USCHPA Legislative Agenda

GENERAL ENERGY POLICY

• PURPA Protection

The Public Utilities Regulatory Policy Act of 1978 provides CHP facilities an access portal to monopoly utilities' infrastructure by requiring utilities to purchase power generated by certain “Qualifying Facilities” at the utilities' “avoided cost of generation”. Although the original intent of PURPA was to encourage investment in cleaner, more efficient power production, PURPA also introduces a rudimentary form of competition into the generation sector.

PURPA has faced persistent opposition on the grounds that it is anti-competitive, it raises prices for ratepayers, and was rendered obsolete by the Energy Policy Act (EPACT) of 1992, which further opened the generation sector to competition.

The USCHPA agrees that properly-functioning, competitive power markets, as envisioned by EPACT, would supplant the need for PURPA. However, market restructuring has proceeded in fits and starts, leaving major portions of the electric market inaccessible to CHP, rendering EPACT ineffective in this regard. Furthermore, barriers to market entry by CHP units such as unduly burdensome interconnection regimes and punitive stand-by rates, indicate that markets are not fully accessible by all would-be participants.

The USCHPA, in concert with a wide-ranging coalition of industrial interests, negotiated in the summer, 2003 prelude to the Energy Bill, an agreement with Republican leadership that had expressed an interest in repealing PURPA. The agreement stipulates that PURPA will not be repealed until such a time as the Federal Energy Regulatory Commission (FERC) determines that electric markets are sufficiently competitive that PURPA protection is no longer warranted.

The provision was included in the 2003 Energy Bill and is not expected to resurface as an issue during the current round of Energy Bill negotiations.

COGENERATION AND SMALL POWER PRODUCTION PURCHASE AND SALE REQUIREMENTS

(a) TERMINATION OF MANDATORY P URCHASE AND SALE REQUIREMENTS .—Section 210 of the Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 824a–3) is amended by adding at the end the following:

‘‘(m) TERMINATION OF MANDATORY PURCHASE AND SALE REQUIREMENTS .—

‘‘(1) OBLIGATION TO PURCHASE .—After the date of enactment of this subsection, no electric utility shall be required to enter into a new contract or obligation to purchase electric energy from a qualifying cogeneration facility or a qualifying small power production facility under this section if the Commission finds that the qualifying cogeneration facility or qualifying small power production facility has nondiscriminatory access to—

‘‘(A)(i) independently administered, auction-based day ahead and real time wholesale markets for the sale of electric energy; and (ii) wholesale markets for long-term sales of capacity and electric energy; or
‘‘(B)(i) transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers; and (ii) competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short - term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In determining whether a meaningful opportunity to sell exists, the Commission shall consider, among other factors, evidence of transactions within the relevant market; or
‘‘(C) wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as markets described in subparagraphs (A) and (B).

‘‘(2) REVISED PURCHASE AND SALE OBLIGATION FOR NEW FACILITIES .—

(A) After the date of enactment of this subsection, no electric utility shall be required pursuant to this section to enter into a new contract or obligation to purchase from or sell electric energy to a facility that is not an existing qualifying cogeneration facility unless the facility meets the criteria for qualifying cogeneration facilities established by the Commission pursuant to the rulemaking required by subsection (n).

‘‘(B) For the purposes of this paragraph, the term ‘existing qualifying cogeneration facility' means a facility that—

‘‘(i) was a qualifying cogeneration facility on the date of enactment of subsection (m); or
‘‘(ii) had filed with the Commission a notice of self-certification, self recertification or an application for Commission certification under 18 C.F.R. 292.207 prior to the date on which the Commission issues the final rule required by subsection (n).

‘‘(3) COMMISSION REVIEW .—Any electric utility may file an application with the Commission for relief from the mandatory purchase obligation pursuant to this subsection on a service territory-wide basis. Such application shall set forth the factual basis upon which relief is requested and describe why the conditions set forth in subparagraphs (A), (B) or (C) of paragraph (1) of this subsection have been met. After notice, including sufficient notice to potentially affected qualifying cogeneration facilities and qualifying small power production facilities, and an opportunity for comment, the Commission shall make a final determination within 90 days of such application regarding whether the conditions set forth in subparagraphs (A), (B) or (C) of paragraph (1) have been met.
‘‘(4) REINSTATEMENT OF OBLIGATION TO PURCHASE .—At any time after the Commission makes a finding under paragraph (3) relieving an electric utility of its obligation to purchase electric energy, a qualifying cogeneration facility, a qualifying small power production facility, a State agency, or any other affected person may apply to the Commission for an order reinstating the electric utility's obligation to purchase electric energy under this section. Such application shall set forth the factual basis upon which the application is based and describe why the conditions set forth in subparagraphs (A), (B) or (C) of paragraph (1) of this subsection are no longer met. After notice, including sufficient notice to potentially affected utilities, and opportunity for comment, the Commission shall issue an order within 90 days of such application reinstating the electric utility's obligation to purchase electricenergy under this section if the Commission finds that the conditions set forth in subparagraphs (A), (B) or (C) of paragraph (1) which relieved the obligation to purchase, are no longer met.
‘‘(5) OBLIGATION TO SELL .—After the date of enactment of this subsection, no electric utility shall be required to enter into a new contract or obligation to sell electric energy to a qualifying cogeneration facility or a qualifying small power production facility under this section if the Commission finds that—

‘‘(A) competing retail electric suppliers are willing and able to sell and deliver electric energy to the qualifying cogeneration facility or qualifying small power production facility; and
‘‘(B) the electric utility is not required by State law to sell electric energy in its service territory.

‘‘(6) NO EFFECT ON EXISTING RIGHTS AND REMEDIES .—Nothing in this subsection affects the rights or remedies of any party under any contract or obligation, in effect or pending approval before the appropriate State regulatory authority or non-regulated electric utility on the date of enactment of this subsection, to purchase electric energy or capacity from or to sell electric energy or capacity to a qualifying cogeneration facility or qualifying small power production facility under this Act (including the right to recover costs of purchasing electric energy or capacity).
‘‘(7) RECOVERY OF COSTS .—

(A) The Commission shall issue and enforce such regulations as are necessary to ensure that an electric utility that purchases electric energy or capacity from a qualifying cogeneration facility or qualifying small power production facility in accordance with any legally enforceable obligation entered into or imposed under this section recovers all prudently incurred costs associated with the purchase.
‘‘(B) A regulation under subparagraph (A) shall be enforceable in accordance with the provisions of law applicable to enforcement of regulations under the Federal Power Act (16 U.S.C. 791a et seq.).

‘‘(n) RULEMAKING FOR NEW QUALIFYING FACILITIES .—

(1)(A) Not later than 180 days after the date of enactment of this section, the Commission shall issue a rule revising the criteria in 18 C.F.R. 292.205 for new qualifying cogeneration facilities seeking to sell electric energy pursuant to section 210 of this Act to ensure—

‘‘(i) that the thermal energy output of a new qualifying cogeneration facility is used in a productive and beneficial manner;
‘‘(ii) the electrical, thermal, and chemical output of the cogeneration facility is used fundamentally for industrial, commercial, or institutional purposes and is not intended fundamentally for sale to an electric utility, taking into account technological, efficiency, economic, and variable thermal energy requirements, as well as State laws applicable to sales of electric energy from a qualifying facility to its host facility; and
‘‘(iii) continuing progress in the development of efficient electric energy generating technology.

