Cogeneration Technologies
An EcoGeneration Solutions LLC. Company
E-mail:  info @ cogeneration .net

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Kyoto Protocol
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The Renewable Energy Institute

email:  info@RenewableEnergyInstitute.org

 

We provide Cooler, Cleaner, Greener Power & Energy Solutions  project development services that are Kyoto Protocol compliant and generate clean energy and significantly reduce carbon dioxide emissions. Unlike most companies, we are equipment supplier/vendor neutral. This means we help our clients select the best equipment for their specific application. This approach provides our customers with superior performance, decreased operating expenses and increased return on investment. 

Cogeneration Technologies, located in Houston, Texas, provides project development services that generate clean energy and significantly reduce greenhouse gas emissions and carbon dioxide emissions. Included in this are our turnkey "ecogeneration™" products and services which includes renewable energy technologies, waste to energy, waste to watts™ and waste heat recovery solutions.  Other project development technologies include; Anaerobic Digester, Anaerobic Lagoon, Biogas Recovery, BioMethane, Biomass Gasification, and Landfill Gas To Energy, project development services. 

Unlike most companies, we are equipment supplier/vendor neutral. This means we help our clients select the best equipment for their specific application. This approach provides our customers with superior performance, decreased operating expenses and increased return on investment.

Products and services provided by Cogeneration Technologies includes the following power and energy project development services: 

  • Project Engineering Feasibility & Economic Analysis Studies  

  • Engineering, Procurement and Construction

  • Environmental Engineering & Permitting 

  • Project Funding & Financing Options; including Equity Investment, Debt Financing, Lease and Municipal Lease

  • Shared/Guaranteed Savings Program with No Capital Investment from Qualified Clients 

  • Project Commissioning 

  • 3rd Party Ownership and Project Development

  • Long-term Service Agreements

  • Operations & Maintenance 

  • Green Tag (Renewable Energy Credit, Carbon Dioxide Credits, Emission Reduction Credits) Brokerage Services; Application and Permitting

We are Renewable Energy Technologies specialists and develop clean power and energy projects that will generate a "Renewable Energy Credit," Carbon Dioxide Credits  and Emission Reduction Credits.  Some of our products and services solutions and technologies include; Absorption Chillers, Adsorption Chillers, Automated Demand Response, Biodiesel Refineries, Biofuel Refineries, Biomass Gasification, BioMethane, Canola Biodiesel, Coconut Biodiesel, Cogeneration, Concentrating Solar Power, Demand Response Programs, Demand Side Management, Energy Conservation Measures, Energy Master Planning, Engine Driven Chillers, Solar CHP, Solar Cogeneration, Rapeseed Biodiesel, Solar Electric Heat Pumps, Solar Electric Power Systems, Solar Heating and Cooling, Solar Trigeneration, Soy Biodiesel, and Trigeneration.

Unlike most companies, we are equipment supplier/vendor neutral. This means we help our clients select the best equipment for their specific application. This approach provides our customers with superior performance, decreased operating expenses and increased return on investment. 

For more information: call us at: 832-758-0027 

The Kyoto Protocol, Energy Production, and Carbon Dioxide Emissions


For over one hundred years, energy and power production have been generated around the world through the burning of fossil fuels, including;  fuel oil, coal, diesel, and natural gas.  Over the past decade, environmental science and research has discovered and linked global warming, and global climate change to the carbon dioxide emissions from the combustion of fossil fuels.  This has placed an increased need to reduce energy consumption and discover more environmentally friendly fuel sources. 

Co/trigeneration is the simultaneous production of electricity and thermal energy at the same time, with one fuel input and combustion process (such as natural gas) and is an environmentally-friendlier method of generating electricity. Co/trigeneration is much less expensive and costly in terms of both economic and environmental expenses, than traditional forms of power generation.  There are also far fewer carbon and carbon dioxide emissions generated through co/trigeneration.  

Co/trigeneration slashes carbon dioxide emissions by as much 80% and more.

In 1992, managers of the 2.8-million-square-foot McCormick Place Exhibition and Convention Center in Chicago were planning an addition that would double the size of their convention center. To avoid $27 million in capital costs for a new heating and cooling system, the McCormick Place managers selected Trigen Energy Corporation of White Plains, New York to install a new trigeneration system under an energy outsource or energy services agreement. Trigen installed the new trigeneration system that simultaneously provides the McCormick Place Convention Center with heating, cooling, and electricity and achieves an overall efficiency rating of 93%.  Besides the initial savings of not having to spend $27 million for the new system, McCormick Place also saves >$1 million annually in energy and operating expenses. The system produces about half the carbon dioxide emissions of a traditional system, as well as 24,000 tons of carbon dioxide and 59 tons of nitrogen oxides (NOx) each year when compared to a traditional system.  

Coors Brewing Company has a 90 percent efficient trigeneration system at its Golden, Colorado plant, the largest single brewing site in the world. The trigeneration system saves 250,000 tons of carbon dioxide annually, along with 125 tons of NOx and 900 tons of SO2. 

KYOTO PROTOCOL TO THE UNITED NATIONS 
FRAMEWORK CONVENTION ON CLIMATE CHANGE

The Parties to this Protocol,

Being Parties to the United Nations Framework Convention on Climate Change, hereinafter referred to as "the Convention",

In pursuit of the ultimate objective of the Convention as stated in its Article 2,

Recalling the provisions of the Convention,

Being guided by Article 3 of the Convention,

Pursuant to the Berlin Mandate adopted by decision 1/CP.1 of the

Conference of the Parties to the Convention at its first session,

Have agreed as follows:

Article 1

For the purposes of this Protocol, the definitions contained in Article 1 of the Convention shall apply. In addition:

1. "Conference of the Parties" means the Conference of the Parties to the Convention.

2. "Convention" means the United Nations Framework Convention on Climate Change, adopted in New York on 9 May 1992.

3. "Intergovernmental Panel on Climate Change" means the Intergovernmental Panel on Climate Change established in 1988 jointly by the World Meteorological Organization and the United Nations Environment Programme.

4. "Montreal Protocol" means the Montreal Protocol on Substances that Deplete the Ozone Layer, adopted in Montreal on 16 September 1987 and as subsequently adjusted and amended.

5. "Parties present and voting" means Parties present and casting an affirmative or negative vote.

6. "Party" means, unless the context otherwise indicates, a Party to this Protocol.

7. "Party included in Annex I" means a Party included in Annex I to the Convention, as may be amended, or a Party which has made a notification under Article 4, paragraph 2(g), of the Convention.

Article 2

1. Each Party included in Annex I, in achieving its quantified emission limitation and reduction commitments under Article 3, in order to promote sustainable development, shall:

(a) Implement and/or further elaborate policies and measures in accordance with its national circumstances, such as:

(i) Enhancement of energy efficiency in relevant sectors of the national economy;

(ii) Protection and enhancement of sinks and reservoirs of greenhouse gases not controlled by the Montreal Protocol, taking into account its commitments under relevant international environmental agreements; promotion of sustainable forest management practices, afforestation and reforestation;

(iii) Promotion of sustainable forms of agriculture in light of climate change considerations;

(iv) Research on, and promotion, development and increased use of, new and renewable forms of energy, of carbon dioxide sequestration technologies and of advanced and innovative environmentally sound technologies;

(v) Progressive reduction or phasing out of market imperfections, fiscal incentives, tax and duty exemptions and subsidies in all greenhouse gas emitting sectors that run counter to the objective of the Convention and application of market instruments;

(vi) Encouragement of appropriate reforms in relevant sectors aimed at promoting policies and measures which limit or reduce emissions of greenhouse gases not controlled by the Montreal Protocol;

(vii) Measures to limit and/or reduce emissions of greenhouse gases not controlled by the Montreal Protocol in the transport sector;

(viii) Limitation and/or reduction of methane emissions through recovery and use in waste management, as well as in the production, transport and distribution of energy;

(b) Cooperate with other such Parties to enhance the individual and combined effectiveness of their policies and measures adopted under this Article, pursuant to Article 4, paragraph 2(e)(i), of the Convention. To this end, these Parties shall take steps to share their experience and exchange information on such policies and measures, including developing ways of improving their comparability, transparency and effectiveness. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall, at its first session or as soon as practicable thereafter, consider ways to facilitate such cooperation, taking into account all relevant information.

2. The Parties included in Annex I shall pursue limitation or reduction of emissions of greenhouse gases not controlled by the Montreal Protocol from aviation and marine bunker fuels, working through the International Civil Aviation Organization and the International Maritime Organization, respectively.

3. The Parties included in Annex I shall strive to implement policies and measures under this Article in such a way as to minimize adverse effects, including the adverse effects of climate change, effects on international trade, and social, environmental and economic impacts on other Parties, especially developing country Parties and in particular those identified in Article 4, paragraphs 8 and 9, of the Convention, taking into account Article 3 of the Convention. The Conference of the Parties serving as the meeting of the Parties to this Protocol may take further action, as appropriate, to promote the implementation of the provisions of this paragraph.

4. The Conference of the Parties serving as the meeting of the Parties to this Protocol, if it decides that it would be beneficial to coordinate any of the policies and measures in paragraph 1(a) above, taking into account different national circumstances and potential effects, shall consider ways and means to elaborate the coordination of such policies and measures.

Article 3

1. The Parties included in Annex I shall, individually or jointly, ensure that their aggregate anthropogenic carbon dioxide equivalent emissions of the greenhouse gases listed in Annex A do not exceed their assigned amounts, calculated pursuant to their quantified emission limitation and reduction commitments inscribed in Annex B and in accordance with the provisions of this Article, with a view to reducing their overall emissions of such gases by at least 5 per cent below 1990 levels in the commitment period 2008 to 2012.

2. Each Party included in Annex I shall, by 2005, have made demonstrable progress in achieving its commitments under this Protocol.

3. The net changes in greenhouse gas emissions by sources and removals by sinks resulting from direct human-induced land-use change and forestry activities, limited to afforestation, reforestation and deforestation since 1990, measured as verifiable changes in carbon stocks in each commitment period, shall be used to meet the commitments under this Article of each Party included in Annex I. The greenhouse gas emissions by sources and removals by sinks associated with those activities shall be reported in a transparent and verifiable manner and reviewed in accordance with Articles 7 and 8.

4. Prior to the first session of the Conference of the Parties serving as the meeting of the Parties to this Protocol, each Party included in Annex I shall provide, for consideration by the Subsidiary Body for Scientific and Technological Advice, data to establish its level of carbon stocks in 1990 and to enable an estimate to be made of its changes in carbon stocks in subsequent years. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall, at its first session or as soon as practicable thereafter, decide upon modalities, rules and guidelines as to how, and which, additional human-induced activities related to changes in greenhouse gas emissions by sources and removals by sinks in the agricultural soils and the land-use change and forestry categories shall be added to, or subtracted from, the assigned amounts for Parties included in Annex I, taking into account uncertainties, transparency in reporting, verifiability, the methodological work of the Intergovernmental Panel on Climate Change, the advice provided by the Subsidiary Body for Scientific and Technological Advice in accordance with Article 5 and the decisions of the Conference of the Parties. Such a decision shall apply in the second and subsequent commitment periods. A Party may choose to apply such a decision on these additional human-induced activities for its first commitment period, provided that these activities have taken place since 1990.

5. The Parties included in Annex I undergoing the process of transition to a market economy whose base year or period was established pursuant to decision 9/CP.2 of the Conference of the Parties at its second session shall use that base year or period for the implementation of their commitments under this Article. Any other Party included in Annex I undergoing the process of transition to a market economy which has not yet submitted its first national communication under Article 12 of the Convention may also notify the Conference of the Parties serving as the meeting of the Parties to this Protocol that it intends to use an historical base year or period other than 1990 for the implementation of its commitments under this Article. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall decide on the acceptance of such notification.

6. Taking into account Article 4, paragraph 6, of the Convention, in the implementation of their commitments under this Protocol other than those under this Article, a certain degree of flexibility shall be allowed by the Conference of the Parties serving as the meeting of the Parties to this Protocol to the Parties included in Annex I undergoing the process of transition to a market economy.

7. In the first quantified emission limitation and reduction commitment period, from 2008 to 2012, the assigned amount for each Party included in Annex I shall be equal to the percentage inscribed for it in Annex B of its aggregate anthropogenic carbon dioxide equivalent emissions of the greenhouse gases listed in Annex A in 1990, or the base year or period determined in accordance with paragraph 5 above, multiplied by five. Those Parties included in Annex I for whom land-use change and forestry constituted a net source of greenhouse gas emissions in 1990 shall include in their 1990 emissions base year or period the aggregate anthropogenic carbon dioxide equivalent emissions by sources minus removals by sinks in 1990 from land-use change for the purposes of calculating their assigned amount.

8. Any Party included in Annex I may use 1995 as its base year for hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride, for the purposes of the calculation referred to in paragraph 7 above.

9. Commitments for subsequent periods for Parties included in Annex I shall be established in amendments to Annex B to this Protocol, which shall be adopted in accordance with the provisions of Article 21, paragraph 7. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall initiate the consideration of such commitments at least seven years before the end of the first commitment period referred to in paragraph 1 above.

10. Any emission reduction units, or any part of an assigned amount, which a Party acquires from another Party in accordance with the provisions of Article 6 or of Article 17 shall be added to the assigned amount for the acquiring Party.

11. Any emission reduction units, or any part of an assigned amount, which a Party transfers to another Party in accordance with the provisions of Article 6 or of Article 17 shall be subtracted from the assigned amount for the transferring Party.

