
manufacturers cannot view the U.S. as a uniform market, and CHP
users cannot be assured that what works in one facility will
work in another one across state lines. A lack of uniform
standards causes uncertainty, too, since some standards have
set timeframes during which a CHP system will be allowed or
denied interconnection, while other standards do not. The local
interconnection regulations can also impact the size and design
of a CHP system. Further, some utilities require costly studies
or the installation of unnecessary (and expensive) equipment
prior to interconnection, discouraging CHP.
Standby and backup tariffs
Many utilities also currently charge discriminatory rates for
standby and backup power services that don't reflect the true
costs and benefits to utilities of having CHP systems in their
service areas. Standby service rates are charges that are
incurred by a CHP user when their CHP system goes down due to
an emergency or scheduled maintenance outage. Standby charges
are generally composed of two elements: a charge for the actual
energy used (energy charges) and a charge reflective of the
peak one-time demand of the standby power (demand charges).
Energy charges better reflect the true economics of CHP than do
demand charges, but the majority of standby rates are weighted
heavily toward demand charges. Backup power is the additional
electricity a CHP-using facility purchases to supplement its
CHP power output to meet the entire onsite load requirement.
Though backup power usage characteristics are similar to those
of a facility not using CHP, some utilities discriminate
against facilities that have CHP and use different rates to
charge for backup power than a non-CHP facility.
Private wires regulations
Many states and cities restrict the use of public right-of-
ways to utilities for the construction and operation of energy
distribution systems. This restriction has posed a barrier to
many CHP systems since a CHP-using facility is prohibited from
selling excess thermal or electric power to a neighboring
facility if that energy would need to use private wires to
cross a public right-of-way. If facilities could connect with
nearby facilities via access to these private wires, the
viability of CHP systems could be increased. Facilities with
complementary energy use patterns could share access to a
single CHP system. The economies of scale found in aggregating
the energy demand of multiple facilities would make CHP even
more economically attractive.
2008 aceee chp scorecard
In 2008 ACEEE assessed how each U.S. state was doing relative to
five CHP policy categories, including the first two listed above:
interconnection standards and standby/backup tariffs. An excerpt of
that research is presented below to give an overview of the varied
landscape CHP systems face. The overall score for each state as
determined in the 2008 scorecard is given as well. For context, that
overall score incorporates the two noted categories as well as three
others: the presence of CHP financial incentives, the ability of CHP to
qualify for a state's energy efficiency or renewable energy portfolio
standard if present, and the use of output-based air emissions
regulations.
States are rated on interconnection and standby rates according to
this scheme:
conclusion
Given the clear benefits that CHP delivers to the nation and
recognizing that the removal of certain long recognized barriers as
indicated above would facilitate an increased amount of it, the
following recommendations are suggested:
1. For systems 2 megawatts and under, allow a more
streamlined, expedited process be utilized in terms of safety
studies, application process, fees, and any other burdensome
and unnecessary business practice imposed for interconnecting;
2. Scale stand-by tariffs and back-up fees to a level that is
affordable to these smaller sized systems;
3. Set up an annual review process during which all aspects
of the interconnection process is reviewed and evaluated based
on how much additional CHP occurs. This review process should
look to make needed changes to the utility business practices
if determined still unduly burdensome; and
4. Create a net metering system for systems 2 megawatts and
under that rewards and encourages their installation.
______
Statement of Kent Jeffreys, Staff Vice President, International Council
of Shopping Centers
Thank you for this opportunity to add to the record of your May 7,
2009 Subcommittee on Energy hearing to investigate net metering and
other policies that promote the deployment of distributed generation
and improve grid reliability, increase clean energy production, expand
consumer choice and diversify our nation's energy supply.
The International Council of Shopping Centers (ICSC) is the premier
global trade association of the retail real estate industry. Founded in
1957, ICSC has more than 70,000 members in the U.S., Canada, and over
90 other countries. ICSC represents owners, developers, retailers,
lenders, and other professionals as well as academics and public
officials. ICSC has over 5,000 public sector members including mayors,
city managers, and economic development and planning professionals.
Among its many initiatives, ICSC promotes retail development in
underserved urban and rural markets. ICSC's award winning Alliance
Program encourages public-private partnerships and open dialogue on
emerging issues impacting the retail real estate industry and the
quality of life in local communities, including sustainability and
energy efficiency.
For many years, some states have required that electric utilities
offer customers the option of ``running the meter backwards'' if the
customer generates her own power. Unfortunately, in most parts of the
country, this option only has been available to residential or small
commercial customers. In most jurisdictions ``net metering'' has
significant limitations including extremely low compensation for any
excess electricity generated and strict limits on how much power, in
total, may be generated annually. Obviously, these facts stand in the
way of fully utilizing the vast roof space available for solar panel
installation at commercial property sites across America.