‘‘(B) The rule issued pursuant to section (n)(1)(A) shall be applicable only to facilities that seek to sell electric energy pursuant to section 210 of this Act. For all other purposes, except as specifically provided in section (m)(2)(A), qualifying facility status shall be determined in accordance with the rules and regulations of this Act.
‘‘(2) Notwithstanding rule revisions under paragraph (1), the Commission's criteria for qualifying cogeneration facilities in effect prior to the date on which the Commission issues the final rule required by paragraph (1) shall continue to apply to any cogeneration facility that—

‘‘(A) was a qualifying cogeneration facility on the date of enactment of subsection (m), or
‘‘(B) had filed with the Commission a notice of self certification, self-recertification or an application for Commission certification under 18 C.F.R. 292.207 prior to the date on which the Commission issues the final rule required by paragraph (1).''.

(b) ELIMINATION OF OWNERSHIP LIMITATIONS .—

(1) QUALIFYING SMALL POWER PRODUCTION FACILITY .—Section 3(17)(C) of the Federal Power Act (16 U.S.C. 796(17)(C)) is amended to read as follows:
‘‘(C) ‘qualifying small power production facility' means a small power production facility that the Commission determines, by rule, meets such requirements (including requirements respecting fuel use, fuel efficiency, and reliability) as the Commission may, by rule, prescribe;''.
(2) QUALIFYING COGENERATION FACILITY .—Section 3(18)(B) of the Federal Power Act (16 U.S.C. 796(18)(B)) is amended to read as follows:
‘‘(B) ‘qualifying cogeneration facility' means a cogeneration facility that the Commission determines, by rule, meets such requirements (including requirements respecting minimum size, fuel use, and fuel efficiency) as the Commission may, by rule, prescribe;''.

• Recognition of waste-heat recapture within renewable portfolios

The goal of renewable portfolio standards is to stimulate the development of technologies that generate useful power with a minimal environmental footprint. In pursuit of this objective, Congress should include “Recycled Energy”, or heat from electric generation normally wasted by traditional electric facilities but recaptured by CHP units for other uses, as eligible for credits within the RPS.

This is a relatively new idea that has been broached with Congress in 2002 (H.R. 4) but was ultimately discarded. The strength of the approach is that is allows entities affected (primarily utility companies) by the RPS greater latitude in meeting the standard's requirements while simultaneously generating the air quality and energy independence benefits sought by the RPS. In addition to utility companies, ratepayers' groups could be supporters (or, more likely, accept as a compromise) such a provision because it can lower the potential impact of an RPS on electricity costs. Detractors (generally, the renewable community) contend that while biomass CHP constitutes a renewable resource, such recycled energy is a fossil-fuel derivative and thus not a renewable.

No legislative language has yet been developed for this proposal.

• Clean distributed generation and transmission & distribution system policies

Two themes dominate USCHPA approaches to T&D issues: (1) a more inclusive planning process for T&D upgrades and (2) a realignment of T&D Tariffs to better capture the value CHP provides to the system.

(1) T&D Planning Processes

The August 14, 2003 Blackout put an exclamation point on calls to revamp policies and processes related to upgrades to and expansion of transmission and distribution systems (T&D). There was a strong consensus that current mechanisms do not adequately resolve system reliability problems but the consensus rapidly breaks down over how to do so. Post-Blackout discussions indicated a strong bias toward remedying these problems with new and improved transmission facilities.

The USCHPA advocates for a more holistic approach which includes a wider array of technologies that address both the supply and demand side of the equation. Transmission is not the only solution to reliability issues; customer-sited resources such as CHP, energy efficiency investments, and voluntary load curtailment programs targeted to congestion-stricken areas can defer or even supplant the need for transmission upgrades at a potentially lower cost.

The USCHPA embraces the spirit of the recommendations of the The New England Demand Response Initiative's (NEDRI) framework for a more holistic approach to T&D enhancements. Building on the NEDRI concept that planners should consider various approaches to resolving T&D gaps, the USCHPA proposed legislation that would encourage consideration of CHP alongside other forms of system upgrades. Specifically, the legislation stipulates that FERC will not grant eminent domain or modifications to the transmission tariff to an entity seeking to make a transmission upgrade if it can be shown that a CHP system would provide similar performance benefits at a lower cost.

The language below was submitted to the House Energy & Commerce Committee for consideration with the energy bill but it was ultimately not included in the Energy Bill. USCHPA considers this language a good starting place but estimates that the provision needs refinement before it can be expected to reach political viability.

Opposition to these types of policies typically come from T&D utilities, who have a strong preference for transmission-only system upgrades.

Consideration of least cost solutions, including distributed power and clean distributed generation, to transmission constraints

Within six months of the date of enactment of this section, the [Federal Energy Regulatory] Commission shall establish, by rule, standards providing for the consideration of combined heat and power (“CHP”) and other forms of clean and efficient distributed generation (“DG”) as an alternative to transmission line expansion or enhancement.

A) Such standards shall:

1) be applicable to all utilities;
2) apply in any instance where a ruling is sought by or on behalf of a utility from the Commission to:

(a) approve, permit, or authorize a transmission line right-of-way, upgrade, construction, expansion, enhancement, or other transmission project to increase electricity transfer capacity (collectively, “transmission project”), or
(b) to modify a utility's Commission-approved tariff to collect or recover any costs from such a transmission project.

3) provide that any utility seeking such Commission action must first file with the Commission a Preliminary Transmission Proposal including the following information:

(a) the proposed amount of increased power transfer capacity as a result of the transmission project;
(b) the expected annual deliveries of power in the first full year of operation;
(c) the expected line losses of transmitted energy in percentage and absolute terms;
(d) the expected annual, weekly, and daily load profiles for usage of that increased capacity;
(e) the geographical market region expected to be served by the transmission project;
(f) a not-to-exceed estimate of total cost and cost per kilowatt of delivered capacity;
(g) the portion of the projected cost to be paid by ratepayers versus from other sources;
(h) a not-to-exceed estimate of the time required to complete the proposed Transmission Project, including time for public acceptance and approvals; and
(i) impacts of the transmission project on system reliability, power quality, system security, public acceptance, and other ancillary benefits and costs.

B) Upon receipt of the Transmission Proposal, the Commission shall publicly post the Transmission Proposal for a period of 90 days.

C) During or before the expiration of the 90-day period, the Commission shall accept for filing and shall make publicly available:

1) Comments on the Preliminary Transmission propsal; and
2) Proposals for CHP/DG projects which their sponsors believe offer equal or better availability of the incremental electric energy or reliability in the designated market areas at equal or lower cost to ratepayers, including similar information to that for Preliminary Transmission Proposals as provided in subsection (A)(3) above.

(2) Realigning T&D Tariffs

The goal of this provision is to realign T&D tariffs such that they better capture the reliability value CHP units provide the grid. It is premised on the notion that CHP units can provide certain reliability benefits in critical areas of the electric grid, particularly in highly transmission-constrained zones such as those around New York City. The first provision directs the DOE to study the potential benefits to reliability and reductions in the cost of energy services associated with increasing the level of grid-based CHP. The second provision directs FERC to then capture these values in the transmission tariff in order to encourage CHP units to locate in these areas and provide the necessary reliability services. The third provision aims to ensure that CHP facilities are not unfairly punished by T&D providers for variable usage by the facility at which the CHP unit is sited.