12. Any certified emission reductions which a Party acquires from another Party in accordance with the provisions of Article 12 shall be added to the assigned amount for the acquiring Party.

13. If the emissions of a Party included in Annex I in a commitment period are less than its assigned amount under this Article, this difference shall, on request of that Party, be added to the assigned amount for that Party for subsequent commitment periods.

14. Each Party included in Annex I shall strive to implement the commitments mentioned in paragraph 1 above in such a way as to minimize adverse social, environmental and economic impacts on developing country Parties, particularly those identified in Article 4, paragraphs 8 and 9, of the Convention. In line with relevant decisions of the Conference of the Parties on the implementation of those paragraphs, the Conference of the Parties serving as the meeting of the Parties to this Protocol shall, at its first session, consider what actions are necessary to minimize the adverse effects of climate change and/or the impacts of response measures on Parties referred to in those paragraphs. Among the issues to be considered shall be the establishment of funding, insurance and transfer of technology.

Article 4

1. Any Parties included in Annex I that have reached an agreement to fulfil their commitments under Article 3 jointly, shall be deemed to have met those commitments provided that their total combined aggregate anthropogenic carbon dioxide equivalent emissions of the greenhouse gases listed in Annex A do not exceed their assigned amounts calculated pursuant to their quantified emission limitation and reduction commitments inscribed in Annex B and in accordance with the provisions of Article 3. The respective emission level allocated to each of the Parties to the agreement shall be set out in that agreement.

2. The Parties to any such agreement shall notify the secretariat of the terms of the agreement on the date of deposit of their instruments of ratification, acceptance or approval of this Protocol, or accession thereto. The secretariat shall in turn inform the Parties and signatories to the Convention of the terms of the agreement.

3. Any such agreement shall remain in operation for the duration of the commitment period specified in Article 3, paragraph 7.

4. If Parties acting jointly do so in the framework of, and together with, a regional economic integration organization, any alteration in the composition of the organization after adoption of this Protocol shall not affect existing commitments under this Protocol. Any alteration in the composition of the organization shall only apply for the purposes of those commitments under Article 3 that are adopted subsequent to that alteration.

5. In the event of failure by the Parties to such an agreement to achieve their total combined level of emission reductions, each Party to that agreement shall be responsible for its own level of emissions set out in the agreement.

6. If Parties acting jointly do so in the framework of, and together with, a regional economic integration organization which is itself a Party to this Protocol, each member State of that regional economic integration organization individually, and together with the regional economic integration organization acting in accordance with Article 24, shall, in the event of failure to achieve the total combined level of emission reductions, be responsible for its level of emissions as notified in accordance with this Article.

Article 5

1. Each Party included in Annex I shall have in place, no later than one year prior to the start of the first commitment period, a national system for the estimation of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by the Montreal Protocol. Guidelines for such national systems, which shall incorporate the methodologies specified in paragraph 2 below, shall be decided upon by the Conference of the Parties serving as the meeting of the Parties to this Protocol at its first session.

2. Methodologies for estimating anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by the Montreal Protocol shall be those accepted by the Intergovernmental Panel on Climate Change and agreed upon by the Conference of the Parties at its third session. Where such methodologies are not used, appropriate adjustments shall be applied according to methodologies agreed upon by the Conference of the Parties serving as the meeting of the Parties to this Protocol at its first session. Based on the work of, inter alia, the Intergovernmental Panel on Climate Change and advice provided by the Subsidiary Body for Scientific and Technological Advice, the Conference of the Parties serving as the meeting of the Parties to this Protocol shall regularly review and, as appropriate, revise such methodologies and adjustments, taking fully into account any relevant decisions by the Conference of the Parties. Any revision to methodologies or adjustments shall be used only for the purposes of ascertaining compliance with commitments under Article 3 in respect of any commitment period adopted subsequent to that revision.

3. The global warming potentials used to calculate the carbon dioxide equivalence of anthropogenic emissions by sources and removals by sinks of greenhouse gases listed in Annex A shall be those accepted by the Intergovernmental Panel on Climate Change and agreed upon by the Conference of the Parties at its third session. Based on the work of, inter alia, the Intergovernmental Panel on Climate Change and advice provided by the Subsidiary Body for Scientific and Technological Advice, the Conference of the Parties serving as the meeting of the Parties to this Protocol shall regularly review and, as appropriate, revise the global warming potential of each such greenhouse gas, taking fully into account any relevant decisions by the Conference of the Parties. Any revision to a global warming potential shall apply only to commitments under Article 3 in respect of any commitment period adopted subsequent to that revision.


Article 6

1. For the purpose of meeting its commitments under Article 3, any Party included in Annex I may transfer to, or acquire from, any other such Party emission reduction units resulting from projects aimed at reducing anthropogenic emissions by sources or enhancing anthropogenic removals by sinks of greenhouse gases in any sector of the economy, provided that:

(a) Any such project has the approval of the Parties involved;

(b) Any such project provides a reduction in emissions by sources, or an enhancement of removals by sinks, that is additional to any that would otherwise occur;

(c) It does not acquire any emission reduction units if it is not in compliance with its obligations under Articles 5 and 7; and

(d) The acquisition of emission reduction units shall be supplemental to domestic actions for the purposes of meeting commitments under Article 3.

2. The Conference of the Parties serving as the meeting of the Parties to this Protocol may, at its first session or as soon as practicable thereafter, further elaborate guidelines for the implementation of this Article, including for verification and reporting.

3. A Party included in Annex I may authorize legal entities to participate, under its responsibility, in actions leading to the generation, transfer or acquisition under this Article of emission reduction units.

4. If a question of implementation by a Party included in Annex I of the requirements referred to in this Article is identified in accordance with the relevant provisions of Article 8, transfers and acquisitions of emission reduction units may continue to be made after the question has been identified, provided that any such units may not be used by a Party to meet its commitments under Article 3 until any issue of compliance is resolved.


Article 7

1. Each Party included in Annex I shall incorporate in its annual inventory of anthropogenic emissions by sources and removals by sinks of greenhouse gases not controlled by the Montreal Protocol, submitted in accordance with the relevant decisions of the Conference of the Parties, the necessary supplementary information for the purposes of ensuring compliance with Article 3, to be determined in accordance with paragraph 4 below.

2. Each Party included in Annex I shall incorporate in its national communication, submitted under Article 12 of the Convention, the supplementary information necessary to demonstrate compliance with its commitments under this Protocol, to be determined in accordance with paragraph 4 below.

3. Each Party included in Annex I shall submit the information required under paragraph 1 above annually, beginning with the first inventory due under the Convention for the first year of the commitment period after this Protocol has entered into force for that Party. Each such Party shall submit the information required under paragraph 2 above as part of the first national communication due under the Convention after this Protocol has entered into force for it and after the adoption of guidelines as provided for in paragraph 4 below. The frequency of subsequent submission of information required under this Article shall be determined by the Conference of the Parties serving as the meeting of the Parties to this Protocol, taking into account any timetable for the submission of national communications decided upon by the Conference of the Parties.

4. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall adopt at its first session, and review periodically thereafter, guidelines for the preparation of the information required under this Article, taking into account guidelines for the preparation of national communications by Parties included in Annex I adopted by the Conference of the Parties. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall also, prior to the first commitment period, decide upon modalities for the accounting of assigned amounts.


Article 8

1. The information submitted under Article 7 by each Party included in Annex I shall be reviewed by expert review teams pursuant to the relevant decisions of the Conference of the Parties and in accordance with guidelines adopted for this purpose by the Conference of the Parties serving as the meeting of the Parties to this Protocol under paragraph 4 below. The information submitted under Article 7, paragraph 1, by each Party included in Annex I shall be reviewed as part of the annual compilation and accounting of emissions inventories and assigned amounts. Additionally, the information submitted under Article 7, paragraph 2, by each Party included in Annex I shall be reviewed as part of the review of communications.

2. Expert review teams shall be coordinated by the secretariat and shall be composed of experts selected from those nominated by Parties to the Convention and, as appropriate, by intergovernmental organizations, in accordance with guidance provided for this purpose by the Conference of the Parties.

3. The review process shall provide a thorough and comprehensive technical assessment of all aspects of the implementation by a Party of this Protocol. The expert review teams shall prepare a report to the Conference of the Parties serving as the meeting of the Parties to this Protocol, assessing the implementation of the commitments of the Party and identifying any potential problems in, and factors influencing, the fulfilment of commitments. Such reports shall be circulated by the secretariat to all Parties to the Convention. The secretariat shall list those questions of implementation indicated in such reports for further consideration by the Conference of the Parties serving as the meeting of the Parties to this Protocol.

4. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall adopt at its first session, and review periodically thereafter, guidelines for the review of implementation of this Protocol by expert review teams taking into account the relevant decisions of the Conference of the Parties.

5. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall, with the assistance of the Subsidiary Body for Implementation and, as appropriate, the Subsidiary Body for Scientific and Technological Advice, consider:

(a) The information submitted by Parties under Article 7 and the reports of the expert reviews thereon conducted under this Article; and

(b) Those questions of implementation listed by the secretariat under paragraph 3 above, as well as any questions raised by Parties.

6. Pursuant to its consideration of the information referred to in paragraph 5 above, the Conference of the Parties serving as the meeting of the Parties to this Protocol shall take decisions on any matter required for the implementation of this Protocol.


Article 9

1. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall periodically review this Protocol in the light of the best available scientific information and assessments on climate change and its impacts, as well as relevant technical, social and economic information. Such reviews shall be coordinated with pertinent reviews under the Convention, in particular those required by Article 4, paragraph 2(d), and Article 7, paragraph 2(a), of the Convention. Based on these reviews, the Conference of the Parties serving as the meeting of the Parties to this Protocol shall take appropriate action.

2. The first review shall take place at the second session of the Conference of the Parties serving as the meeting of the Parties to this Protocol. Further reviews shall take place at regular intervals and in a timely manner.

Article 10

All Parties, taking into account their common but differentiated responsibilities and their specific national and regional development priorities, objectives and circumstances, without introducing any new commitments for Parties not included in Annex I, but reaffirming existing commitments under Article 4, paragraph 1, of the Convention, and continuing to advance the implementation of these commitments in order to achieve sustainable development, taking into account Article 4, paragraphs 3, 5 and 7, of the Convention, shall:

(a) Formulate, where relevant and to the extent possible, cost-effective national and, where appropriate, regional programmes to improve the quality of local emission factors, activity data and/or models which reflect the socio-economic conditions of each Party for the preparation and periodic updating of national inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by the Montreal Protocol, using comparable methodologies to be agreed upon by the Conference of the Parties, and consistent with the guidelines for the preparation of national communications adopted by the Conference of the Parties;

(b) Formulate, implement, publish and regularly update national and, where appropriate, regional programmes containing measures to mitigate climate change and measures to facilitate adequate adaptation to climate change:

(i) Such programmes would, inter alia, concern the energy, transport and industry sectors as well as agriculture, forestry and waste management. Furthermore, adaptation technologies and methods for improving spatial planning would improve adaptation to climate change; and

(ii) Parties included in Annex I shall submit information on action under this Protocol, including national programmes, in accordance with Article 7; and other Parties shall seek to include in their national communications, as appropriate, information on programmes which contain measures that the Party believes contribute to addressing climate change and its adverse impacts, including the abatement of increases in greenhouse gas emissions, and enhancement of and removals by sinks, capacity building and adaptation measures;

(c) Cooperate in the promotion of effective modalities for the development, application and diffusion of, and take all practicable steps to promote, facilitate and finance, as appropriate, the transfer of, or access to, environmentally sound technologies, know-how, practices and processes pertinent to climate change, in particular to developing countries, including the formulation of policies and programmes for the effective transfer of environmentally sound technologies that are publicly owned or in the public domain and the creation of an enabling environment for the private sector, to promote and enhance the transfer of, and access to, environmentally sound technologies;

(d) Cooperate in scientific and technical research and promote the maintenance and the development of systematic observation systems and development of data archives to reduce uncertainties related to the climate system, the adverse impacts of climate change and the economic and social consequences of various response strategies, and promote the development and strengthening of endogenous capacities and capabilities to participate in international and intergovernmental efforts, programmes and networks on research and systematic observation, taking into account Article 5 of the Convention;

(e) Cooperate in and promote at the international level, and, where appropriate, using existing bodies, the development and implementation of education and training programmes, including the strengthening of national capacity building, in particular human and institutional capacities and the exchange or secondment of personnel to train experts in this field, in particular for developing countries, and facilitate at the national level public awareness of, and public access to information on, climate change. Suitable modalities should be developed to implement these activities through the relevant bodies of the Convention, taking into account Article 6 of the Convention;

(f) Include in their national communications information on programmes and activities undertaken pursuant to this Article in accordance with relevant decisions of the Conference of the Parties; and

(g) Give full consideration, in implementing the commitments under this Article, to Article 4, paragraph 8, of the Convention.

Article 11

1. In the implementation of Article 10, Parties shall take into account the provisions of Article 4, paragraphs 4, 5, 7, 8 and 9, of the Convention.

