[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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               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

                              ----------                              

                               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

                              ----------                              


                         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\.
---------------------------------------------------------------------------
    \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

                              ----------                              


                               Appendix I

                   Responses to Additional Questions

                              ----------                              

      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.
---------------------------------------------------------------------------
    \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%.
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    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\
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
      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.
---------------------------------------------------------------------------
    * Graphic has been retained in subcommittee files.
---------------------------------------------------------------------------
          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.
---------------------------------------------------------------------------
    \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\
---------------------------------------------------------------------------
    \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.)
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
    \1\ http://www1.eere.energy.gov/industry/distributedenergy/pdfs/
chp_report_12-08.pdf
---------------------------------------------------------------------------
                  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
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \3\ http://www1.eere.energy.gov/industry/distributedenergy/pdfs/
chp_report_12-08.pdf
---------------------------------------------------------------------------
              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.

                                    
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