As with its sister provision, opposition to these types of policies typically come from T&D utilities, who have a strong preference for transmission system upgrades.

TRANSMISSION POLICIES.

(a) STUDY OF COMBINED HEAT AND POWER BENEFITS. – Within one year of the date of enactment of this Act, the Commission shall identify and conduct a study of the potential benefits to electric energy transmission facilities provided by combined heat and power generation systems. The benefits to be evaluated shall include, but not be limited to --

(1) reductions in the use and congestion of the electric energy transmission facilities; (2) reductions in the cost of the electric energy transmission facilities; and
(3) deferral of otherwise necessary new investment in the electric energy transmission facilities.

(b) TRANSMISSION TARIFFS. – After completion of the study required by subsection (a) and upon its own motion or the motion of any owner or operator of a combined heat and power generation system, the Commission shall ensure that the applicable tariff for electric energy transmission service provided to the combined heat and power generation system fairly reflects all of the benefits to the electric energy transmission facilities provided by the combined heat and power generation system.
(c) FAIR TREATMENT OF VARIABLE TRANSMISSION UTILIZATION. –

(1) The Commission shall ensure that all transmitting utilities provide transmission service to combined heat and power generation systems in a manner that does not penalize such generators, directly or indirectly, for variable utilization of the transmission system.
(2) The Commission shall ensure that the requirement in paragraph (1) is met by adopting such policies as it deems appropriate which shall include, but not be limited to, the following:

(A) Subject to the sole exception set forth in subparagraph (B), the Commission shall ensure that the rates applicable to combined heat and power generation systems for transmission services do not directly or indirectly penalize such generation systems for scheduling deviations.
(B) The Commission may exempt a transmitting utility from the requirement set forth in subparagraph (A) if the transmitting utility demonstrates that scheduling deviations by the combined heat and power generation systems interconnected to the transmitting utility's system are likely to have a substantial adverse impact on the reliability of the transmitting utility's system. For purposes of administering this exemption, there shall be a rebuttable presumption of no adverse impact where combined heat and power generation systems collectively constitute 20 percent or less of total generation interconnected with transmitting utility's system and using transmission services provided by transmitting utility.
(C) The Commission shall ensure that to the extent any transmission charges recovering the transmitting utility's embedded costs are assessed to combined heat and power generation systems, they are assessed to such generation systems on the basis of the amount of electric energy transmitted over the transmitting utility's facilities rather than the capacity of the combined heat and power generation systems.
(D) As used in this subsection, the term “scheduling deviation” means delivery of more or less energy than has previously been forecast in a schedule submitted by a combined heat and power generation system to a control area operator or transmitting utility.

• Report on CHP Activities

This directs the DOE to issue a report on CHP activities. Its inclusion will serve as an aid to USCHPA interests in the public, private, and non-profit sectors in monitoring the market for CHP development.

REPORT ON STATUS OF COMBINED HEAT AND POWER DEVELOPMENT.

(a) INITIAL REPORT. -- Within 18 months of the date of enactment of this Act the Secretary of Energy shall report to the Congress on the status of combined heat and power generation development in the United States. Such report shall include, at a minimum --

(1) the amount of installed combined heat and power generation capacity in the United States in the calendar year preceding the date of the report;
(2) the amount of electric energy produced by combined heat and power generation systems during the calendar year immediately preceding the date of the report; and
(3) the amount of electric energy identified in paragraph (2) that was sold into the wholesale market for electric energy.

(b) SUBSEQUENT REPORTS. -- The Secretary of Energy shall revise and update the initial report prepared pursuant to subsection (a) every 12 months after the date of submission of the initial report. (c) AUTHORIZATION OF APPROPRIATIONS. – There are authorized to be Appropriated to the Secretary of Energy, such sums as may be necessary to carry out the requirements of this section.

See http://nedri.raabassociates.org/Articles/FinalNEDRIREPORTAug%2027.doc

Utility Regulatory Issues

• Interconnection and Standby Charges

A robust interconnection regime is a basic foundation of a viable CHP market. Since CHP machines serve facilities that must remain online in the event that the CHP unit goes offline due to maintenance or failure, the facility must be able to access grid-based power. Moreover, interconnection with the grid allows the CHP operator the option to play in wholesale electric markets, which often improves the economics of CHP projects.

An ideal interconnection regime should provide CHP developers with as much regulatory certainty as possible. Most critically, this includes guidelines for the length of time and costs required to complete any studies required to assess the CHP's impact on grid operations, guidelines for the identification and application of protective devices to protect the grid and personnel in the event of outage.

The interconnection provision below directs FERC to promulgate rules for the interconnection of CHP units to T&D facilities. FERC undertook such a process beginning in 2002, absent a Congressional mandate, but the process is currently stalled. A major axis of contention is whether FERC has the authority to makes rules on distribution system interconnection. State governments argue that this falls within the statutory authority of the states to regulate electricity distribution. FERC contends that to the extent distribution systems are involved with the interstate sale of electricity, the Commerce Clause of the Constitution empowers FERC to regulate interstate commerce. FERC asserts that this constitutional authority supercedes states' statutory jurisdiction over distribution-level interconnection because those interconnections are involved in interstate commerce.

There is some doubt among CHP advocates whether the FERC interconnection process will ultimately benefit CHP and whether a final rule will be promulgated. FERC has not pressed the jurisdiction debate formally and the process has been dormant.

The language below also secures a facilities' right to back-up power from the utility. This shall be assessed as the “actual incremental cost” incurred by the utility to serve the CHP facility, including any capacity charges. No specific language has yet been proposed for assessing these costs.

This language has been vetted and supported by the International District Energy Association and a coalition of industrial CHP users for inclusion in a CHP Advancement Act that has not yet been submitted to Congress for consideration.

INTERCONNECTION STANDARDS AND PROCEDURES.

(a) INTERCONNECTION TO DISTRIBUTION FACILITIES. -- Section 210 of the Federal Power Act (16 U.S.C. 824i) is amended by inserting after subsection (e) the following --
“(f) INTERCONNECTION TO DISTRIBUTION FACILITIES. --

“(1) INTERCONNECTION. --

“(A) IN GENERAL. -- A local distribution utility shall interconnect a generating facility with the distribution facilities of the local distribution utility if the owner of the generating facility --

“(i) complies with the final rule promulgated under paragraph (2); and
“(ii) pays the costs of the interconnection, including the generating facility's appropriate share of the necessary and reasonable costs associated with any upgrades to system facilities.

“(B) COSTS. -- The costs of the interconnection shall be--

“(i) just and reasonable,
“(ii) not unduly discriminatory or preferential, and
“(iii) comparable to the costs charged by the local distribution utility for interconnection by any similarly situated generating facility to the distribution facilities of the local distribution utility, as determined by the appropriate regulatory authority.

