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Chapter 4 Sales of Surplus Energy
In industrial facilities with very high heat demands, such as chemical, paper, refining, food processing, and metal production, sizing cogeneration systems to heat loads can generate more electricity than is consumed on-site.
82 Excess energy sales can provide a revenue stream for CHP projects, potentially
Advance projects and help meet national energy goals. This chapter focuses on accessing export markets for surplus electricity from combined heat and power plants, and on setting a fair, reasonable and non-discriminatory price for this energy source. While this guide does not advocate the development of these markets, it illustrates how they can be effectively implemented to promote this aspect of CHP (if such markets exist). Sales of excess energy from combined heat and power systems can be offered through three types of programs:
Program implemented under the Federal Public Service Regulatory Principles Act (PURPA)83
Guaranteed Rate (FIT) and Variations
Competitive procurement process.
4.2 PURPA Avoided Cost Rate
The high efficiency of a combined heat and power system depends on the facility's ability to utilize waste heat. Therefore, CHP systems are usually designed to meet on-site heating needs, rather than electricity needs. The electrical load of the system can usually be achieved by adjusting the electrical-to-heat ratio of the system.
84 Cogeneration System Design
Maximizing efficiency in many industrial facilities (i.e. Thermalmatch) can result in electricity production capacity exceeding plant demand, creating additional energy pricing-related market risk for end users, often among other core activities.
Congress passed PURPA to encourage competition for resources and the development of combined heat and power (another term for combined heat and power) and renewable energy technologies by providing a market for electricity produced by non-utility producers. Combined heat and power plants of any size and renewable resources up to 80 MW are eligible.
PURPA requires FERC to define and periodically review policies requiring utilities to purchase electricity and electricity from eligible facilities at the plant's avoided cost.
86 PURPA stipulates that the
Electric utilities purchased from qualifying institutions must not exceed the "Incremental Electricity Cost of Alternative Electricity."
87 PURPA defines incremental costs as “electricity costs
Electricity such businesses would generate or purchase from other sources if not purchased from [qualifying facility].
88 PURPA also requires utilities to purchase electricity from eligible facilities
At rates that are fair and reasonable to public service and public interest customers and that do not discriminate against eligible facilities.
82 combined heat and power systems, sized to correspond to the heating needs of the installation, work at maximum efficiency. 83 Congress passed PURPA in 1978 at 16 U.S.C. §824a-3. 84 Ace. Certification of combined heat and power systems: development of emission standards. Written by Anna Shipley et al. September 2001 Report No. IE014. http://pcpower.in/doc/combined_heat_and_power_systems.pdf.85 US Department of Energy Combined Heat and Power: Clean Energy Solutions. August 201286 FERC fulfilled its PURPA obligations by declaring 18 CFR Part 292. 87 16 U.S.C. §824a-3(b). 88 16 USC § 824a-3(d).
20 www.seeaction.energy.gov, March 2013.
States have considerable flexibility in administering PURPA. For example, in the recent California FIT case, for CHP systems up to 20 MW, FERC ruled that avoiding a “tiered” structure of cost rates complied with PURPA.
In particular, FERC affirms that government procurement commitments may be considered in calculating avoided costs:
"...when a state requires a utility to obtain a certain percentage of its electricity from generators with certain characteristics, generators with those characteristics are relevant in determining the costs avoided by the utility in meeting that supply requirement. source".
The 2005 amendments to PURPA and related FERC decisions restricted the use of PURPA in certain areas, particularly for installations greater than 20 MW.
91 Federal Energy Regulatory Office, 19 January 2006
The Commission (FERC) issued a Notice of Public Regulation (NOPR) to implement this provision of the Energy Policy Act of 2005. In this notice, FERC preliminarily determined that eligible facilities and utility-connected operators (ISO), PJM, ISO-New England (ISO-NE), and New York Independent System Operators (NYISO) that are members of the Independent Midwest System may not Discriminatory access to such wholesale markets, and where these markets meet legal standards, may exempt commitments to enter into new contracts or qualifying services. For all other media, FERC recommends determining whether the vehicle qualifies for the statutory purchase exemption on a case-by-case basis.
PURPA Mandatory Purchasing Commitments have also been demonstrated at Midwest ISO, PJM, ISO-NE, NYISO, Southwest Power Pool (SPP) and California ISO qualified facilities.
93 DOE Maintenance Checklist
Certain U.S. public services covered by Title I PURPA.94
Feed-in tariffs (FITs), also known as premium payments, advanced renewable tariffs, floor prices and standard products, are among the most common policies used by governments around the world to support the development of renewable resources in the energy sector. By early 2012, at least 65 countries and 27 international states and provinces had adopted these programs.
95 Key features include a price guarantee and
Buyer, grid access and long-term stable contracts strengthen investor confidence in CHP plants. 96
While these programs currently focus on renewable resources, FIT can also be used to extract cogeneration.