2. In the context of the implementation of Article 4, paragraph 1, of the Convention, in accordance with the provisions of Article 4, paragraph 3, and Article 11 of the Convention, and through the entity or entities entrusted with the operation of the financial mechanism of the Convention, the developed country Parties and other developed Parties included in Annex II to the Convention shall:

(a) Provide new and additional financial resources to meet the agreed full costs incurred by developing country Parties in advancing the implementation of existing commitments under Article 4, paragraph 1(a), of the Convention that are covered in Article 10, subparagraph (a); and

(b) Also provide such financial resources, including for the transfer of technology, needed by the developing country Parties to meet the agreed full incremental costs of advancing the implementation of existing commitments under Article 4, paragraph 1, of the Convention that are covered by Article 10 and that are agreed between a developing country Party and the international entity or entities referred to in Article 11 of the Convention, in accordance with that Article.

The implementation of these existing commitments shall take into account the need for adequacy and predictability in the flow of funds and the importance of appropriate burden sharing among developed country Parties. The guidance to the entity or entities entrusted with the operation of the financial mechanism of the Convention in relevant decisions of the Conference of the Parties, including those agreed before the adoption of this Protocol, shall apply mutatis mutandis to the provisions of this paragraph.

3. The developed country Parties and other developed Parties in Annex II to the Convention may also provide, and developing country Parties avail themselves of, financial resources for the implementation of Article 10, through bilateral, regional and other multilateral channels.

Article 12

1. A clean development mechanism is hereby defined.

2. The purpose of the clean development mechanism shall be to assist Parties not included in Annex I in achieving sustainable development and in contributing to the ultimate objective of the Convention, and to assist Parties included in Annex I in achieving compliance with their quantified emission limitation and reduction commitments under Article 3.

3. Under the clean development mechanism:

(a) Parties not included in Annex I will benefit from project activities resulting in certified emission reductions; and

(b) Parties included in Annex I may use the certified emission reductions accruing from such project activities to contribute to compliance with part of their quantified emission limitation and reduction commitments under Article 3, as determined by the Conference of the Parties serving as the meeting of the Parties to this Protocol.

4. The clean development mechanism shall be subject to the authority and guidance of the Conference of the Parties serving as the meeting of the Parties to this Protocol and be supervised by an executive board of the clean development mechanism.

5. Emission reductions resulting from each project activity shall be certified by operational entities to be designated by the Conference of the Parties serving as the meeting of the Parties to this Protocol, on the basis of:

(a) Voluntary participation approved by each Party involved;

(b) Real, measurable, and long-term benefits related to the mitigation of climate change; and

(c) Reductions in emissions that are additional to any that would occur in the absence of the certified project activity.

6. The clean development mechanism shall assist in arranging funding of certified project activities as necessary.

7. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall, at its first session, elaborate modalities and procedures with the objective of ensuring transparency, efficiency and accountability through independent auditing and verification of project activities.

8. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall ensure that a share of the proceeds from certified project activities is used to cover administrative expenses as well as to assist developing country Parties that are particularly vulnerable to the adverse effects of climate change to meet the costs of adaptation.

9. Participation under the clean development mechanism, including in activities mentioned in paragraph 3(a) above and in the acquisition of certified emission reductions, may involve private and/or public entities, and is to be subject to whatever guidance may be provided by the executive board of the clean development mechanism.

10. Certified emission reductions obtained during the period from the year 2000 up to the beginning of the first commitment period can be used to assist in achieving compliance in the first commitment period.

Article 13

1. The Conference of the Parties, the supreme body of the Convention, shall serve as the meeting of the Parties to this Protocol.

2. Parties to the Convention that are not Parties to this Protocol may participate as observers in the proceedings of any session of the Conference of the Parties serving as the meeting of the Parties to this Protocol. When the Conference of the Parties serves as the meeting of the Parties to this Protocol, decisions under this Protocol shall be taken only by those that are Parties to this Protocol.

3. When the Conference of the Parties serves as the meeting of the Parties to this Protocol, any member of the Bureau of the Conference of the Parties representing a Party to the Convention but, at that time, not a Party to this Protocol, shall be replaced by an additional member to be elected by and from amongst the Parties to this Protocol.

4. The Conference of the Parties serving as the meeting of the Parties to this Protocol shall keep under regular review the implementation of this Protocol and shall make, within its mandate, the decisions necessary to promote its effective implementation. It shall perform the functions assigned to it by this Protocol and shall:

(a) Assess, on the basis of all information made available to it in accordance with the provisions of this Protocol, the implementation of this Protocol by the Parties, the overall effects of the measures taken pursuant to this Protocol, in particular environmental, economic and social effects as well as their cumulative impacts and the extent to which progress towards the objective of the Convention is being achieved;

(b) Periodically examine the obligations of the Parties under this Protocol, giving due consideration to any reviews required by Article 4, paragraph 2(d), and Article 7, paragraph 2, of the Convention, in the light of the objective of the Convention, the experience gained in its implementation and the evolution of scientific and technological knowledge, and in this respect consider and adopt regular reports on the implementation of this Protocol;

(c) Promote and facilitate the exchange of information on measures adopted by the Parties to address climate change and its effects, taking into account the differing circumstances, responsibilities and capabilities of the Parties and their respective commitments under this Protocol;

(d) Facilitate, at the request of two or more Parties, the coordination of measures adopted by them to address climate change and its effects, taking into account the differing circumstances, responsibilities and capabilities of the Parties and their respective commitments under this Protocol;

(e) Promote and guide, in accordance with the objective of the Convention and the provisions of this Protocol, and taking fully into account the relevant decisions by the Conference of the Parties, the development and periodic refinement of comparable methodologies for the effective implementation of this Protocol, to be agreed on by the Conference of the Parties serving as the meeting of the Parties to this Protocol;

(f) Make recommendations on any matters necessary for the implementation of this Protocol;

(g) Seek to mobilize additional financial resources in accordance with

Article 11, paragraph 2;

(h) Establish such subsidiary bodies as are deemed necessary for the implementation of this Protocol;

(i) Seek and utilize, where appropriate, the services and cooperation of, and information provided by, competent international organizations and intergovernmental and non-governmental bodies; and

(j) Exercise such other functions as may be required for the implementation of this Protocol, and consider any assignment resulting from a decision by the Conference of the Parties.

5. The rules of procedure of the Conference of the Parties and financial procedures applied under the Convention shall be applied mutatis mutandis under this Protocol, except as may be otherwise decided by consensus by the Conference of the Parties serving as the meeting of the Parties to this Protocol.

6. The first session of the Conference of the Parties serving as the meeting of the Parties to this Protocol shall be convened by the secretariat in conjunction with the first session of the Conference of the Parties that is scheduled after the date of the entry into force of this Protocol. Subsequent ordinary sessions of the Conference of the Parties serving as the meeting of the Parties to this Protocol shall be held every year and in conjunction with ordinary sessions of the Conference of the Parties, unless otherwise decided by the Conference of the Parties serving as the meeting of the Parties to this Protocol.

7. Extraordinary sessions of the Conference of the Parties serving as the meeting of the Parties to this Protocol shall be held at such other times as may be deemed necessary by the Conference of the Parties serving as the meeting of the Parties to this Protocol, or at the written request of any Party, provided that, within six months of the request being communicated to the Parties by the secretariat, it is supported by at least one third of the Parties.

8. The United Nations, its specialized agencies and the International Atomic Energy

Agency, as well as any State member thereof or observers thereto not party to the Convention, may be represented at sessions of the Conference of the Parties serving as the meeting of the Parties to this Protocol as observers. Any body or agency, whether national or international, governmental or non-governmental, which is qualified in matters covered by this Protocol and which has informed the secretariat of its wish to be represented at a session of the Conference of the Parties serving as the meeting of the Parties to this Protocol as an observer, may be so admitted unless at least one third of the Parties present object. The admission and participation of observers shall be subject to the rules of procedure, as referred to in paragraph 5 above.

Article 14

1. The secretariat established by Article 8 of the Convention shall serve as the secretariat of this Protocol.

2. Article 8, paragraph 2, of the Convention on the functions of the secretariat, and

Article 8, paragraph 3, of the Convention on arrangements made for the functioning of the secretariat, shall apply mutatis mutandis to this Protocol. The secretariat shall, in addition, exercise the functions assigned to it under this Protocol.

Article 15

1. The Subsidiary Body for Scientific and Technological Advice and the Subsidiary Body for Implementation established by Articles 9 and 10 of the Convention shall serve as, respectively, the Subsidiary Body for Scientific and Technological Advice and the Subsidiary Body for Implementation of this Protocol. The provisions relating to the functioning of these two bodies under the Convention shall apply mutatis mutandis to this Protocol. Sessions of the meetings of the Subsidiary Body for Scientific and Technological Advice and the Subsidiary Body for Implementation of this Protocol shall be held in conjunction with the meetings of, respectively, the Subsidiary Body for Scientific and Technological Advice and the Subsidiary Body for Implementation of the Convention.

2. Parties to the Convention that are not Parties to this Protocol may participate as observers in the proceedings of any session of the subsidiary bodies. When the subsidiary bodies serve as the subsidiary bodies of this Protocol, decisions under this Protocol shall be taken only by those that are Parties to this Protocol.

3. When the subsidiary bodies established by Articles 9 and 10 of the Convention exercise their functions with regard to matters concerning this Protocol, any member of the Bureaux of those subsidiary bodies representing a Party to the Convention but, at that time, not a party to this Protocol, shall be replaced by an additional member to be elected by and from amongst the Parties to this Protocol.

Article 16

The Conference of the Parties serving as the meeting of the Parties to this Protocol shall, as soon as practicable, consider the application to this Protocol of, and modify as appropriate, the multilateral consultative process referred to in Article 13 of the Convention, in the light of any relevant decisions that may be taken by the Conference of the Parties. Any multilateral consultative process that may be applied to this Protocol shall operate without prejudice to the procedures and mechanisms established in accordance with Article 18.

Article 17

The Conference of the Parties shall define the relevant principles, modalities, rules and guidelines, in particular for verification, reporting and accountability for emissions trading. The Parties included in Annex B may participate in emissions trading for the purposes of fulfilling their commitments under Article 3. Any such trading shall be supplemental to domestic actions for the purpose of meeting quantified emission limitation and reduction commitments under that Article.

Article 18

The Conference of the Parties serving as the meeting of the Parties to this Protocol shall, at its first session, approve appropriate and effective procedures and mechanisms to determine and to address cases of non-compliance with the provisions of this Protocol, including through the development of an indicative list of consequences, taking into account the cause, type, degree and frequency of non-compliance. Any procedures and mechanisms under this Article entailing binding consequences shall be adopted by means of an amendment to this Protocol.

Article 19

The provisions of Article 14 of the Convention on settlement of disputes shall apply mutatis mutandis to this Protocol.

Article 20

1. Any Party may propose amendments to this Protocol.

2. Amendments to this Protocol shall be adopted at an ordinary session of the Conference of the Parties serving as the meeting of the Parties to this Protocol. The text of any proposed amendment to this Protocol shall be communicated to the Parties by the secretariat at least six months before the meeting at which it is proposed for adoption. The secretariat shall also communicate the text of any proposed amendments to the Parties and signatories to the Convention and, for information, to the Depositary.

3. The Parties shall make every effort to reach agreement on any proposed amendment to this Protocol by consensus. If all efforts at consensus have been exhausted, and no agreement reached, the amendment shall as a last resort be adopted by a three-fourths majority vote of the Parties present and voting at the meeting. The adopted amendment shall be communicated by the secretariat to the Depositary, who shall circulate it to all Parties for their acceptance.

4. Instruments of acceptance in respect of an amendment shall be deposited with the Depositary. An amendment adopted in accordance with paragraph 3 above shall enter into force for those Parties having accepted it on the ninetieth day after the date of receipt by the Depositary of an instrument of acceptance by at least three fourths of the Parties to this Protocol.

5. The amendment shall enter into force for any other Party on the ninetieth day after the date on which that Party deposits with the Depositary its instrument of acceptance of the said amendment.

Article 21

1. Annexes to this Protocol shall form an integral part thereof and, unless otherwise expressly provided, a reference to this Protocol constitutes at the same time a reference to any annexes thereto. Any annexes adopted after the entry into force of this Protocol shall be restricted to lists, forms and any other material of a descriptive nature that is of a scientific, technical, procedural or administrative character.

2. Any Party may make proposals for an annex to this Protocol and may propose amendments to annexes to this Protocol.

3. Annexes to this Protocol and amendments to annexes to this Protocol shall be adopted at an ordinary session of the Conference of the Parties serving as the meeting of the Parties to this Protocol. The text of any proposed annex or amendment to an annex shall be communicated to the Parties by the secretariat at least six months before the meeting at which it is proposed for adoption. The secretariat shall also communicate the text of any proposed annex or amendment to an annex to the Parties and signatories to the Convention and, for information, to the Depositary.

4. The Parties shall make every effort to reach agreement on any proposed annex or amendment to an annex by consensus. If all efforts at consensus have been exhausted, and no agreement reached, the annex or amendment to an annex shall as a last resort be adopted by a three-fourths majority vote of the Parties present and voting at the meeting. The adopted annex or amendment to an annex shall be communicated by the secretariat to the Depositary, who shall circulate it to all Parties for their acceptance.

5. An annex, or amendment to an annex other than Annex A or B, that has been adopted in accordance with paragraphs 3 and 4 above shall enter into force for all Parties to this Protocol six months after the date of the communication by the Depositary to such Parties of the adoption of the annex or adoption of the amendment to the annex, except for those Parties that have notified the Depositary, in writing, within that period of their non-acceptance of the annex or amendment to the annex. The annex or amendment to an annex shall enter into force for Parties which withdraw their notification of non-acceptance on the ninetieth day after the date on which withdrawal of such notification has been received by the Depositary.