“(C) APPLICABLE REQUIREMENTS- The right of a generating facility to interconnect under subparagraph (A) does not--

“(i) relieve the generating facility or the local distribution utility of other Federal, State, or local requirements;
“(ii) include a right to transmission or distribution service for the generating facility; or
“(iii) allow the generating facility or its customer to bypass or avoid payment of any costs approved for recovery by the appropriate regulatory authority, or deprive the generating facility or its customer of any rights or arguments it might have to avoid paying such costs.

`(2) RULE. –

“(A) IN GENERAL. -- Not later than 1 year after the date of enactment of this subsection, the Commission shall promulgate a final rule establishing reasonable and appropriate technical standards for the interconnection of a generating facility with the distribution facilities of a local distribution utility, and shall provide for the updating or modification of such standards when appropriate.
“(B) PROCESS. -- To the extent feasible, the Commission shall develop the standards through a process involving interested parties, and shall rely, where appropriate, on standards developed through independent standard setting organizations.

“(3) RIGHT TO BACKUP POWER. --

“(A) IN GENERAL- In accordance with subparagraph (B), a local distribution utility shall offer to provide backup power to a generating facility or a retail electric consumer to the extent that the local distribution utility is obligated under State law to provide electricity supply service to retail electric consumers in the area in which the generating facility is located and

“(i) is not subject to an order of a non-Federal regulatory authority to provide open access to its facilities;
“(ii) has not offered to provide open access to its facilities; or
“(iii) does not allow a generating facility to purchase backup power from another entity using its facilities under terms that are just and reasonable, and not unduly discriminatory or preferential.

“(B) RATES, TERMS, AND CONDITIONS. -- A sale of backup power under subparagraph (A), for both firm and interruptible backup power service, shall be at such rates and under such terms and conditions, as determined by and filed with the appropriate regulatory authority, as are just and reasonable and not unduly discriminatory or preferential, taking into account--

“(i) the actual incremental cost, whenever incurred by the local distribution utility, to supply such backup power service during the period in which the backup power service is provided, and
“(ii) any capacity charges assessed against similarly situated generating facilities in the area in which the generating facility is located.

“(C) NO REQUIREMENT FOR CERTAIN SALES. -- A local distribution utility shall not be required to provide backup power for resale.

“(D) NEW OR EXPANDED LOADS.-- To the extent backup power is used to serve a new or expanded load on the distribution system, the generating facility shall pay the appropriate share of the necessary and reasonable costs associated with any upgrades to transmission, distribution, or generation facilities required to provide such service, as determined by the appropriate regulatory authority.

“(4) ADMINISTRATION. --

“(A) BY A NON-FEDERAL REGULATORY AUTHORITY. -- Except where subject to the jurisdiction of the Commission pursuant to provisions other than subparagraph (B), a non-Federal regulatory authority may administer and enforce the rule promulgated under subparagraph (2)(A) and administer and enforce the requirements of paragraph 3 for backup power.
“(B) BY THE COMMISSION. -- To the extent that a non-Federal regulatory authority does not administer and enforce the rule or the backup power requirements, the Commission shall administer and enforce the rule or the backup power requirements, as appropriate, with respect to interconnection in that jurisdiction.”.

(b) INTERCONNECTION TO TRANSMISSION FACILITIES. -- Section 210 of the Federal Power Act (16 U.S.C. 824i) is amended by inserting after subsection (f) (as added by subsection (a) of this Section) the following:
“(g) INTERCONNECTION TO TRANSMISSION FACILITIES. --

“(1) INTERCONNECTION. --
“(A) DEFINITION. -- For purposes of this subsection and subsection (h) the term `transmitting utility' means any entity (notwithstanding section 201(f)) that owns, controls, or operates an electric power transmission facility that is used for the sale of electric energy.
“(B) IN GENERAL- Notwithstanding subsections (a) and (c), a transmitting utility shall interconnect a generating facility with the transmission facilities of the transmitting utility if the owner of the generating facility--

“(i) complies with the final rule promulgated under paragraph (2); and
“(ii) pays the costs of the interconnection, including the generating facility's appropriate share of the necessary and reasonable costs associated with any upgrades to system facilities.

“(C) COSTS. --

“(i) IN GENERAL. -- The costs of the interconnection shall be --
“(I) comparable to the costs charged by the transmitting utility for interconnection by any similarly situated generating facility to the transmission facilities of the transmitting utility, or
“(II) otherwise negotiated and agreed to by the parties, provided that such costs are approved by the Commission as just and reasonable and not unduly discriminatory or preferential.
“(ii) DETERMINATION OF INTERCONNECTION COSTS. -- A non-Federal regulatory authority that is authorized to determine the rates for transmission service on facilities subject to its jurisdiction shall be authorized to determine the costs of any interconnection to such facilities under this subparagraph.

“(D) APPLICABLE REQUIREMENTS. -- The right of a generating facility to interconnect under subparagraph (B) does not --

“(i) relieve the generating facility or the transmitting utility of other Federal, State, or local requirements;
“(ii) include a right to transmission or distribution service for the generating facility; or
“(iii) allow the generating facility or its customer to bypass or avoid payment of any costs approved for recovery by the appropriate regulatory authority, or deprive the generating facility or its customer of any rights or arguments it might have to avoid paying such costs.

“(2) RULE. --

“(A) IN GENERAL. -- Not later than 1 year after the date of enactment of this subsection, the Commission shall promulgate a final rule establishing reasonable, appropriate, and technically feasible technical standards for the interconnection of a generating facility with the transmission facilities of a transmitting utility.
“(B) PROCESS. -- To the extent feasible, the Commission shall develop the standards through a process involving interested parties, and shall rely, where appropriate, on standards developed through independent standard setting organizations.

“(3) RIGHT TO BACKUP POWER. --

“(A) IN GENERAL- In accordance with subparagraph (B), a local distribution utility that is obligated under State law to provide electricity supply to retail electric consumers in the area in which the generating facility is located shall offer to provide backup power to the generating facility at the interconnection point and to a retail electric consumer, unless--

“(i) Federal, State, or local law (including regulations) allows such a generating facility or retail electric consumer to purchase backup power from an entity other than the local distribution utility; or
“(ii) the local distribution utility allows a generating facility to purchase backup power from an entity other than the local distribution utility using--

“(I) the transmission facilities of the transmitting utility; or
“(II) the transmission facilities of any other transmitting utility that allows such transmission.

“(B) RATES, TERMS, AND CONDITIONS. -- A sale of backup power under subparagraph (A), for both firm and interruptible backup power service, shall be at such rates and under such terms and conditions, as determined by and filed with the appropriate regulatory authority, as are just and reasonable and not unduly discriminatory or preferential, taking into account --

“(i) the actual incremental cost, whenever incurred by the local distribution utility, to supply such backup power service during the period in which the backup power service is provided, and
“(ii) any capacity charges assessed against similarly situated generating facilities in the area in which the generating facility is located.

“(C) NO REQUIREMENT FOR CERTAIN SALES. -- A local distribution utility shall not be required to provide backup power for resale.
“(D) NEW OR EXPANDED LOADS. -- To the extent backup power is used to serve a new or expanded load on the transmission system, the generating facility shall pay the appropriate share of the necessary and reasonable costs associated with any upgrades to transmission, distribution, or generating facilities required to provide such service, as determined by the appropriate regulatory authority.
“(E) ADMINISTRATION. --

“(i) BY A NON-FEDERAL REGULATORY AUTHORITY. -- Except where subject to the jurisdiction of the Commission pursuant to provisions other than clause (ii), a non-Federal regulatory authority may administer and enforce the requirements of this paragraph for backup power.
“(ii) BY THE COMMISSION- To the extent that a non-Federal regulatory authority does not administer and enforce the backup power requirements, the Commission shall administer and enforce the backup power requirements with respect to interconnection in that jurisdiction.”.