Like PURPA, FIT sets out standard rates, terms and conditions for purchasing electricity from eligible producers. FIT can go further by establishing priority access and transportation.
FIT program administrators must balance the need to set prices high enough to attract the desired type and amount of electricity with the need to protect consumers from paying more than is necessary to meet generation goals.
89 133 FERC ¶ 61.059, October 21, 2010. See the discussion of California's AB 1613 program in this guide. 90 Ibid., FERC Rules, 15, No. 29. 91 The Energy Policy Act of 2005 limits the amendment (210(m)), which allows utilities to apply to FERC for a waiver of the purchase obligation (outside of existing contracts), at least for large projects, if they can demonstrate that a competitive market provides sufficient Opportunity to sell electricity from qualified utilities. FERC found six regional transmission organizations and the Texas Electric Reliability Council to meet this requirement. In their FERC applications, utilities located in these designated areas may rely on a firm assumption that eligible facilities greater than 20 MW have access to the wholesale market without discrimination. 92 Edison Electric Institute. Purple: Make the sequel better than the original. December 2006. www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation/Documents/purpa.pdf.93 EUCI, The Use of PURPA in Today's Deregulated Wholesale Markets. June 5, 2012. http://llaw.com/wordpress_dev2/wp-content/uploads/2012/08/5June2012-Utiling-PURPA-in-todays-Deregulated-Wholesale-Market.pdf.94http://energy.gov/oe/services/ electricity-policy-coordination-and-implementation/other-regulatory-efforts/public.95 See REN21, Global Status Report on Renewable Energy 2012 (pp. 66 and 118). www.map.ren21.net/GSR/GSR2012.pdf. 96 For more information on regulatory rates see the National Association of Public Service Regulatory Commissioners. Feed Rates: Frequently Asked Questions from State Public Utilities Commissions. June 2010. www.naruc.org/Publications/NARUC%20Feed%20in%20Tariff%20FAQ.pdf National Institute of Regulatory Research. What is the effective feed rate in your state? design guide. April 2010. www.nrri.org/pubs/multi-utility/NRRI_FIT_design_april10-07.pdf; National Renewable Energy Laboratory. A guide for policymakers in designing interest rate regulation policies. June 2010. www.nrel.gov/docs/fy10osti/44849.pdf; and California Energy Commission. 2010. California Feed-In Tariff Program: Implications for Project Financing, Competitive Renewable Energy Zones, and Data Requirements. Prepared by KEMA, Incorporated.www.energy.ca.gov/2010publications/CEC-300-2010-006/CEC-300-2010-006.pdf.
http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation/Documents/purpa.pdfhttp://lklaw.com/wordpress_dev2/wp-content/uploads/2012/08/5June2012-Uusing-PURPA-in-todays- Mercado mayorista desregulado.pdfhttp://energy.gov/oe/services/electricity-policy-coordination-and-implementation/other-regulatory-efforts/publichttp://www.map.ren21.net/GSR/GSR2012。 pdfhttp://www.naruc.org/Publications/NARUC%20Feed%20in%20Tariff%20FAQ.pdfhttp://www.nrri.org/pubs/multi-utility/NRRI_FIT_design_april10-07.pdfhttp://www.nrri。 org/pubs/multi-utility/NRRI_FIT_design_april10-07.pdfhttp://www.nrel.gov/docs/fy10osti/44849.pdfhttp://www.energy.ca.gov/2010publications/CEC-300-2010-006/ CEC-300-2010-006.pdf
March 2013 www.seeaction.energy.gov 21
Program administrators typically set a fixed price for units delivered within a certain number of years, differentiated by technology, or mark up electricity market prices. This valuation is based on the estimated cost of qualifying generation and a reasonable return to investors.
Administrative pricing that does not reflect market conditions has resulted in new pricing mechanisms replacing the U.S. FIT that use competitive procurement across all FIT-eligible resources, with utilities selecting lower-cost supplies. For example, in late 2010, the California Public Utilities Commission adopted a renewable energy auction mechanism for distributed renewable energy generators ranging from 3 to 20 MW. The program offers non-negotiable contracts and minimum cost orders up to capacity limits. The Oregon Public Utilities Commission's Photovoltaic FIT Pilot Program uses a streamlined competitive bidding process to procure all systems over 100 kW. In addition, the scheme benefits from competitive bidding in one of two annual registration windows for systems above 10kW.
Alternatively, FIT pricing can be based on the value a generator provides to the electricity system or society. An example of such a program is the City of Sacramento's FIT program described in this section.
4.4 Competing orders
As mentioned above, in addition to using market-based mechanisms for variants of the FIT, governments and freight handlers have set CHP targets or timetables through laws, directives or agreements to expedite the competitive bidding process for the acquisition of large CHP projects. This chapter provides examples of such approaches in California and Ontario, Canada. In the restructured states, cogeneration projects can also apply to the energy market, as well as the capacity and ancillary services markets, provided they comply with established agreements. This process is described in Appendix E.