6. If the adoption of an annex or an amendment to an annex involves an amendment to this Protocol, that annex or amendment to an annex shall not enter into force until such time as the amendment to this Protocol enters into force.

7. Amendments to Annexes A and B to this Protocol shall be adopted and enter into force in accordance with the procedure set out in Article 20, provided that any amendment to Annex B shall be adopted only with the written consent of the Party concerned.

Article 22

1. Each Party shall have one vote, except as provided for in paragraph 2 below.

2. Regional economic integration organizations, in matters within their competence, shall exercise their right to vote with a number of votes equal to the number of their member States that are Parties to this Protocol. Such an organization shall not exercise its right to vote if any of its member States exercises its right, and vice versa.

Article 23

The Secretary-General of the United Nations shall be the Depositary of this Protocol.

Article 24

1. This Protocol shall be open for signature and subject to ratification, acceptance or approval by States and regional economic integration organizations which are Parties to the Convention. It shall be open for signature at United Nations Headquarters in New York from

16 March 1998 to 15 March 1999. This Protocol shall be open for accession from the day after the date on which it is closed for signature. Instruments of ratification, acceptance, approval or accession shall be deposited with the Depositary.

2. Any regional economic integration organization which becomes a Party to this Protocol without any of its member States being a Party shall be bound by all the obligations under this Protocol. In the case of such organizations, one or more of whose member States is a Party to this Protocol, the organization and its member States shall decide on their respective responsibilities for the performance of their obligations under this Protocol. In such cases, the organization and the member States shall not be entitled to exercise rights under this Protocol concurrently.

3. In their instruments of ratification, acceptance, approval or accession, regional economic integration organizations shall declare the extent of their competence with respect to the matters governed by this Protocol. These organizations shall also inform the Depositary, who shall in turn inform the Parties, of any substantial modification in the extent of their competence.

Article 25

1. This Protocol shall enter into force on the ninetieth day after the date on which not less than 55 Parties to the Convention, incorporating Parties included in Annex I which accounted in total for at least 55 per cent of the total carbon dioxide emissions for 1990 of the Parties included in Annex I, have deposited their instruments of ratification, acceptance, approval or accession.

2. For the purposes of this Article, "the total carbon dioxide emissions for 1990 of the Parties included in Annex I" means the amount communicated on or before the date of adoption of this Protocol by the Parties included in Annex I in their first national communications submitted in accordance with Article 12 of the Convention.

3. For each State or regional economic integration organization that ratifies, accepts or

approves this Protocol or accedes thereto after the conditions set out in paragraph 1 above for entry into force have been fulfilled, this Protocol shall enter into force on the ninetieth day following the date of deposit of its instrument of ratification, acceptance, approval or accession.

4. For the purposes of this Article, any instrument deposited by a regional economic integration organization shall not be counted as additional to those deposited by States members of the organization.

Article 26

No reservations may be made to this Protocol.

Article 27

1. At any time after three years from the date on which this Protocol has entered into force for a Party, that Party may withdraw from this Protocol by giving written notification to the Depositary.

2. Any such withdrawal shall take effect upon expiry of one year from the date of receipt by the Depositary of the notification of withdrawal, or on such later date as may be specified in the notification of withdrawal.

3. Any Party that withdraws from the Convention shall be considered as also having withdrawn from this Protocol.

Article 28

The original of this Protocol, of which the Arabic, Chinese, English, French, Russian and Spanish texts are equally authentic, shall be deposited with the Secretary-General of the United Nations.

DONE at Kyoto this eleventh day of December one thousand nine hundred and ninety-seven.

IN WITNESS WHEREOF the undersigned, being duly authorized to that effect, have affixed their signatures to this Protocol on the dates indicated.

Annex A

Greenhouse gases

Carbon dioxide (CO2)

Methane (CH4)

Nitrous oxide (N2O)

Hydrofluorocarbons (HFCs)

Perfluorocarbons (PFCs)

Sulphur hexafluoride (SF6)

Sectors/source categories

Energy

Fuel combustion

Energy industries

Manufacturing industries and construction

Transport

Other sectors

Other

Fugitive emissions from fuels

Solid fuels

Oil and natural gas

Other

Industrial processes

Mineral products

Chemical industry

Metal production

Other production

Production of halocarbons and sulphur hexafluoride

Consumption of halocarbons and sulphur hexafluoride

Other

Solvent and other product use

Agriculture

Enteric fermentation

Manure management

Rice cultivation

Agricultural soils

Prescribed burning of savannas

Field burning of agricultural residues

Other

Waste

Solid waste disposal on land

Wastewater handling

Waste incineration

Other

Annex B

 

Party Quantified emission limitation or

reduction commitment

(percentage of base year or period)

Australia 108

Austria 92

Belgium 92

Bulgaria* 92

Canada 94

Croatia* 95

Czech Republic* 92

Denmark 92

Estonia* 92

European Community 92

Finland 92

France 92

Germany 92

Greece 92

Hungary* 94

Iceland 110

Ireland 92

Italy 92

Japan 94

Latvia* 92

Liechtenstein 92

Lithuania* 92

Luxembourg 92

Monaco 92

Netherlands 92

New Zealand 100

Norway 101

Poland* 94

Portugal 92

Romania* 92

Russian Federation* 100

Slovakia* 92

Slovenia* 92

Spain 92

Sweden 92

Switzerland 92

Ukraine* 100

United Kingdom of Great Britain and Northern Ireland 92

United States of America 93

* Countries that are undergoing the process of transition to a market economy.


Carbon Dioxide Emissions from the
Generation of Electric Power in
the United States

July 2000



Introduction

The President issued a directive on April 15, 1999, requiring an annual report summarizing the carbon dioxide (CO2) emissions produced by the generation of electricity by utilities and nonutilities in the United States. In response, the U.S. Department of Energy (DOE) and the U.S. Environmental Protection Agency (EPA) jointly submitted the first report on October 15, 1999. This is the second annual report(1) that estimates the CO2 emissions attributable to the generation of electricity in the United States. The data on CO2 emissions and the generation of electricity were collected and prepared by the Energy Information Administration (EIA), and the report was jointly written by DOE and EPA to address the five areas outlined in the Presidential Directive.

  • The emissions of CO2 are presented on the basis of total mass (tons) and output rate (pounds per kilowatthour). The information is stratified by the type of fuel used for electricity generation and presented for both regional and national levels. The percentage of electricity generation produced by each fuel type or energy resource is indicated.

  • The 1999 data on CO2 emissions and generation by fuel type are compared to the same data for the previous year, 1998. Factors contributing to regional and national level changes in the amount and average output rate of CO2 are identified and discussed.

  • The Energy Information Administration's most recent projections of CO2 emissions and generation by fuel type for 1999 are compared to the actual data summarized in this report to identify deviations between projected and actual CO2 emissions and electricity generation.

  • Information for 1998 on voluntary carbon-reducing and carbon-sequestration projects reported by the electric power sector and the resulting amount of CO2 reductions are presented. Included are programs undertaken by the utilities themselves as well as programs supported by the Federal government to support voluntary CO2 reductions.

  • Appropriate updates to the Department of Energy's estimated environmental effects of the Administration's proposed restructuring legislation are included.


Electric Power Industry CO2 Emissions and
Generation Share by Fuel Type

In 1999,(2) estimated emissions of CO2 in the United States resulting from the generation of electric power were 2,245 million metric tons,(3) an increase of 1.4 percent from the 2,215 million metric tons in 1998. The estimated generation of electricity from all sources increased by 2.0 percent, going from 3,617 billion kilowatthours to 3,691 billion kilowatthours. Electricity generation from coal-fired plants, the primary source of CO2 emissions from electricity generation, was nearly the same in 1999 as in 1998. Much of the increase in electricity generation was produced by gas-fired plants and nuclear plants. The 1999 national average output rate,(4) 1.341 pounds of CO2 per kilowatthour generated, also showed a slight change from 1.350 pounds CO2 per kilowatthour in 1998 (Table 1). While the share of total generation provided by fossil fuels rose slightly, a reduction in the emission rate for coal-fired generation combined with growth in the market share of gas-fired generation contributed to the modest improvement in the output rate.(5)

Table 1. Summary of Carbon Dioxide Emissions and Net Generation in the United States, 1998 and 1999

 

1998

1999p

Change

Percent
Change

Carbon Dioxide (thousand metric tons)a

 

 

 

 

  Coal

1,799,762

1,787,910

-11,852

-0.66

  Petroleum

110,244

106,294

-3,950

-3.58

  Gas

291,236

337,004

45,768

15.72

  Other Fuels b

13,596

13,596

-

-

   U.S. Total

2,214,837

2,244,804

29,967

1.35

Generation (million kWh)

 

 

 

 

   Coal

1,873,908

1,881,571

7,663

0.41

   Petroleum

126,900

119,025

-7,875

-6.21

   Gas

488,712

562,433

73,721

15.08

   Other Fuels b

21,747

21,749

2

-

   Total Fossil-fueled

2,511,267  

2,584,779

73,512  

2.93

   Nonfossil-fueled c

1,105,947

1,106,294

347

0.03

   U.S. Total

3,617,214

3,691,073

73,509

2.04

Output Rate d (pounds CO2 per kWh)

 

 

 

 

   Coal

2.117

2.095

-0.022

-1.04

   Petroleum

1.915

1.969

0.054

2.82

   Gas

1.314

1.321

0.007

0.53

   Other Fuels b

1.378

1.378

-

-

U.S. Average

1.350

1.341

-0.009

-0.67

   a One metric ton equals one short ton divided by 1.1023. To convert carbon dioxide to carbon units, divide by 44/12.
   b Other fuels include municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to generate electricity. Nonutility data for 1999 for these fuels are unavailable; 1998 data are used.
   c Nonfossil includes nuclear, hydroelectric, solar, wind, geothermal, biomass, and other fuels or energy sources with zero or net zero CO2 emissions. Although geothermal contributes a small amount of CO2 emissions, in this report it is included in nonfossil.
   dU.S. average output rate is based on generation from all energy sources.
   P= Preliminary data.
   - = No change.
   Note: Data for 1999 are preliminary. Data for 1998 are final.
   Sources: •Energy Information Administration, Form EIA-759, "Monthly Power Plant Report"; Form EIA-767,"Steam-Electric Plant Operation and Design Report"; Form EIA-860B, "Annual Electric Generator Report -Nonutility"; and Form 900, "Monthly Nonutility Power Report." •Federal Energy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."


In the United States, about 40.5 percent(6) of anthropogenic CO2 emissions was attributed to the combustion of fossil fuels for the generation of electricity in 1998, the latest year for which all data are available.(7) The available energy sources used for electricity generation result in varying output rates for CO2 emissions from region to region across the United States. Although all regions use some fossil fuels for electricity generation, several States generate almost all electricity at nuclear or hydroelectric plants, resulting in correspondingly low output rates of CO2 per kilowatthour. For example, Vermont produces mostly nuclear power, while Washington, Idaho, and Oregon generate almost all electricity at hydroelectric plants. At the other extreme, Colorado, Indiana, Iowa, Kentucky, New Mexico, North Dakota, Ohio, West Virginia, and Wyoming--a group that includes some of the Nation's largest coal-producing States--generate most of their electricity with coal. Regions where coal-fired generators dominate the industry show the highest rates of CO2 emissions per kilowatthour.

Coal

Estimated emissions of CO2 produced by coal-fired generation of electricity were 1,788 million metric tons in 1999 (Table 1), 0.7 percent less than in 1998, while electricity generation from coal was 0.4 percent more than the previous year. The divergent direction of generation and emissions changes may reflect a combination of thermal efficiency improvements, changes in average fuel characteristics, and variances associated with both sampling and nonsampling errors. CO2 emissions from coal-fired electricity generation comprise nearly 80 percent of the total CO2 emissions produced by the generation of electricity in the United States, while the share of electricity generation from coal was 51.0 percent in 1999 (Table 3). Coal has the highest carbon intensity among fossil fuels, resulting in coal-fired plants having the highest output rate of CO2 per kilowatthour. The national average output rate for coal-fired electricity generation was 2.095 pounds CO2 per kilowatthour in 1999 (Table 4).

Coal-fired generation contributes over 90 percent of CO2 emissions in the East North Central, West North Central, East South Central, and Mountain Census Divisions and 84 percent in the South Atlantic Census Division (Table 2). Nearly two-thirds of the Nation's CO2 emissions from electricity generation are accounted for by the combustion of coal for electricity generation in these five regions where most of the Nation's coal-producing States are located. Consequently, these regions have relatively high output rates of CO2 per kilowatthour.