(c) TRANSMISSION INTERCONNECTION PROCESS AND PROCEDURES. -- Section 210 of the Federal Power Act is amended by inserting after subsection (g) (as added by subsection (b)) the following:

“(h) TRANSMISSION INTERCONNECTION PROCESS AND PROCEDURES-

“(1) Within 180 days of the enactment of this section, the Commission shall issue a rule establishing procedures governing --

“(A) the interconnection of new generating facilities to a transmission system owned or operated by any transmitting utility or any regional transmission organization approved by the Commission; and

“(B) the increase in capacity of an existing generating facility interconnected to a transmission system owned or operated by any transmitting utility or any regional transmission organization approved by the Commission.

Such rulemaking proceeding shall establish interconnection procedures and required elements for interconnection agreements as provided in paragraphs (2) and (3). The Commission shall apply similar procedures and required elements to the interconnection of new generating facilities to a distribution system to the extent that the Commission has jurisdiction to do so pursuant to paragraph (f)(4) of this section. Nothing in this section or subsection shall affect the terms and conditions of existing agreements between qualifying facilities and utilities pursuant to 18 CFR 292.

“(2) INTERCONNECTION PROCEDURES. -- Pursuant to the rulemaking proceeding under paragraph (1) of this subsection, the Commission shall establish interconnection procedures to govern the process in which any transmitting utility or regional transmission organization responds to and resolves interconnection requests. Such procedures shall include provisions governing each of the following:

“(A) The study or studies to be conducted to ensure that the interconnection can occur without compromising the reliability of the system being interconnected.

“(B) The time frames for completing such study or studies.

“(C) The priorities among generating facilities that submit interconnection requests.

“(D) The rights that new generating facilities have upon interconnection.

“(E) Compensation, if and as appropriate, for transmitting utilities or regional transmission organizations for the costs of processing the interconnection requests.

“(F) Criteria for assuring that such interconnections will meet applicable reliability standards and will not adversely affect existing transmission operations or service.

“(G) Criteria for assuring that such interconnections will not violate applicable laws (including safety and environmental laws), rules, or contracts.

Any transmitting utility or regional transmission organization shall include such interconnection procedures in its tariffs filed with and approved by the Commission under section 205 of this Act. The Commission may approve different or additional provisions in the interconnection procedures if the different or additional provisions are substantially comparable with the procedures established by the Commission pursuant to this section.

“(3) REQUIRED ELEMENTS FOR INTERCONNECTION AGREEMENTS. -- Pursuant to the rulemaking proceeding under paragraph (1) of this subsection, the Commission shall also identify the required elements for interconnection agreements. Each such interconnection agreement shall contain provisions respecting --

“(A) the cost responsibility for facilities necessary to interconnect the new generating facility or for upgrades to the transmission system required to allow the reliable interconnection of the new generating facility;

“(B) the security and creditworthiness requirements for constructing the interconnection facilities or system upgrades;

“(C) the methods for preserving the confidentiality of information exchanged between any new generating facility, and any transmitting utility or regional transmission organization;

“(D) the requirements for operating any new generating facility in parallel with the transmission system; and

“(E) the methods for resolving disputes between any new generating facility, and any transmitting utility or regional transmission organization.

“(4) EXECUTION OF INTERCONNECTION AGREEMENT. -- Each interconnection agreement under this section shall be executed both by any new generating facility, and by any transmitting utility or regional transmission organization before the commencement of the construction of facilities necessary to interconnect such new generating facility. Such generating facility and transmitting utility or regional transmission organization may agree to different or additional terms and conditions in their interconnection agreement than required under paragraph 3 if they are consistent with the elements for interconnection agreements established by the Commission. The Commission shall resolve any dispute between the parties to such an agreement or any refusal to execute such an agreement within sixty days of notice by either party of the dispute or refusal.

“(5) EXEMPTION FROM COMMISSION APPROVED PROCEDURES. -- Any transmitting utility or regional transmission organization shall be exempted by the Commission from the requirements of this subsection, upon a showing by the transmitting utility, regional transmission organization, or a generating facility that substantially comparable interconnection procedures and agreements previously have been filed with and approved by the Commission for interconnection with that entity. Any interconnecting generating facility may be entitled to interconnect with that entity under such substantially comparable interconnection procedures and agreements.”.

(d) CONFORMING AMENDMENTS. -- Section 210 of the Federal Power Act (16 U.S.C. 824i) is amended as follows:

(1) In subsection (a)(1) --

(A) by inserting `transmitting utility, local distribution utility,' after `electric utility,'; and

(B) in subparagraph (A), by inserting `any transmitting utility,' after `small power production facility,'.

(2) In subsection (c)(2) --

(A) in subparagraph (B), by striking `or' at the end;

(B) in subparagraph (C), by striking `and' at the end and inserting `or'; and

(C) by adding at the end the following:

“(D) promote competition in electric energy markets, and”.

(3) In subsection (d), by striking the last sentence.

(4) In subsection (e)(1), by inserting “subsections (a) through (d) of “ after “used in”.

• Natural Gas Delivery Rates

This provision directs state authorities to consider providing CHP facilities with preferential natural gas delivery rates. It has been vetted by a coalition of large industrial CHP users and IDEA, but it has not yet been formally introduced. It is not clear whether the provision would face substantial political opposition.

SECTION 5. NATURAL GAS DELIVERY RATES . –

Each appropriate State authority with responsibility for regulating distribution of natural gas to consumers shall consider and make a determination concerning whether or not it is appropriate to implement natural gas delivery rates for operators of combined heat and power generation systems that are comparable to the delivery rates applicable to centrally located electric generation facilities .

Tax Issues

• 10% Tax Credit for CHP Investments

The USCHPA has been successful in convincing the 108th Congress to grant tax credits for CHP investments. These amount to 10% of the value of the CHP investment.

Although the tax credits are themselves uncontroversial and were included in the Energy Bill conference report passed by the House in November, 2003, action contemplated by the Senate threatens to diminish the value of the credits. Under severe budgetary pressure, the Senate moved to cut the overall tax package by $14 billion by reverting to the Senate's version of the Energy Bill as it went into conference. That text includes the tax credit but lengthens the depreciation schedule for some equipment eligible for the break, making it less attractive.

The USCHPA recommends that the Senate include the House conference report with the more favorable depreciation terms.

As of publication of this document the new Energy Bill had not reached the floor of the Senate. The provision below represents the USCHPA's preferred language, which slightly aments Section 1306 of the House-passed Energy Conference Report to eliminate a 15 MW cap on eligibility.

ENERGY CREDIT FOR COMBINED HEAT AND POWER SYSTEM PROPERTY.