In response to this situation, Congress passed the Energy Policy
Act of 2005 and amended Section 111(d) of the Public Utility Regulatory
Policies Act (PURPA) to require that utilities with greater than
500,000 MWh of annual retail sales consider setting standards for
interconnection and net metering by August 8, 2008. There was no
requirement that these entities actually adopt more robust net metering
standards or alter pre-existing approaches to net metering. As a
result, only a few states have improved their net metering rules in the
intervening years--often as the result of popular demand from local
citizens. Yet in the absence of a minimum national net metering
standard, America is not producing nearly as much renewably generated
electricity as it could. And the patchwork quilt of state regulations
further hinders national real estate firms from aggressively responding
to the nation's need for distributed generation and renewable power.
Opposing arguments have included a concern over potential safety
issues such as the worry that allowing thousands of small power
generators to hook into transmission lines could run the risk of
electrocuting workmen who fail to properly disconnect the private
systems during repair or maintenance. The truth is that proper
interconnection standards easily deal with safety concerns and, where
they have been instituted, have allowed net metering to continue
without mishap. The safety issue is largely a red herring.
In addition, some utilities have argued that allowing even a
relatively small percentage of private power onto the grid could
destabilize the whole system. Yet experts assure us that even if 15 or
20 percent of baseload electric demand were supplied by wind, solar and
other renewable power from private sources it would not destabilize the
ability of the grid to respond to changing levels of demand. For
example, Germany has successfully integrated a far larger percentage of
renewable power into its national grid than the United States and
continues to expand its capacity. In addition, Congress has already
approved funding to accelerate the conversion of America's existing
transmission capacity into the ``smart grid'' of tomorrow--further
reducing the concerns of a destabilized transmission network.
A final argument against national net metering has been that local
ratepayers have funded the existing transmission grid. Therefore, it
has been argued, allowing customer-generated power onto the grid would
amount to a huge subsidy. In addition to being trumped by high-priority
national concerns (potential climate change and oil imports from
unstable regions, for example), and the fact that customer-generators
are also ratepayers, the ``subsidy'' argument can be addressed by
establishing modest and fair access rates to transmission lines.
However, these charges should be allowed only when the customer-
generated renewable power is, in fact, distributed beyond the local
area and relies upon the regional transmission system.
A strong case can be made that national energy policy should
allow--even encourage--customers to generate more ``green power'' than
they consume each month. The excess electricity should be delivered
(via the local transmission lines) to other local customers without
arbitrary and excessive fees or unnecessary technical obstacles such as
redundant or needlessly expensive interconnection standards.
When solar photovoltaic is generating the renewable power, the
electricity is usually generated during the ``peak demand'' periods of
the day. Peak demand places a strain on existing baseload capacity--
both generation and transmission. Electric utilities reflect this
higher demand (and related strain on the system) by charging more per
kilowatt for the electricity during peak periods. Therefore, rather
than creating a new problem for the electric grid, on-site solar is
providing a solution to an existing problem.
Any national net metering standard will need to address the
question of pricing levels. Currently, in most circumstances customer-
generators are able to offset kilowatts purchased from the grid on a
penny-for-penny basis--but only up to the point where they completely
``net out'' against their monthly charges. At that point, various rules
may apply in various jurisdictions. Most often, excess electricity from
the customer-generator only receives the so-called ``avoided cost'' or
``incremental cost'' for the utility company. Avoided costs are
generally around one or two cents per kilowatt-hour while normal retail
prices across the country are far higher. In other words, where avoided
costs apply the customer-generator is effectively subsidizing the
utility company whenever she produces excess electricity.
Such low levels of compensation for excess capacity act as a
disincentive for customer-generators to contribute as much renewable
power as their site can produce. Establishing a national net metering
price ``floor'' tied to local retail prices (which vary around the
country) could unleash the market for renewable power across the
country. Arguments to the contrary are similar to arguments against
universal service charges and can be dealt with through regulatory
hearings conducted by the Federal Energy Regulatory Commission. Yet
without specific guidance from Congress, net metering will only expand
slowly in the handful of states that have robust net metering laws
already on the books.
ICSC believes that stronger incentives for consumer-generated
``green'' power would enhance national security, reduce imports of
foreign oil, create local jobs, reduce the need for new long-distance
transmission lines, create more power during peak demand periods,
reduce the risk of blackouts and brownouts and cut by approximately 90
percent the amount of pollution (including greenhouse gases) for each
kilowatt of solar that replaces coal-fired power.
The time has come for a minimum national standard for net metering
sufficient to stimulate a greatly expanded capacity for on-site
renewable power generation. This committee is to be commended for
reviewing the recent progress--or lack thereof--on net metering and
associated interconnection standards.
Again, thank you for this opportunity to provide input during this
important national debate.