Table 2. Estimated Carbon Dioxide Emissions From Generating Units at U.S. Electric Plants by Census Division, 1998 and 1999 (Thousand Metric Tons)

Census Division

1998

1999

Total

Coal

Petroleum

Gas

Othera

Total

Coal

Petroleum

Gas

Othera

New England

50,450

16,470

23,068

7,966

2,945

52,822

14,637

24,224

11,015

2,945

Middle Atlantic

189,023

139,821

17,315

28,441

3,447

190,214

134,528

15,232

37,007

3,447

East North Central

427,580

410,141

4,351

12,039

1,049

423,063

397,266

5,415

19,333

1,049

West North Central

217,123

209,858

1,521

4,726

1,018

219,104

208,786

1,957

7,342

1,018

South Atlantic

445,435

373,780

43,777

24,515

3,363

452,180

378,018

41,356

29,442

3,363

East South Central

226,749

212,350

5,018

9,299

82

228,240

214,486

3,212

10,460

82

West South Central

364,056

214,544

5,461

143,945

106

380,792

221,309

5,744

153,634

106

Mountain

219,147

206,256

888

12,002

*

217,543

202,421

1,278

13,843

*

Pacific Contiguous

64,668

14,555

2,588

46,165

1,360

70,591

14,563

2,153

52,515

1,360

Pacific Noncontiguous

10,606

1,985

6,257

2,138

225

10,256

1,895

5,724

2,413

225

U.S. Total

2,214,837

1,799,762

110,244

291,236

13,596

2,244,804

1,787,910

106,294

337,004

13,596

   aOther fuels include municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to generate electricity. Nonutility data for 1999 for these fuels are unavailable; 1998 data are used.
   * = the absolute value is less than 0.5.
   Note: Data for 1999 are preliminary. Data for 1998 are final.
   Sources: •Energy Information Administration, Form EIA-759, "Monthly Power Plant Report"; Form EIA-767, "Steam-Electric Plant Operation and Design Report"; Form EIA-860B, "Annual Electric Generator Report - Nonutility"; Form EIA-900, "Monthly Nonutility Power Report." •Federal Energy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."



Table 3. Percent of Electricity Generated at U.S. Electric Plants by Fuel Type and Census Division, 1998 and 1999
(Percent)

Census Division

1998

1999

Coal

Petroleum

Gas

Othera

Nonfossil

Coal

Petroleum

Gas

Othera

Nonfossil

New England

17.9

24.4 

13.8

4.6

39.3

16.3

22.9 

18.0

4.6

38.3

Middle Atlantic

38.4

5.2

13.6

1.3

41.5

35.8

4.5

17.5

1.3

40.9

East North Central

76.3

0.8

3.8

0.4

18.8

72.0

0.7

4.4

0.4

22.5

West North Central

75.5

0.7

2.3

0.3

21.1

73.9

0.7

3.0

0.3

22.0

South Atlantic

55.3

7.2

6.6

0.7

30.2

55.5

6.7

7.8

0.7

29.2

East South Central

66.2

2.1

3.2

*

28.4

68.0

1.4

3.9

*

26.7

West South Central

39.1

0.6

42.2

0.3

17.8

40.1

0.7

44.6

0.3

14.3

Mountain

67.9

0.2

6.8

0.1

25.0

67.5

0.3

8.1

0.1

24.1

Pacific Contiguous

4.3

0.7

23.1

0.4

71.4

4.2

0.5

26.2

0.4

68.7

Pacific Noncontiguous

12.2

52.3 

21.3

1.9

12.4

11.7

52.2 

24.8

1.9

 9.4

U.S. Total

51.8

3.5

13.5

0.6

30.6

51.0

3.2

15.2

0.6

30.0

   aOther fuels include municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to generate electricity. Nonutility data for 1999 for these fuels are unavailable; 1998 data are used.
   * = the absolute value is less than 0.05.
   Note: Data for 1999 are preliminary. Data for 1998 are final.
   Sources: •Energy Information Administration, Form EIA-759, "Monthly Power Plant Report"; Form EIA-767, "Steam-Electric Plant Operation and Design Report"; Form EIA-860B, "Annual Electric Generator Report - Nonutility"; Form EIA-900, "Monthly Nonutility Power Report." •Federal Energy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."



Table 4. Estimated Carbon Dioxide Emissions Rate From Generating Units at U.S. Electric Plants by Census Division, 1998 and 1999 (Pounds per Kilowatthour)

Census Division

1998

1999

Total

Coal

Petroleum

Gas

Othera

Total

Coal

Petroleum

Gas

Othera

New England

1.059

1.934

1.984

1.213

1.339

1.077

1.827

2.156

1.250

1.328

Middle Atlantic

1.071

2.062

1.884

1.188

1.502

1.058

2.089

1.872

1.178

1.502

East North Central

1.680

2.113

2.244

1.239

1.124

1.579

2.061

2.759

1.630

1.131

West North Central

1.767

2.262

1.759

1.659

2.422

1.746

2.250

2.207

1.958

2.596

South Atlantic

1.334

2.026

1.821

1.113

1.377

1.342

2.019

1.822

1.115

1.372

East South Central

1.457

2.060

1.515

1.857

3.244

1.470

2.031

1.530

1.734

3.244

West South Central

1.469

2.214

3.955

1.376

0.151

1.529

2.215

3.170

1.382

0.151

Mountain

1.572

2.179

2.802

1.257

0.005

1.542

2.128

3.036

1.214

0.005

Pacific Contiguous

0.417

2.158

2.396

1.287

2.140

0.435

2.152

2.419

1.238

2.108

Pacific Noncontiguous

1.453

2.229

1.641

1.375

1.661

1.393

2.209

1.488

1.319

1.661

U.S. Average

1.350

2.117

1.915

1.314

1.378

1.341

2.095

1.969

1.321

1.378

   aOther fuels include municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to generate electricity. Nonutility data for 1999 for these fuels are unavailable; 1998 data are used.
   Note: Data for 1999 are preliminary. Data for 1998 are final.
   Sources: •Energy Information Administration, Form EIA-759, "Monthly Power Plant Report"; Form EIA-767, "Steam-Electric Plant Operation and Design Report"; Form EIA-860B, "Annual Electric Generator Report - Nonutility"; Form EIA-900, "Monthly Nonutility Power Report." •Federal Energy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."


Figure 1. Census Regions and Divisions

Petroleum

CO2 emissions from petroleum-fired electricity generation were 106 million metric tons in 1999, 3.6 percent less than in 1998. Generation of electricity from petroleum-fired plants decreased from 127 billion kilowatthours in 1998 to 119 billion kilowatthours in 1999. CO2 emissions from petroleum-fired electricity generation accounted for 4.7 percent of the national total, while generation from petroleum plants was 3.2 percent of the Nation's total electricity generation. The national average output rate for all petroleum-fired generation was 1.969 pounds CO2 per kilowatthour in 1999.

The New England Census Division generates about one-fourth of its electricity at petroleum-fired plants which produce approximately 45 percent of that region's CO2 emissions. The Pacific Noncontiguous Census Division generates about one-half of its electricity at petroleum-fired plants, producing about one-half of the region's CO2 emissions. The South Atlantic and Middle Atlantic Census Divisions also use some petroleum for electricity generation, particularly in Florida. The South Atlantic Census Division contributes the largest share of CO2 emissions from petroleum-fired plants, 1.8 percent of the Nation's total CO2 emissions from all sources.

Natural Gas

Emissions of CO2 from the generation of electricity at natural gas-fired plants were 337 million metric tons in 1999. Natural gas-fired plants were the only fossil-fueled plants to substantially increase generation from 1998 to 1999. Generation increased an estimated 15.0 percent, with CO2 emissions increasing a corresponding 15.7 percent. Emissions of CO2 from natural gas-fired plants represented 15.0 percent of total CO2 emissions from electricity generation in 1999, while natural gas-fired electricity generation accounted for 15.2 percent of total generation. The output rate for CO2 from natural gas-fired plants in 1999 was 1.321 pounds CO2 per kilowatthour. Natural gas is the least carbon-intensive fossil fuel.

The West South Central Census Division, which includes Texas, Oklahoma, and Louisiana, is where much of the Nation's natural gas-fired capacity is located. The Northeast and Pacific Contiguous Census Divisions also use natural gas to generate a substantial portion of their electricity. About 40.4 percent of the West South Central Division's CO2 emissions from the generation of electricity comes from gas-fired plants, representing approximately 45.6 percent of all CO2 emissions from natural gas combustion for electricity generation in the Nation. About three-fourths of the Pacific Contiguous Census Division's CO2 emissions are from natural gas-fired plants; however, most of that division's electricity generation is produced at nonfossil-fueled plants, such as hydroelectric and nuclear plants.

Nonfossil Fuels

Nonfossil-fueled generation from nuclear, hydroelectric, and other renewable sources (wind, solar, biomass, and geothermal) represented about 30.0 percent of total electricity generation in 1999 and 30.6 percent in 1998. The use of nonfossil fuels and renewable energy sources to generate electricity avoids the emission of CO2 that results from the combustion of fossil fuels. Due to lower marginal costs, nuclear and hydroelectric power generation typically displace fossil-fueled electricity generation.

Nuclear plants increased their output by 8.1 percent in 1999 as several plants in the East North Census Division returned to service, contributing to a record capacity factor of 86 percent for nuclear plants in 1999.(8) Nuclear energy provided 19.7 percent of the Nation's electricity in 1999.(9) Two-thirds of the Nation's nuclear power is generated in the New England, East North Central, South Atlantic, and Middle Atlantic Census Divisions, which generate 27.6 percent, 21.0 percent, 26.0 percent, and 35.6 percent, respectively, of their electricity with nuclear power.

More than one-half of the Nation's hydroelectric capacity is located in the Pacific Contiguous Census Division, which includes California, Oregon, and Washington. In the Mountain Census Division, Idaho generates virtually all of its electricity at hydroelectric plants. The availability of hydroelectric power is affected by both the amount and patterns of precipitation. High snowpack levels in the Northwest increased hydroelectric generation in Washington and Oregon during 1999, despite the fact that on an annual basis both States received less precipitation in 1999 than they did in 1998. However, the remainder of the Nation experienced dry conditions in 1999, decreasing the amount of hydroelectric power available to displace fossil-fueled generation.(10)

Factors Contributing to Changes In CO2
Emissions and Generation

The primary factors that alter CO2 emissions from electricity generation from year to year are the growth in demand for electricity, the type of fuels or energy sources used for generation, and the thermal efficiencies of the power plants. A number of contributing factors influencing the primary factors can also be identified: economic growth, the price of electricity, the amount of imported electricity, weather, fuel prices, and the amount of available generation from hydroelectric, renewable, and nuclear plants. Other contributing factors include demand-side management programs that encourage energy efficiency, strategies to control other air emissions to comply with the requirements for the Clean Air Act Amendments of 1990, and the installation of new capacity utilizing advanced technologies to increase plant efficiency, such as combined-cycle plants and combined heat and power projects. Annual changes in CO2 emissions are a net result of these complex and variable factors.

As estimated in this report, the amount of anthropogenic CO2 emissions attributable to the generation of electricity in the United States increased 1.4 percent since the previous year. In 1999, fossil-fueled generation increased by about 2.9 percent; however, almost all of the increase was associated with natural gas, the least carbon-intensive fossil fuel. The increase in CO2 emissions from the combustion of natural gas for electricity generation amounted to 46 million metric tons, while the CO2 emissions from the combustion of petroleum and coal decreased 16 million metric tons.

The national average output rate declined from 1.350 pounds of CO2 per kilowatthour in 1998 to 1.341 pounds CO2 per kilowatthour in 1999. The primary driver of this change was the decreased output rate for coal-fired electricity generation, which went from 2.117 pounds of CO2 per kilowatthour to 2.095 pounds of CO2 per kilowatthour. A change in the output rate for coal-fired electricity generation in the absence of significant change in non-emitting generation will have the greatest effect on the national average output rate of CO2 per kilowatthour both because coal-fired generation dominates the industry and is the most carbon-intensive fuel.

Economic Growth

Economic factors influence the demand for electric power. In 1999, a strong economy was measured by the 4.2-percent increase in the Gross Domestic Product (GDP).(11) Electricity consumption grew by 1.7 percent,(12) while the average national price of electricity decreased 2.1 percent, from 6.74 cents in 1998 to 6.60 cents in 1999.(13) Although the growing demand for electricity is primarily met by a corresponding growth in generation, a small amount is met by imported power, primarily from Canada.

Weather

Weather is another factor affecting the year-to-year changes in the demand for electricity. Both 1999 and 1998 were record-breaking years in terms of warm weather in the United States. The availability of hydroelectric power to displace fossil-fueled power was limited by dry conditions in much of the Nation, with the exception of the Pacific Northwest States.

During the summer months, the demand for power for air conditioning is a major factor in setting record high peak demands for some utilities. In 1999, electricity generating plants consumed almost as much coal as the record amount consumed in 1998 and increased their natural gas consumption to meet the continuing high demand for electricity in the summer of 1999.

Demand-Side Management (DSM)

Energy efficiency programs and DSM activities, such as improving insulation and replacing lighting and appliances with more energy efficient equipment, can reduce the demand for electricity. The reductions in demand achieved by DSM programs contribute to avoided CO2 emissions. In 1998, 49.2 billion kilowatthours of energy savings were achieved by DSM activities at electric utilities, a decrease from 56.4 billion kilowatthours in 1997. Declining levels of energy savings reflect, in part, lower utility spending on DSM programs. In 1998, utilities' total expenditures on DSM were $1.4 billion, a decrease of 13.1 percent from the previous year, and nearly 50 percent below the 1994 spending level.(14) Data for 1999 are not yet available.

Fossil and Nonfossil Fuels for Electricity Generation

The fuel or energy source used to generate electricity is the most significant factor affecting the year-to-year changes in CO2 emissions. Because hydroelectric and nuclear generation displace fossil-fueled generation when available, CO2emissions increase when hydroelectric or nuclear power is unavailable and fossil-fueled generation is used as a replacement. Conversely, CO2 emissions can be reduced through a greater use of nuclear, hydroelectric, and renewable energy for electricity generation. Collectively, nonfossil-fueled electricity generation by nuclear, hydroelectric, and renewable energy sources that do not contribute to anthropogenic CO2 emissions remained almost unchanged in 1999 as compared to 1998, with much of the increase in nuclear generation being offset by an absolute decrease in hydroelectric power generation and other generation from fuels such as municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to generate electricity.