(a) IN GENERAL .—Section 48(a)(3)(A) (defining energy property), as amended by this Act, is amended by striking ‘‘or'' at the end of clause (ii), by adding ‘‘or'' at the end of clause (iii), and by inserting after clause (iii) the following new clause:

‘‘(iv) combined heat and power system property,''

(b) COMBINED HEAT AND POWER SYSTEM PROPERTY .— Section 48 (relating to energy credit; reforestation credit), as amended by this Act, is amended by adding at the end the following new subsection:

‘‘(d) COMBINED HEAT AND POWER SYSTEM PROPERTY .—For purposes of subsection (a)(3)(A)(iv)—

‘‘(1) COMBINED HEAT AND POWER SYSTEM PROPERTY .—The term ‘combined heat and power system property' means property comprising a system—

‘‘(A) which uses the same energy source for the simultaneous or sequential generation of electrical power, mechanical shaft power, or both, in combination with the generation of steam or other forms of useful thermal energy (including heating and cooling applications),

‘‘(B) which produces—

‘‘(i) at least 20 percent of its total useful energy in the form of thermal energy which is not used to produce electrical or mechanical power (or combination thereof), and

‘‘(ii) at least 20 percent of its total useful energy in the form of electrical or mechanical power (or combination thereof),

‘‘(C) the energy efficiency percentage of which exceeds 60 percent, and 5

‘‘(D) which is placed in service before January 1, 2007.

‘‘(2) SPECIAL RULES .—

‘‘(A) ENERGY EFFICIENCY PERCENTAGE .—For purposes of this subsection, the energy efficiency percentage of a system is the fraction—

‘‘(i) the numerator of which is the total useful electrical, thermal, and mechanical power produced by the system at normal operating rates, and expected to be consumed in its normal application, and

‘‘(ii) the denominator of which is the lower heating value of the fuel sources for the system. 20

‘‘(B) DETERMINATIONS MADE ON BTU BASIS .—The energy efficiency percentage and the percentages under paragraph (1)(C) shall be determined on a Btu basis.

‘‘(C) INPUT AND OUTPUT PROPERTY NOT INCLUDED .—The term ‘combined heat and power system property' does not include property used to transport the energy source to the facility or to distribute energy produced by the facility.

‘‘(D) PUBLIC UTILITY PROPERTY .—

‘‘(i) ACCOUNTING RULE FOR PUBLIC UTILITY PROPERTY .—If the combined heat and power system property is public utility property (as defined in section 168(i)(10)), the taxpayer may only claim the credit under subsection (a) if, with respect to such property, the taxpayer uses a normalization method of accounting.

‘‘(ii) CERTAIN EXCEPTION NOT TO APPLY .—The matter in subsection (a)(3) which follows subparagraph (D) thereof shall not apply to combined heat and power system property.

‘‘(3) SYSTEMS USING BAGASSE .—If a system is designed to use bagasse for at least 90 percent of the energy source—

‘‘(A) paragraph (1)(D) shall not apply, but

‘‘(B) the amount of credit determined under subsection (a) with respect to such system shall not exceed the amount which bears the same ratio to such amount of credit (determined without regard to this paragraph) as the energy efficiency percentage of such system bears to 60 percent.''.

EFFECTIVE DATE .—The amendments made by this subsection shall apply to periods after December 31, 2003, in taxable years ending after such date, under rules similar to the rules of section 48(m) of the Internal Revenue Code of 1986 (as in effect on the day before the date of the enactment of the Revenue Reconciliation Act of 1990).

Environmental Regulatory Issues

• Output-based allocation

A major pillar of the USCHPA policy agenda is the creation of policy instruments that capture CHP's value to enhancing air quality, ideally by means of a multiple-pollutant cap-and-trade mechanism for key pollutants, including greenhouse gasses (GHG), sulphur oxides (SO x ), nitrogen oxides (NO x ), and mercury (Hg).

The USCHPA has not yet authored its own multi-pollutant strategy. In large measure this is a function of the fact that these mechanisms deal with broad swathes of the electricity industry and not just CHP. However, any meaningful multiple-pollutant bill must have the following essential characteristics:

Comprehensive inclusion of all major pollutants. The four noted above, GHG's, NO x , SO x , and Hg, constitute the 4 pollutants in bills offered by James Jeffords (I-VT) and Thomas Carper (D-DE). The Bush Administration's Clear Skies proposal does not include Carbon Dioxide (CO 2 ), thus failing to capture CHP's value as a tool for limiting GHG emissions and global climate change.

Output-based emission allocations . Pollution credits should be distributed on the basis of the amount of energy produced. Schemes such as Clear Skies rely on input-based allocations. Output-based allocations encourage greater efficiencies by tying the level of pollution a facility permitted to the amount of energy actually produced, in contrast to input-based systems which link the credits to the amount of fuel consumed.

A fair playing field for new entrants. Since the raison d'être for a credit trading scheme is to enhance air quality, the scheme must not create barriers to entry for new, cleaner technologies. Thus, any system whereby existing units are granted credits but new units are required to buy them, as Clear Skies would, runs counter to the intent of a pollution-reduction scheme by constraining the market for pollution remedies. The USCHPA prefers either a system based on auctions or periodic updating of emissions allocations.

Until the USCHPA develops its own multiple pollutant strategy, one useful point of reference is the language offered by Senator Thomas Carper's bill, S. 843 ( click to view).

Budget and Appropriation Issues

While much of this language has not been formally submitted to Congress it closely mirrors provisions in the House-approved energy conference report. It is unlikely to face opposition, however, in the current budget climate securing additional funds for CHP projects will prove a challenge.

• Office of Electrical Transmission and Distribution

Created amid much fanfare in 2003, the Office of Electric Transmission and Distribution (OETD) has been hampered by a lack of a Congressional mandate and, more importantly, a budget that has been eaten away by earmarks. Ironically, the intensification of interest in the nation's transmission and distribution (T&D) infrastructure has not yet resulted in a change in either, although the Bush administration did propose increasing the OETD's budget slightly from $88 million to $91 million from FY 2004 to FY 2005.

The USCHPA supports the OETD for its potential role in enhancing understanding of how CHP can contribute to T&D-related reliability issues. In February, 2004 the USCHPA joined a coalition of transmission interests to secure enhanced funding levels for the OETD. The USCHPA also supports language included in the House-passed conference report ( Section 1227 ) that provides formal Congressional sanctioning for this office within the DOE.

OFFICE OF ELECTRIC TRANSMISSION AND DISTRIBUTION.

The following is Section 1227 of the House-passed Energy Conference Report

• CREATION OF AN OFFICE OF ELECTRIC TRANSMISSION AND DISTRIBUTION.—

• Title II of the Department of Energy Organization Act (42 U.S.C. 7131 et seq.) (as amended by section 502(a) of this Act) is amended by inserting the following after section 217, as added by title V of this Act:

‘‘SEC. 218. OFFICE OF ELECTRIC TRANSMISSION AND DISTRIBUTION.

‘‘(a) ESTABLISHMENT .—There is established within the Department an Office of Electric Transmission and Distribution. This Office shall be headed by a Director, subject to the authority of the Secretary. The Director shall be appointed by the Secretary. The Director shall be compensated at the annual rate prescribed for level IV of the Executive Schedule under section 5315 of title 5, United States Code.

‘‘(b) DIRECTOR .—The Director shall—

‘‘(1) coordinate and develop a comprehensive, multi-year strategy to improve the Nation's electricity transmission and distribution;

‘‘(2) implement or, where appropriate, coordinate the implementation of, the recommendations made in the Sec-retary's May 2002 National Transmission Grid Study;

‘‘(3) oversee research, development, and demonstration to support Federal energy policy related to electricity transmission and distribution;

‘‘(4) grant authorizations for electricity import and export pursuant to section 202(c), (d), (e), and (f) of the Federal Power Act (16 U.S.C. 824a);

‘‘(5) perform other functions, assigned by the Secretary, related to electricity transmission and distribution; and

‘‘(6) develop programs for workforce training in power and transmission engineering.''.

• CONFORMING AMENDMENTS .—(1) The table of contents of the Department of Energy Organization Act (42 U.S.C. 7101 note) is amended by inserting after the item relating to section 217 the following new item:

‘‘Sec. 218. Office of Electric Transmission and Distribution.''.

(2) Section 5315 of title 5, United States Code, is amended by inserting after the item relating to ‘‘Inspector General, Department of Energy.'' the following:‘‘Director, Office of Electric Transmission and Distribution, Department of Energy.''.

• Electric Transmission and Distribution Programs

The USCHPA proposes a program within the OETD to commercialize the grid reliability benefits of CHP. The language below is very similar to Section 1225 of the House-passed energy conference report, calling for wider commercialization of grid-enhancing technology. The language here has been slightly altered to make it optimal for CHP. As an authorization, any such language must be reinforced by a formal appropriation. However, the program represents one potential avenue for CHP to bolster grid reliability.

ELECTRIC TRANSMISSION AND DISTRIBUTION PROGRAMS.

The following significantly modifies Section 1225 of the House-passed Energy Conference Report

• ELECTRIC TRANSMISSION AND DISTRIBUTION PROGRAM.—The Secretary of Energy (hereinafter in this section referred to as the ‘‘Secretary'') acting through the Director of the Office of Electric Transmission and Distribution shall establish a comprehensive research, development, demonstration and commercial application program to promote improved reliability and efficiency of electrical transmission and distribution systems through the integration of efficient combined heat and power systems and distributed and residential-based power generators.

• GOALS.—The goals of this initiative shall be to—

• establish facilities to develop grid-based distributed energy generation applications in partnership with manufacturers and utilities;

• provide technical leadership for establishing performance-based reliability standards for grid-based distributed energy generation applications including suitable modeling and analysis;

• facilitate commercial transition toward more integration of grid-based distributed energy generation applications;

• facilitate the integration of grid-based distributed energy generation applications to improve system performance, power flow control and reliability.

• PROGRAM PLAN.— Not later than 1 year after the date of the enactment of this legislation, the Secretary, in consultation with other appropriate Federal agencies, shall prepare and transmit to Congress a 5-year program plan to guide activities under this section. In preparing the program plan, the Secretary may consult with utilities, energy services providers, manufacturers, institutions of higher education, other appropriate State and local agencies, environmental organizations, professional and technical societies, and any other persons the Secretary considers appropriate.

• IMPLEMENTATION.—The Secretary shall consider implementing this program using a consortium of industry, university and national laboratory participants.

• REPORT.—Not later than 2 years after the transmittal of the plan under subsection (b), the Secretary shall transmit a report to Congress describing the progress made under this section and identifying any additional resources needed to continue the development and commercial application of transmission and distribution infrastructure technologies.

• AUTHORIZATION OF APPROPRIATIONS.—For purposes of carrying out this subsection, there are authorized to be appropriated—

• for fiscal year 2004, $15,000,000;

• for fiscal year 2005, $20,000,000;

• for fiscal year 2006, $30,000,000;

• for fiscal year 2007, $35,000,000; and

• for fiscal year 2008, $40,000,000.

• Advanced Power System Technology Program

The House-passed Energy Bill conference report contained a provision that would enhance funding for advanced energy technologies. The original provision was designed for a range of technologies; this one has been modified specifically for CHP units. As with the T&D programs discussed above, this should best be considered within the context of the appropriations process.

ADVANCED POWER SYSTEM TECHNOLOGY INCENTIVE PROGRAM.

The following significantly modifies Section 1226 of the House-passed Energy Conference Report

• PROGRAM.—The Secretary of Energy is authorized to establish an Advanced Power System Technology Incentive Program to support the deployment of certain CHP and distributed energy technologies and to improve and protect certain critical governmental, industrial, and commercial processes. Funds provided under this section shall be used by the Secretary to make incentive payments to eligible owners or operators of advanced power system technologies to increase power generation through enhanced operational, economic, and environmental performance. Payments under this section may only be made upon receipt by the Secretary of an incentive payment application establishing an applicant as either—

• a qualifying advanced power system technology facility; or

• a qualifying security and assured power facility.

• INCENTIVES.—Subject to availability of funds, a payment of 1.8 cents per kilowatt-hour shall be paid to the owner or operator of a qualifying advanced power system technology facility under this section for electricity generated at such facility. An additional 0.7 cents per kilowatt-hour shall be paid to the owner or operator of a qualifying security and assured power facility for electricity generated at such facility. Any facility qualifying under this section shall be eligible for an incentive payment for up to, but not more than, the first 10,000,000 kilowatt-hours produced in any fiscal year.

• ELIGIBILITY.—For purposes of this section:

• QUALIFYING ADVANCED POWER SYSTEM TECHNOLOGY FACILITY.—The term ‘‘qualifying advanced power system technology facility'' means a facility using an advanced fuel cell, turbine, or hybrid power system generate electric energy and, where applicable, useful thermal output. .

• QUALIFYING SECURITY AND ASSURED POWER FACILITY.—The term ‘‘qualifying security and assured power facility'' means a qualifying advanced power system technology facility determined by the Secretary of Energy, in consultation with the Secretary of Homeland Security, to be in critical need of secure, reliable, rapidly available, high-quality power for critical governmental, industrial, or commercial applications.

AUTHORIZATION.—There are authorized to be appropriated to the Secretary of Energy for the purposes of this section, $20,000,000 for each of the fiscal years 2004 through 2010.

• Revolving fund for non-profit CHP facilies

Created in concert with the International District Energy Association, this provision has two components that aim to improve the proliferation of CHP. The first is a technical assistance program that provides entities interested in CHP projects assistance in identifying opportunities, negotiating interconnection and fuel input contracts, identifying financing, permitting, etc. This includes financial assistance for performing feasibility studies, overcoming implementation barriers, engineering and design of CHP facilities.

The second component is a revolving fund that provides up to 70% of a project's total capital costs, not to exceed $15 million at an advantageous interest rate .

CHP INFRASTRUCTURE INITIATIVE

(a) ESTABLISHMENT. – The Secretary of Energy shall, with funds appropriated for this purpose, implement a program of information dissemination and technical assistance to colleges, universities, airports, hospitals, public utilities, local governments, state governments, federal agencies and other public or non-profit entities to assist them in identifying, evaluating, designing and implementing CHP infrastructure.

(b) INFORMATION DISSEMINATION. -- The Secretary shall develop information and assessment tools addressing—

(1) Identification of opportunities to use CHP in public sector institutions;

(2) Technical and economic characteristics of CHP;

(3) Utility interconnection, negotiation of power and fuel contracts;

(4) Financing alternatives;

(5) Permitting and siting issues;

(6) Case studies of successful CHP systems; and

(7) Computer software for assessment, design and operation and maintenance of CHP systems.