As stated previously, the amount of available hydroelectric power is affected by precipitation patterns. In 1999, hydroelectric power generation was lower in all regions, except in the Northwestern States. Oregon, Idaho, and Washington typically generate more than 90 percent of their power at hydroelectric plants and export power to California. Hydroelectric power generationincreased in 1999 in these States, reducing the need for fossil-fueled generation and contributed to keeping CO2 emissions low in the Pacific Contiguous Census Division. Nationally, hydroelectric power generation decreased by 3.6 percent in 1999.

Nuclear power generation increased by 8.1 percent to a record level in 1999, which contributed to keeping CO2 emissions lower by displacing fossil-fueled generation, particularly in the East North Central Census Division. Several nuclear plants came back online in 1999, helping to increase the average nuclear capacity factor to 86 percent. An absolute increase in the amount of nuclear power more than offset the loss of some hydroelectric power in 1999.

Fuel Quality and Price

The amount of CO2 emissions from the combustion of fossil fuels to generate electricity varies according to the quality of the fuels, defined by their carbon content and the associated heating value (Btu).(15) The Btu content of fuels is a determinant of the number of kilowatthours that can be produced(16) and carbon content is a determinant of the amount of CO2 released when the fuel is burned. Fossil fuels are categorized as either coal, natural gas and other gaseous fuels, or petroleum and petroleum products. Coal-fired electricity generation has the highest output rate of CO2 per kilowatthour produced, averaging 2.095 pounds per kilowatthour in 1999. Petroleum-fired electricity generation averaged 1.969 pounds per kilowatthour, and natural gas-fired electricity generation had the lowest rate of 1.321 pounds per kilowatthour. With coal-fired plants generating the majority of electricity in the Nation and having the highest output rate, they produced the greatest share of CO2 emissions from electricity generation, approximately 80 percent of the total.

Some plants are capable of switching fuels to take advantage of the least expensive or the most available resources. In 1998, the price of crude oil reached its lowest level since 1976, causing the price of petroleum delivered to electric utilities to fall below that of natural gas for the first time since 1993. This factor is important when considering the capability of some electric plants to burn the least expensive of these two fuels. As a result of falling prices in 1998, petroleum-fired generation was higher in 1998 than in 1997. However during 1999, the price of petroleum began to increase, and generation from petroleum plants declined. Petroleum has a higher output rate of CO2 than natural gas; therefore, switching from petroleum to natural gas can have a beneficial effect on both the overall amount and output rate of CO2 emissions.

In 1999, virtually all of the increase in fossil-fueled generation was from natural gas-fired plants. Coal-fired electricity generation was close to unchanged, while petroleum-fired electricity generation fell. Most of the increase in CO2 emissions from gas-fired plants was offset by the decline in CO2 emissions from petroleum- and coal-fired plants.

Thermal Efficiencies of Power Plants

CO2 emissions from electric power generation are influenced by the efficiency with which fossil fuels are converted into electricity. In a typical power plant, about one-third of the energy contained in the fuel is converted into electricity, while the remainder is emitted as waste heat. Substantial improvements in generation efficiency can be achieved in the future through the replacement of traditional power generators with more efficient technologies, such as combined-cycle generators and combined heat and power (CHP) systems. In these types of systems, waste heat is captured to produce additional kilowatthours of electricity or displace energy used for heating or cooling. Both strategies result in lower CO2 emissions. The national average thermal efficiency of power generation from fossil fuels in 1999 was estimated to be 32.54 percent, slightly higher than the previous year's average of 32.42 percent.(17)

The average thermal efficiency of coal-fired plants went from 33.15 percent to 33.54 percent in 1999. The improvement in efficiency is also reflected in the national average output rate of pounds of CO2 per kilowatthour. The output rate for coal-fired plants decreased from 2.117 pounds of CO2 per kilowatthour in 1998 to 2.095 in 1999. Petroleum-fired plants and natural gas-fired plants showed slightly lower thermal efficiencies in 1999, with a corresponding change in the output rate. The rate for petroleum-fired plants increased from 1.915 to 1.969 pounds of CO2 per kilowatthour, and natural gas-fired plants' output rate increased from 1.314 to 1.321 pounds of CO2 per kilowatthour.

Conclusion

The emission of CO2 by electric power plants is not controlled because no standards or required reductions currently exist. Some technology is available to limit CO2 emissions, but it is extremely expensive. The options to limit the emission of CO2 from electricity generation are to encourage reduction of the overall consumption of electricity through energy efficiency and conservation initiatives, to improve combustion efficiency at existing plants or install new units that employ more efficient technologies, such as combined-cycle units and combined heat and power (CHP) systems, and to replace fossil-fueled generation with nonfossil-fueled alternatives, such as nuclear, hydroelectric, and other renewable energy sources.

Comparison of Projected with Actual CO2
Emissions and Generation by Fuel Type

Each year, the Energy Information Administration prepares the Annual Energy Outlook (AEO), which contains projections of selected energy information. Projections for electricity supply and demand data, including CO2 emissions and generation by fuel type, are made for the next 20 years. To evaluate the accuracy and usefulness of the forecast, a comparison was made between the latest forecast for 1999 (from the AEO2000) and the estimated actual data for 1999 (Table 5). The near-term projections in the AEO are based on a combination of the partial-year data available when the forecast was prepared, the latest short-term forecast appearing in the Short-Term Energy Outlook, and the regional detail contained in the National Energy Modeling System (NEMS). Consequently, comparisons with the actual data for 1999 are not a definitive indicator of the accuracy of the longer-term projections appearing in the AEO. Nevertheless, they do provide a useful preliminary gauge for tracking and measuring the projections against actual data over time.

Table 5. U.S. Electric Power Industry Projected and Actual Carbon Dioxide Emissions and Generation, 1999

 

Projected

Actual

Percentage
Difference

CO2 Emissions (million metric tons)

 

 

 

  Coal

1,863

1,788

-4.0        

  Petroleum

100

106

6.0        

  Natural Gas, Refinery and Still Gas

313

337

7.7        

  Othera

--

14

N/A        

Total CO2 Emissions

2,277

2,245

-1.4        

Generation (billion kWh)

 

 

 

  Coal

1,878

1,882

0.2        

  Petroleum

121

119

-1.7        

  Natural Gas, Refinery and Still Gas

542

562

3.7        

  Othera

20

22

10.0        

  Non-Fossil Fuels b

1,072

1,106

3.2        

Total Generation

3,632

3,691

1.6        

Net Imports

47

29

-38.0        

Total Electricity Supply

3,679

3,720

1.1        

Retail Electricity Sales by Utilities (billion kWh)

3,288

3,296

0.2        

Nonutility Generation for Own Use/Sales (billion kWh)c

173

165

-4.6        

Losses and Unaccounted For (billion kWh)

218

259

18.8        

   aOther fuels include municipal solid waste (MSW), tires, and other fuels that emit anthropogenic CO2 when burned to generate electricity. MSW generation represents the largest share of this category. MSW projections in the Annual Energy Outlook 2000 are assumed to have zero net CO2 emissions. Due to a change in the accounting for MSW by the Environmental Protection Agency, future AEOs will estimate the CO2 emissions attributed to the non-biomass portion of this fuel. If this had been done for the AEO2000, CO2 emissions for MSW would have been 14 million metric tons for 1999.
   bIncludes nuclear and most renewables, which either do not emit CO2 or whose net CO2 emissions are assumed to be zero.
   cData for 1999 are estimated.
    Note: Actual data for CO2 emissions and electricity generation for 1999 are preliminary. Components may not add to total due to independent rounding.
   Sources: Projections: Energy Information Administration, Annual Energy Outlook 2000, DOE/EIA-0383 (2000) (Washington, DC, December 1999) and supporting runs of the National Energy Modeling System. Actual: Carbon dioxide emissions and generation: Table 1; other data: Energy Information Administration, Monthly Energy Review, April 2000, DOE/EIA-0035(2000/04) (Washington, DC, April 2000); Energy Information Administration, Short-Term Energy Outlook, May 2000 (EIA Web site, www.eia.doe.gov/emeu/steo/pub/contents.html).

Total electricity-related CO2 emissions for fossil fuels in 1999 were 1.4 percent below the projected emissions level, while the actual total generation from fossil fuels was 0.9 percent above the projected generation level. The largest percentage difference between projected and actual generation by fuel (other than for "Other") was for natural gas-fired generation, which was 3.7 percent higher than projected, but with a corresponding difference in CO2 emissions of 7.7 percent. However, the largest absolute difference between projected and actual CO2 emissions by fuel was for coal-fired generation, whose emissions were 75 million metric tons, or 4.0 percent, below the projected level, even while generation was 0.2 percent higher. Three primary factors contribute to the divergence in projected and actual CO2 emissions:

  • Efficiency of generating units. Average generating efficiencies for coal-fired capacity were higher in 1999 than those assumed by NEMS, on the order of about 4 percent. On the other hand, the efficiency of natural gas-fueled capacity was about 4 percent lower than the NEMS assumptions. Because coal-fired units produce more than three times the generation of natural gas-fired generators, the impact of the higher efficiencies of coal-burning capacity outweighs the lower actual efficiencies for natural gas capacity. Efficiencies for petroleum-based generation, a much smaller share of overall supply, were 5.6 percent lower than the NEMS assumptions.

  • Total generation requirements. Overall electricity generation was 1.6 percent higher in 1999 than projected. This was due to the combined effects of higher sales, lower imports, and higher losses for electricity than expected. The incremental generation requirements were met in part by higher natural gas-fired generation, as well as greater reliance on nonfossil sources of electricity such as nuclear and renewables. To the extent that natural gas-fired generation was above the forecast, higher CO2 emissions resulted.

  • Increased nuclear and hydroelectric generation. Nuclear generation was 30 billion kilowatthours, or 5.7 percent, above the projected levels in 1999. The difference was due primarily to improving performance of nuclear generating units, beyond that assumed in the projections. Also, hydroelectric generation was 13 billion kilowatthours, or 4.3 percent, above projections. Given the same overall level of generation, higher nuclear and hydroelectric projections would have resulted in less projected generation from fossil fuels, thus bringing electricity-related CO2 emissions more in line with actual data.

Voluntary Carbon-Reduction and
Carbon-Sequestration Programs

Both the DOE and the EPA operate voluntary programs for reducing greenhouse gas emissions and reporting such emission reductions. Voluntary programs that contribute to emission reductions in the electricity sector include DOE/EIA's Voluntary Reporting of Greenhouse Gases Program and EPA's ENERGY STAR program.

EIA's Voluntary Reporting of Greenhouse Gases Program collects information from organizations that have undertaken carbon-reducing or carbon-sequestration projects. Most of the electric utilities that report to the Voluntary Reporting Program also participate in voluntary emission reduction activities through DOE's Climate Challenge Program. In 1998, as part of the Voluntary Reporting Program, 120 organizations in the electric power sector reported on 1,166 projects undertaken in 1998.(18) By undertaking these projects, participants indicated that they reduced CO2 emissions by 165.8 million metric tons(19) (Table 6). The organizations almost universally measured their project-level reductions by comparing emissions with what they would have been in the absence of the project. Reported CO2 reductions from these projects accounted for 7.5 percent of 1998 CO2 emissions attributed to the generation of electric power in the United States. Foreign reductions, largely from carbon-sequestration projects, account for 6.0 percent of total electric utility sector reductions reported for 1998.


Table 6. Electric Power Sector Carbon Dioxide Emission Reductions, 1997 and 1998
(Million Metric Tons Carbon Dioxide)

Type of Reduction

Carbon Dioxidea

1997

1998

Domestic Reductions

 

 

  Emission Reductions Projects

135.9

155.3

  Sequestration Projects

   0.3

   0.5

   Total Domestic Reductions

136.2

155.8

Foreign Reductions

 

 

  Emission Reductions Projects

   0.1

   0.1

  Sequestration Projects

   9.4

   9.9

   Total Foreign Reductions

   9.5

 10.0

Total CO2 Reductions Reported

145.8

165.8

    aThe Voluntary Reporting of Greenhouse Gases Program is currently in the 1999 data reporting cycle; the most recent year for which complete data are available is 1998. The 1997 and 1998 data in last year's report were preliminary and have been revised in this report due to subsequent completion of internal EIA review of those data. Emission reductions also include those reported by landfill methane operators. The use of landfill methane to generate electricity displaces fossil fuel power generation and produces a reduction in CO2 emissions equivalent to the amount of CO2 that would have resulted from fossil fuel power generation. In calculating CO2 reductions, it is assumed that landfill carbon is biogenic and, thus, the CO2 emissions from landfill gas combustion are zero.
   Note: Totals may not equal the sums of the parts due to independent rounding. This data cannot be compared directly to other figures in this report because reporters to EIA's Voluntary Reporting of Greenhouse Gases Program may report emission reductions using baselines and valuation methods different from those applied elsewhere.
   Source: Energy Information Administration, Form EIA-1605, "Voluntary Reporting of Greenhouse Gases," (long form) and EIA-1605EZ, "Voluntary Reporting of Greenhouse Gases," (short form), 1997 and 1998 data.



DOE's Climate Challenge Program, a voluntary initiative with the electric utility sector established under the President's 1993 Climate Change Action Plan, has become the principal mechanism by which electric utilities participate in voluntary emission reduction activities. Participants that reported the CO2 emission reductions summarized in this report include electric utilities and holding companies, independent power producers, and landfill methane operators. Climate Challenge participants negotiate voluntary commitments with the DOE to achieve a certain level of emission reductions and/or to participate in specific projects. Companies making Climate Challenge commitments as of 1998 accounted for about 71 percent of 1990 U.S. electric utility generation.(20) Climate Challenge participants are required to report their achieved emissions reductions to the Voluntary Reporting of Greenhouse Gases Program.

Results from the Climate Challenge program cannot be compared directly to other figures in this report because the Climate Challenge program allows participants to report emissions reductions using baselines and calculation methods different from those applied elsewhere. For this reason, EIA keeps an accounting of reports submitted by Climate Challenge participants, but the United States counts only a fraction of these reported reductions in comprehensive assessments of overall reductions in greenhouse gases.(21)

The largest reductions claimed for 1998 are from these major U.S. electric utilities: the Tennessee Valley Authority (26.0 million metric tons of CO2), TXU (19.9 million metric tons of CO2), Duke Energy (12.1 million metric tons of CO2), and FirstEnergy (10.6 million metric tons of CO2).(22) These four companies accounted for about 41.4 percent of the CO2 emissions reductions reported in 1998 by the electric power sector. Each of these companies owns one or more nuclear power plants, and the bulk of their reported reductions is calculated by comparing either actual or additional nuclear output from their plants with the emissions that would have occurred if the same quantity of electricity had been generated using fossil fuels.

Electric power industry companies also reported on projects reducing other greenhouse gases.(23) Combining all projects and all greenhouse gases, the electric power sector reporters claimed 176.9 million metric tons of carbon dioxide equivalent reductions in 1998.

Utilities also undertook a number of carbon-sequestration projects. Although these projects do not directly affect CO2 emissions, they do offset utility CO2 emissions. Foreign carbon-sequestration projects from the electric sector were reported to be 9.9 million metric tons of CO2 in 1998, while domestic projects were reported to be 0.5 million metric tons. These activities were dominated by three independent power producer subsidiaries of the AES Corporation, which reported 7.6 million metric tons of CO2 sequestration annually from three projects with activities in Belize, Bolivia, Ecuador, Peru, and Guatemala. These projects undertake tropical rain forest management, preservation, or reforestation.

In addition, more than 30 companies reported on their pro-rated share of participation in the Edison Electric Institute's UtiliTree program.(24) The UtiliTree program is a carbon-sequestration mutual fund in which electric utilities purchase shares. UtiliTree uses the funds to participate in forest management and reforestation projects in the United States and abroad.

The United States' voluntary programs are reducing domestic emissions of greenhouse gases in a number of sectors across the economy through a range of partnerships and outreach efforts. For example, the ENERGY STAR Program, run by the EPA in partnership with DOE, reduces energy consumption in homes and office buildings across the Nation. EPA and DOE set energy-efficiency specifications for a range of products including office equipment, heating and cooling equipment, residential appliances, televisions and VCRs, and new homes. The ENERGY STAR label for buildings is based on a performance rating system that allows building owners to evaluate the efficiency of their buildings relative to others. On average, buildings across the country can improve efficiency by 30 percent through a variety of improvements. Manufacturer and retailer partners in the program may place the nationally recognized ENERGY STAR label on qualifying products.

In the past several years, the ENERGY STAR label has expanded to include more than 30 products and nearly 7,000 product models. In 1999, energy consumption was reduced by approximately 28 billion kilowatthours as a result of the program, reducing greenhouse gas emissions by nearly 21 million metric tons CO2 (Table 7). Through EPA's ENERGY STAR Buildings and Green Lights Partnership, more than 15 percent of the square footage in U.S. buildings has undergone efficiency upgrades resulting in electricity savings in excess of 21 billion kilowatthours and emissions reductions of more than 16 million metric tons CO2.

Table 7. CO2 Emission Reductions and Energy Savings from EPA's Voluntary Programs, 1998 and 1999

 

1998

1999

 

Million Metric Tons
of CO2 Reduced

Billion kWh
Saved

Million Metric Tons
of CO2 Reduced

Billion kWh
Saved

ENERGY STAR Labeled Products

14.7 

20

20.9

28

ENERGY STAR Buildings and Green Lights

 8.8

13

16.5

21

Climate Wise

 9.9

  3

13.9

  5

   Source: U.S. Environmental Protection Agency, Climate Protection Division, 1998 Annual Report: Driving Investment in Energy Efficiency, ENERGY STAR and Other Voluntary Programs (EPA 430-R-99-005), forthcoming.


Environmental Effects of
Federal Restructuring Legislation

In April 1999, the Administration submitted to Congress the Comprehensive Electricity Competition Act (CECA), a bill to restructure the U.S. electricity industry and foster retail competition. CECA was designed to ensure that the full economic and environmental benefits of electricity restructuring are realized. The expected environmental benefits are the result of both the effects of competition and specific provisions included in the Administration's proposal, such as a renewables portfolio standard, a public benefits fund, and tax incentives for investment in combined heat and power facilities. Competition itself will also provide incentives to generators to improve their own efficiencies, and create new markets for green power and end-use efficiency services, all of which reduce greenhouse gas emissions.

Following an exhaustive interagency review, the DOE issued a Supporting Analysis(25) that quantified both the economic and environmental benefits of the Administration's plan in May 1999. The analysis focused on the impacts of full national retail competition relative to continued cost-of-service regulation. The results showed that the Administration's proposal will reduce CO2 emissions by 216 million metric tons in 2010. An EIA study(26) using the same assumptions from the supporting analysis produced similar results. Carbon dioxide emissions in the EIA report were estimated to be 194 million metric tons lower in the competitive case than in the cost-of-service reference case in 2010. A number of key uncertainties, however, can affect these projections, and some of the reductions could be realized due to actions already taken by individual States. Recognizing uncertainties and the need to avoid double-counting, the Administration projected that its proposal would reduce CO2 emissions from energy use by 147 to 220 million metric tons annually by 2010.

The DOE and EPA see no recent developments that would change our projection of the expected impact of the Administration proposal. However, we note that restructuring bills that have recently moved forward in the Congress differ significantly from the Administration's comprehensive proposal. These bills do not include key provisions that support the effective functioning of competitive electricity markets and energy diversity while at the same time providing reductions in CO2 emissions. In addition to maintaining our capability to reassess the impacts of our own proposal, we are also prepared to provide quantitative analyses of alternative restructuring bills. Additional measures could offer potential for cost-effective emissions reductions in the electric power sector, although they are no substitute for comprehensive restructuring legislation that promotes competitive markets and consumer benefits while providing important reductions in CO2 emissions from electric power generation.

Presidential Directive

MEMORANDUM FOR THE

SECRETARY OF ENERGY

ADMINISTRATOR OF THE ENVIRONMENTAL PROTECTION AGENCY

SUBJECT: Report on Carbon Dioxide (CO2) Emissions

My Administration's proposal to promote retail competition in the electric power industry, if enacted, will help to deliver economic savings, cleaner air, and a significant down payment on greenhouse gas emissions reductions. The proposal exemplifies my Administration's commitment to pursue both economic growth and environmental progress simultaneously.

As action to advance retail competition proceeds at both the State and Federal levels, the Administration and the Congress share an interest in tracking environmental indicators in this vital sector. We must have accurate and frequently updated data.

Under current law, electric power generators report various types of data relating to generation and air emissions to the Department of Energy (DOE) and the Environmental Protection Agency (EPA). To ensure that this data collection is coordinated and provides for timely consideration by both the Administration and the Congress, you are directed to take the following actions:

  • On an annual basis, you shall provide me with a report summarizing CO2 emissions data collected during the previous year from all utility and nonutility electricity generators providing power to the grid, beginning with 1998 data. This information shall be provided to me no more than 6 months after the end of the previous year, and for 1998, within 6 months of the date of this directive.

  • The report, which may be submitted jointly, shall present CO2 emissions information on both a national and regional basis, stratified by the type of fuel used for electricity generation, and shall indicate the percentage of electricity generated by each type of fuel or energy resource. The CO2 emissions shall be reported both on the basis of total mass (tons) and output rate (e.g., pounds per megawatt-hour).

  • The report shall present the amount of CO2 reduction and other available information from voluntary carbon-reducing and carbon-sequestration projects undertaken, both domestically and internationally, by the electric utility sector.

  • The report shall identify the main factors contributing to any change in CO2 emissions or CO2 emission rates relative to the previous year on a national, and, if relevant, regional basis. In addition, the report shall identify deviations from the actual CO2 emissions, generation, and fuel mix of their most recent projections developed by the Department of Energy and the Energy Information Administration, pursuant to their existing authorities and emissions.

  • In the event that Federal restructuring legislation has not been enacted prior to your submission of the report, the report shall also include any necessary updates to estimates of the environmental effects of my Administration's restructuring legislation.

  • Neither the DOE nor the EPA may collect new information from electricity generators or other parties in order to prepare the report.

    WILLIAM J. CLINTON



    Data Sources and Methodology

    This section describes the data sources and methodology employed to calculate estimates of carbon dioxide (CO2) emissions from utility and nonutility electric generating plants. Due to the report being submitted in June of 2000, the annual census data, on which 1998 emission estimates are based, are not yet available from the Form EIA-860B and Form EIA-767. The methodology employed for estimating 1999 CO2 emissions in this report are based on two monthly data collections, Form EIA-759 and Form EIA-900. The Form EIA-759 collects monthly generation and fuel consumption from all utility-owned generating plants, and the Form EIA-900 collects generation and fuel consumption from nonutility plants with a nameplate capacity of 50 megawatts (MW) or more. The 1999 estimates of CO2 emissions and net generation are preliminary estimates; final emissions estimates based on annual census data will be published in the Electric Power Annual Volume II 1999, later this year.

    Electric Utility Data Sources

    The electric utility data are derived from several forms. The Form EIA-767, "Steam-Electric Plant Operation and Design Report," collects information annually for all U.S. power plants with a total existing or planned organic- or nuclear-fueled steam-electric generator nameplate rating of 10 MW or larger. Power plants with a total generator nameplate rating of 100 MW or more must complete the entire form, providing among other data, information about fuel consumption and quality. Power plants with a total generator nameplate rating from 10 MW to less than 100 MW complete only part of the form, including information on fuel consumption.

    Form EIA-759, "Monthly Power Plant Report," is a cutoff model sample of approximately 360 electric utilities drawn from the frame of all operators of electric utility plants (approximately 700 electric utilities) that generate electric power for public use. The monthly data collection is from all utilities with at least one plant with a nameplate capacity of 50 MW or more. For all utility plants not included in the monthly sample, those with nameplate capacities less than 50 MW, monthly data are collected annually. Form EIA-759 is used to collect data on net generation; consumption of coal, petroleum, and natural gas; and end-of-the-month stocks of coal and petroleum for each plant by fuel-type combination.

    The Federal Energy Regulatory Commission (FERC) Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants," is a monthly record of delivered-fuel purchases, submitted by approximately 230 electric utilities for each electric generating plant with a total steam-electric and combined-cycle nameplate capacity of 50 MW or more. FERC Form 423 collects data on fuel contracts, fuel type, coal origin, fuel quality and delivered cost of fuel.

    Nonutility Data Sources

    Form EIA-860B, "Annual Electric Generator Report - Nonutility," (prior Form EIA-867, "Annual Nonutility Power Producer Report") collects information annually from all nonutility power producers with a total generator nameplate rating of 1 MW or more, including cogenerators, small power producers, and other nonutility electricity generators. All facilities must complete the entire form, providing, among other data, information about fuel consumption and quality; however facilities with a combined nameplate capacity of less than 25 MW are not required to complete Schedule V, "Facility Environmental Information," of the Form EIA-860B.

    Form EIA-900, "Monthly Nonutility Power Plant Report," is a cutoff model sample of approximately 500 nonutilities drawn from the frame of all nonutility facilities (approximately 2000 nonutilities) that have existing or planned nameplate capacity of 1 MW or more. The monthly data collection comes from all nonutilities with a nameplate rating of 50 MW or more. A cutoff model sampling and estimation are employed using the annual Form EIA-860B.

    CO2 Coefficients

    The coefficients for determining carbon released from the combustion of fossil fuels were developed by the Energy Information Administration. A detailed discussion of the development and sources used is contained in the publication, Emissions of Greenhouse Gases in the United States, (DOE/EIA-0573), Appendix B. The nonutility coefficients were developed to be consistent with the utility coefficients.

    Methodology for 1998

    The methodology for developing the CO2 emission estimates for steam utility plants and nonsteam utility plants (calculations performed on a plant basis by fuel), as well as for nonutility plants (calculations performed on a facility basis by fuel), is as follows:

    Steam Utility Plants

    Form EIA-767, "Steam-Electric Plant Operation and Design Report"

    Form EIA-759, "Monthly Power Plant Report"

    FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

    Step 1. Sum of Monthly Consumption (EIA-767) times Monthly Average Btu Content (EIA-767) divided by Total Annual Consumption (EIA-767) = Weighted Annual Btu Content Factor.

    Step 2. Annual Consumption (EIA-767) times Weighted Annual Btu Content Factor (Step 1) = Annual Btu Consumption.