(c) ELIGIBLE APPLICANTS. -- Entities eligible to receive technical assistance include colleges, universities, airports, hospitals, public utilities, local governments, state governments, federal agencies and other public or non-profit organizations.

(d) ELIGIBLE COSTS. -- Upon application by an eligible applicant, the Secretary is authorized to make grants to such applicants to fund---

(1) 75 percent of the cost of feasibility studies to assess the potential for implementation of CHP;

(2) 60 percent of the cost of guidance on overcoming barriers to project implementation (financial, contracting, siting, permitting); and

(3) 45 percent of the cost of detailed engineering and design of CHP and related facilities.

(e) REPAYMENT OF FEDERAL COST SHARE. -- Upon the close of financing for construction of any CHP system for which federal cost-shared technical assistance was provided, the owner of the system shall repay the Federal government for such cost share.

(f) AUTHORIZATION OF APPROPRIATIONS. -- There are authorized to be appropriated to carry out this Act $5 million for fiscal year 2005, $15 million for fiscal year 2006 and $30 million for fiscal year 2007.

CHP IMPLEMENTATION REVOLVING FUND

(a) ESTABLISHMENT. -- The Secretary of Energy shall, with funds appropriated for this purpose, create a CHP Revolving Fund Corporation for the purpose of establishing and operating a CHP Revolving Fund (hereafter referred to as the "CRF") for the purpose of providing loans for the construction of CHP and related facilities for distribution of thermal energy to users.

(b) ELIGIBLE COSTS. -- Loans provided from the CRF shall be no more than 70 percent of the total capital costs and shall not exceed $15 million, for constructing CHP plant and related facilities, including:

(1) plant facilities used for cogenerating thermal energy and electricity in CHP systems;

(2) facilities for storing thermal energy generated through CHP;

(3) facilities for distribution of thermal energy generated through CHP; and

(4) costs for converting buildings to use thermal energy from CHP.

(c) QUALIFICATIONS. -- Loans from the CRF may be made to for-profit or non-profit entities for projects meeting the qualifications and conditions established by the Corporation, including the following minimum qualifications:

(1) The project is technically and economically feasible as determined by a detailed feasibility analysis performed or corroborated by an independent consultant;

(2) The borrower can demonstrate that adequate and comparable financing was not found to be reasonably available from other sources, and that the project is economically more feasible with the availability of the CRF loan; and

(3) The borrower has obtained commitments for the remaining capital required to implement the project, contingent on approval of the CRF loan.

(d) FINANCING TERMS. -- Loans shall be made under the following terms:

(1) Interest on the loan may be a fixed rate or floating rate and shall be equal to the federal cost of funds consistent with the loan type and term;

(2) Interest shall accrue from the date of the loan, but the first payment of interest shall be deferred for a period, not to exceed three years from the date of operation of the system;

(3) Interest attributable to the period of deferred payment shall be amortized over the remainder of the loan term;

(4) Principal shall be repaid on a schedule established at the time the loan is made and shall be initiated no later than three years from the date of operation of the system;

(5) Loans made from the CRF shall be repayable over a period of not more than twenty years from the date the loan is made;

(6) The loan shall be pre-payable at any time without penalty; and

(7) The CRF loan shall be subordinate to other loans for the project.

(e) FUNDING CYCLES. -- Applications for loans from the CRF shall be received on a periodic basis at least semi-annually.

(f) APPLICATION OF REPAYMENTS FOR DEFICIT REDUCTION. Loans from the CRF shall be made, with funds available for this purpose, during the ten years starting from the date that the first loan from the fund is made. Until this ten year period ends, funds repaid by borrowers shall be deposited in the CRF to be made available for additional loans. Once loans from the CRF are no longer being made, repayments will go directly into the U.S. Treasury for the purpose of reducing the federal budget deficit.

(g) PRIORITIES. -- In evaluating projects for funding, priority shall be given to projects which:

(1) maximize energy efficiency;

(2) minimize environmental impacts, including regulated air pollutants, greenhouse gas emissions and use of refrigerants known to cause ozone depletion;

(3) use renewable energy resources;

(4) maximize oil displacement; and

(5) benefit economically-depressed areas.

(h) REGULATIONS. -- Within one year after enactment of this Act, the Secretary shall develop a plan and adopt rules and procedures for establishing and operating the CRF.

(i) PROGRAM REVIEW. -- Every two years the Secretary shall report to the Congress on the status and progress of the CRF.

(j) AUTHORIZATION OF APPROPRIATIONS. -- There are authorized to be appropriated to carry out this Act $50 million for fiscal year 2005, $150 million for fiscal year 2006 and $250 million for fiscal year 2007.

• Low income program

The 2003 Energy bill includes the following program to help finance CHP project in low-income communities. Given recent calls for increasing the Low Income Heating Assistance Program (LIHEAP) resulting out of a cold winter in the Northeast and high gas prices, such an efficiency measure could serve as a useful companion to any measures aimed at increasing LIHEAP funding.

LOW INCOME COMMUNITY ENERGY EFFICIENCY PILOT PROGRAM.

The following is Section 1306 of the House-passed Energy Conference Report

• GRANTS.—The Secretary of Energy is authorized to make grants to units of local government, private, non-profit community development organizations, and Indian tribe economic development entities to improve energy efficiency; identify and develop alternative, renewable, and distributed energy supplies; and increase energy conservation in low income rural and urban communities.

• PURPOSE OF GRANTS.—The Secretary may make grants on a competitive basis for—

(1) investments that develop alternative, renewable, and distributed energy supplies;

(2) energy efficiency projects and energy conservation programs;

(3) studies and other activities that improve energy efficiency in low income rural and urban communities;

(4) planning and development assistance for increasing the energy efficiency of buildings and facilities; and

(5) technical and financial assistance to local government and private entities on developing new renewable and distributed sources of power or combined heat and power generation.

• DEFINITION.—For purposes of this section, the term ‘‘Indian tribe'' means any Indian tribe, band, nation, or other organized group or community, including any Alaskan Native village or regional or village corporation as defined in or established pursuant to the Alaska Native Claims Settlement Act (43 U.S.C. 1601 et seq.), that is recognized as eligible for the special programs and services provided by the United States to Indians because of their status as Indians.

AUTHORIZATION OF APPROPRIATIONS.—For the purposes of this section there are authorized to be appropriated to the Secretary of Energy $20,000,000 for each of fiscal years 2004 through 2006.

Legislative Agenda

GENERAL ENERGY POLICY

• PURPA Protection

• Recognition of waste-heat recapture within renewable portfolios

• Clean distributed generation and transmission & distribution system policies

(1) T&D Planning Processes

(2) Realigning T&D Tariffs

• Report on CHP Activities

Utility Regulatory Issues

• Interconnection and Standby Charges

• Natural Gas Delivery Rates

Tax Issues

• 10% Tax Credit for CHP Investments

Environmental Regulatory Issues

• Output-based allocation

Budget and Appropriation Issues

• Office of Electrical Transmission and Distribution

• Electric Transmission and Distribution Programs

• Advanced Power System Technology Program

• Revolving fund for non-profit CHP facilies

• Low income program