    Step 3. Annual Btu Consumption (Step 2) times CO2 factors = Annual CO2 Emissions.

    Step 4. Reduce Annual CO2 Emissions (Step 3) by 1 percent to assume 99 percent burn factor.

    Nonsteam Utility Plants

    Form EIA-759, "Monthly Power Plant Report"

    FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

    Step 1(a). If monthly EIA-759 and monthly FERC Form 423 are available: Sum of Monthly Consumption (EIA-759) times Monthly Average Btu Content (FERC Form 423) divided by Total Annual Consumption = Weighted Annual Btu Content Factor.

    Step 1(b). If monthly EIA-759 is available, but not monthly FERC Form 423: Sum of Monthly Consumption (EIA-759) times Average Monthly Btu Content (calculated from FERC Form 423) divided by Total Annual Consumption = Weighted Annual Btu Content Factor.

    Step 1(c). If only annual EIA-759 is available: Annual Consumption (EIA-759) times Average Annual Btu Content (calculated from FERC Form 423) divided by Total Annual Consumption = Weighted Annual Btu Content Factor.

    Step 2. Annual Consumption (EIA-759) times Weighted Annual Btu Content Factor (Step 1) = Annual Btu Consumption.

    Step 3. Annual Btu Consumption (Step 2) times CO2 Factors = Annual CO2 Emissions.

    Step 4. Reduce Annual CO2 Emissions (Step 3) by 1 percent to assume 99 percent burn factor.

    Nonutility Plants

    Form EIA-860B, "Annual Electric Generator Report - Nonutility"

    FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

    Step 1. Annual Consumption (EIA-860B) times Average Annual Btu Content (EIA-860B) divided by Total Annual Consumption = Weighted Annual Btu Content Factor.

    Step 2. Annual Consumption (EIA-860B) times Weighted Annual Btu Content Factor (Step 1) = Annual Btu Consumption.

    Step 3. Annual Btu Consumption (Step 2) x CO2 Factors = Annual CO2 Emissions.

    Step 4. Reduce Annual CO2 Emissions (Step 3) by 1 percent to assume 99 percent burn factor.

    Methodology for 1999

    Utility Plants

    Form EIA-767, "Steam-Electric Plant Operation and Design Report"

    Form EIA-759, "Monthly Power Plant Report"

    FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

    Step 1(a). If monthly EIA-759 and prior year annual EIA-767 are available: Sum of Monthly Consumption (EIA-759) times Monthly Average Btu Content (EIA-767) divided by Total Annual Consumption (EIA-759) = Weighted Annual Btu Content Factor.

    Step 1(b). If prior year annual EIA-767 is not available, but monthly EIA-759 and monthly FERC Form 423 are available: Sum the Monthly Consumption (EIA-759) times the Monthly Average Btu Content (FERC Form 423) divided by the Total Annual Consumption (EIA-759) = Weighted Annual Btu Content Factor.

    Step 1(c). If prior year annual EIA-767 and monthly FERC Form 423 are not available, but monthly EIA-759 is available: Sum the Monthly Consumption (EIA-759) times the Average Monthly Btu Content (calculated at State level from FERC Form 423) divided by the Total Annual Consumption (EIA-759) = Weighted Annual Btu Content Factor.

    Step 1(d). If prior year annual EIA-767, monthly EIA-759 and monthly FERC Form 423 are not available, but only annual EIA-759 is available: Annual Consumption (EIA-759) times the Average Annual Btu Content (calculated at State level from FERC Form 423) divided by the Total Annual Consumption (EIA-759) = Weighted Annual Btu Content Factor.

    Step 2. Annual Consumption (EIA-759) times the Weighted Annual Btu Content Factor (Step 1) = Annual Btu Consumption.

    Step 3. Annual Btu Consumption (Step 2) times CO2 Coefficients (Emissions of Greenhouse Gases in the United States) = Annual Gross CO2 Emissions.

    Step 4. Reduce Annual Gross CO2 Emissions (Step 3) by 1 percent to assume 99 percent burn factor.

    Nonutility Plants

    Form EIA-900, "Monthly Nonutility Power Report"

    Form EIA-860B, "Annual Electric Generator Report - Nonutility"

    FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

    Step 1(a). If monthly EIA-900 and prior year annual EIA-860B are available: Sum the Monthly Generation by Census Division and Fuel Type (EIA-900), and apply annual growth factor model to estimate 1999 Annual Generation. Divide 1999 Annual Generation by 1998 Annual Generation (EIA-860B), subtract 1, and multiply by 1998 Total Annual Consumption(27) (EIA-860B) = 1999 Total Annual Consumption. 1999 Total Annual Consumption times Average Btu Content (EIA-860B for prior year) = 1999 Annual Btu Consumption.

    Step 1(b). If monthly EIA-900 and FERC Form 423 for 1998 are available: (sold utility plant to nonutility in 1999): Annual Consumption (EIA-900) times the Average Btu Content (FERC Form 423) = 1999 Annual Btu Consumption.

    Step 1(c). If only monthly EIA-900 is available (new nonutility plants): Annual Consumption (EIA-900) times the Average Btu Content (calculated at State level from FERC Form 423) = 1999 Annual Btu Consumption.

    Step 2. 1999 Annual Btu Consumption (Step 1) times CO2 Coefficients (Emissions of Greenhouse Gases in the United States) = Annual Gross CO2 Emissions.

    Step 3. Reduce Annual Gross CO2 Emissions (Step 2) by 1 percent to assume 99 percent burn factor.


    Endnotes

    1. The Presidential directive required the first report by October 15, 1999, and thereafter the report is required by June 30. See Appendix A for the full text of the directive.

    2. Data for 1999 are preliminary. Data for 1998 are final. Last year, 1998 data were preliminary and have been revised to final numbers.

    3. To convert metric tons to short tons, multiply by 1.1023. Carbon dioxide units at full molecular weight can be converted into carbon units by dividing by 44/12.

    4. The average output rate is the ratio of pounds of carbon dioxide emitted per kilowatthour of electricity produced from all energy sources, both fossil and nonfossil, for a region or the Nation.

    5. Caution should be taken when interpreting year-to-year changes in the estimated emissions and generation due to an undetermined degree of uncertainty in statistical data for the 1999 estimates. Also, differences in the 1998 and 1999 estimation methodologies have an undetermined effect on the change from 1998 to 1999 estimates. See Appendix B, "Data Sources and Methodology," for further information. For more information on uncertainty in estimating carbon dioxide emissions, see Appendix C, "Uncertainty in Emissions Estimates," Emissions of Greenhouse Gases in the United States, DOE/EIA-0573(98) (Washington, DC, October 1999). Also, because weather fluctuations and other transitory factors significantly influence short-run patterns of energy use in all activities, emissions growth rates calculated over a single year should not be used to make projections of future emissions growth.

    6. About 37 percent of CO2 emissions are produced by electric utility generators, as reported in the greenhouse gas inventory for 1998. An additional 3.5 percent are attributable to nonutility power producers, which are included in the industrial sector in the GHG inventory.

    7. Energy Information Administration, Emissions of Greenhouse Gases in the United States 1998, Chapter 2, "Carbon Dioxide Emissions," DOE/EIA-0573(98) (Washington, DC, October 1999). Data for 1999 will be available in October 2000.

    8. Capacity factor is the ratio of the amount of electricity produced by a generating plant for a given period of time to the electricity that the plant could have produced at continuous full-power operation during the same period. Based on national level consumption and generation data presented in the Electric Power Monthly, and assuming a net summer nuclear capability of 99,000 MW, a 1-percent increase in the annual nuclear plant capacity factor (equivalent to 8,672,400 megawatthours of additional nuclear generation) translates into a reduction in annual consumption of either 4.4 million short tons of coal, 14 million barrels of petroleum, or 92 billion cubic feet of gas, or most likely a combination of each.

    9. Energy Information Administration, Electric Power Annual 1999, Volume I, DOE/EIA-0348(99)/1 (Washington, DC, forthcoming).

    10. Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants, 1999, http://www.eia.doe.gov/cneaf/electricity/cq/cq_sum.html.

    11. http://www.bea.doc.gov/bea/dn1.htm, Department of Commerce web site, accessed May 10, 2000.

    12. Retail sales by utilities grew 1.73 percent from 1998 to 1999. Retail sales by marketers in deregulated, competitive retail markets are not included. The addition of an estimated 48 billion kilowatthours in retail marketer sales would result in an increase in electricity consumption of 2.45 percent from 1998 to 1999.

    13. Energy Information Administration, Electric Power Annual 1999, Volume I, DOE/EIA-0348(99)/1 (Washington, DC, forthcoming).

    14. DSM data for 1999 will be available in the latter part of 2000.

    15. Heating value is measured in British thermal units (Btu), a standard unit for measuring the quantity of heat energy equal to the quantity of heat required to raise the temperature of 1 pound of water 1 degree Fahrenheit.

    16. Boiler type and efficiency, capacity factor, and other factors also affect the number of kilowatthours that can be produced at a particular plant.

    17. The thermal efficiency is a ratio of kilowatthours of electricity produced multiplied by 3,412 Btu to the fuel consumed, measured in Btu. This ratio is dependent on the estimated generation and fuel consumption for 1999. Uncertainty and an undetermined degree of variation in both generation and fuel consumption data for the nonutility sector may contribute to an apparent change in the ratio, which should be regarded as a preliminary value at this time.

    18. The Voluntary Reporting of Greenhouse Gases Program is currently in the 1999 data reporting cycle; the most recent year for which complete data are available is 1998. The 1997 and 1998 data in last year's report were preliminary and have been revised in this report due to subsequent completion of internal EIA review of those data. Emission reductions also include those reported by landfill methane operators.

    19. The EIA also receives numerous reports on projects and emissions reductions from reporters outside the electric power sector. In addition, many reports submitted to the Voluntary Reporting Program (including electric power sector reports) include reductions of greenhouse gases other than carbon dioxide, such as methane and nitrous oxide and the high Global Warming Potential gases such as HFCs, PFCs and sulfur hexafluoride.

    20. U.S. Department of Energy, Climate Challenge Fact Sheet (1998), and conversation with Larry Mansueti, August 10, 1999. See also http://www.eren.doe.gov/climatechallenge/execsumm/execsumm.htm.

    21. See the 1997 Climate Change Action Report (the Submission of the United States of America under the United Nations Framework Convention on Climate Change), p. 100, for one such assessment.

    22. TXU was formerly known as Texas Utilities, while FirstEnergy is the result of a merger between Ohio Edison and Centerior Energy (Cleveland Electric).

    23. Other greenhouse gases include methane eductions from landfills and oil and natural gas systems, and sulfur hexafluoride (SF6), which has 23,900 times the global warming impact of carbon dioxide when released into the atmosphere.

    24. The more than 40 companies referenced in last year's report are participants in EEI's UtiliTree program. Of these companies, 31 reported their share of participation to the Voluntary Reporting of Greenhouse Gases Program for 1998.

    25. U.S. Department of Energy, Supporting Analysis for the Comprehensive Electricity Act, May 1999.

    26. Energy Information Administration, The Comprehensive Electricity Competition Act: A Comparison of Model Results. Internet site at http://www.eia.doe.gov/oiaf/servicerpt/ceca.html.

    27. 1998 Annual Consumption for cogenerators is adjusted to exclude fuel not used for generation of electricity.

* A New Perspective on Energy

Integrated systems for cooling, heating and power (CHP) for buildings incorporate multiple technologies for providing energy services to a single building or to a campus of buildings. Electricity to such buildings is provided by on-site or near-site power generators using one or more of the many options: internal combustion (IC) engines, combustion turbines, miniturbines or microturbines, and fuel cells. In CHP systems, waste heat from power generation equipment is recovered for operating equipment for cooling, heating, or controlling humidity in buildings, by using absorption chillers, desiccant dehumidifiers, or heat recovery equipment for producing steam or hot water. These integrated systems are known by a variety of acronyms: CHP, CHPB (Cooling, Heating and Power for Buildings), CCHP (Combined Cooling Heating and Power), BCHP (Buildings Cooling, Heating and Power), Trigeneration and IES (Integrated Energy Systems). 

CHP systems provide many benefits, including:

reduced energy costs, 
improved power reliability, 
increased energy efficiency, and 
improved environmental quality. 

What is a CHP System?

A CHP System is an efficient, environmentally-friendly "cogeneration" system that provides power (electricity) and energy (hot water and/or steam) at the location the power and energy are needed also known as "distributed generation." Cogeneration systems are at least two times more efficient than typical power plants which average about 27% - 35% efficiency - meaning 65% to 73% of the energy is wasted. 

What is a CHP System with Absorption Chillers or "Trigeneration"? 

Even more efficient than a standard CHP system is a CHP system that incorporates absorption chillers, which is  then a "trigeneration" system, also referred to as an "Integrated Energy System" or "Cooling, Heating and Power."  Trigeneration systems can be up to 50% more efficient than cogeneration systems and many average about 90% or more efficiency.  Absorption chillers recover the additional waste heat from CHP Systems to make chilled water for air-conditioning, thereby providing the building or facility's electricity, hot water/steam and air conditioing.


For more information on Carbon Dioxide Emissions, CHP Systems, Trigeneration, Absorption Chillers; Buildings, Cooling, Heating and Power; Cooling, Heating and Power for Buildings; Integrated Energy Systems or Energy Management Systems call us at: 832-758-0027

* From the Department of Energy website with permission 


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