4.5 Pathways to successful implementation
4.5.1 California Investor-Owned Utility Cogeneration Feed Rate
California Assembly Bill (AB) 1613 (2006 and 2007) directs the California Public Utilities Commission (CPUC) to establish standard rates for electricity sales from qualifying combined heat and power systems to investor-owned suppliers.
Orders the California Energy Commission (CEC) to adopt technical eligibility criteria for cogeneration systems and requires utilities serving end customers to provide a marketplace for purchasing surplus electricity from qualified cogeneration systems. This section describes the feed rates established by the CPUC under AB 1613 for the state's three largest investor-owned utilities: Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric.
The CPUC has approved three standard contracts for purchasing surplus electricity from AB 1613-compliant combined heat and power systems:
Standard contract for installations up to 20 MW
Simplified standard contract for systems with an output power not exceeding 5 MW
Plus simplified contracts for systems up to 500kW, up to 10 years at the discretion of the supplier.
97 AB 1613 (2006) directs the CPUC to require investor-owned entities to submit fair and reasonable rates for excess capacity in combined heat and power systems of 20 MW and below. The law requires local utilities to conduct unlimited fee assessments for excess capacity in combined heat and power systems. The CPUC then directed the parties involved to negotiate price terms and a standard contract (PPA). Thus, MPR effectively takes into account time of day, season and fuel cost adjustments. TPM may include total environmental benefits and T&D deferrals. This is distinct from the utility's proposed use of short-run avoidable costs (SRAC). The SRAC is the price of the energy itself, sometimes referred to as the "spot market price" of energy; it does not capture capacity or lead time values. The California Waste Heat and Carbon Emissions Reduction Act, Assembly Bill (AB) 1613 (2007), directs the CPUC, the California Energy Commission, and utilities to develop policies and procedures for purchasing surplus electricity from new high-efficiency combined heat and power systems of 20 megawatts or less. To be eligible, the combined heat and power system must be "sufficient to meet the heat load of the eligible generation customer" and must be "operated continuously in a manner that meets the anticipated heat load and optimizes the efficient use of waste heat." 98 www.cpuc.ca.gov/PUC/energy/CHP/feed-in+tariff.htm.
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The purchase rate is based on the cost of a new baseload gas/steam turbine determined by the CPUC as a reasonable approximation of the marginal unit of utility avoided when purchasing from an eligible CHP. This approach differs significantly from some states' PURPA approach, which is based on short-run avoided costs and includes only energy prices and does not include cogeneration resource efficiency values. In addition, the CPUC has determined that utilities must bear all GHG compliance costs associated with the excess electricity they purchase from eligible CHP facilities.
In addition, local adders are used in CHP systems in high-value areas that meet specific requirements, reflecting savings from avoiding T&D retrofits. Specifically, the CPUC applies a 10 percent siting incentive for interconnected CHP systems in areas with local resource adequacy requirements, areas with limited grid capacity that require the purchase of local resources to protect against grid system failures. Based on the utility's determination of expected T&D costs specified by its general rates, the CPUC believes the total is a conservative estimate of avoided T&D costs for the following reasons:
The rebate applies only to the amount of energy sold to the power plant, not to the amount of energy the plant avoids producing or buying due to CHP.
Aggregate levels are based on the average avoided cost of T&D investment across the utility sector, not just the highest avoided local well-resourced areas.
T&D costs may increase due to requests for higher transmission speeds from FERC and higher billing rates in the CPUC program.
CHP systems must meet the resource adequacy requirements of the CPUC and the California Independent System Operator, or, pending compliance, facilities will be billed under the standard "PURPA Agreement" established as part of the CHP agreement. A qualified CHPS facility approved by the CPUC (see Section 4.5.3).
Rating systems must also be CEC certified per AB 1613.100
And the system must maintain this certification for the duration of the contract. CEC guidelines include emission limits, power conversion efficiency standards, and other technical requirements.
CPUC Requires FERCas The agency recognizes that federal energy law, PURPA, and FERC regulations do not override CPUC's decision to require California utilities to offer specific rates to California combined heat and power plants. 20 MW or less meets energy efficiency and other requirements. Pursuant to AB 1613. On July 15, 2010, FERC issued an order stating that the CPUC may implement its plans
Under two conditions under PURPA: (1) the combined heat and power generator must be certified as a PURPA101 qualifying facility,
(2) The fee set by the CPUC does not exceed the avoidable cost of purchasing the tool.
In a subsequent clarification order, FERC noted that states have broad discretion in implementing PURPA. FERC also said states could use the avoided tiered cost rate structure. In particular, the CPUC may determine the evasion rate for qualifying facilities subject to AB 1613 based on the higher long-term evasion rate, assuming that these facilities avoid purchasing capacity and facilities that do not qualify under AB 1613 can continue. Acceptance rates are based on lower rates, avoiding short-term costs. In addition, FERC confirmed that public procurement obligations (for example, requiring utilities to purchase specific energy sources with specific characteristics or under long-term contracts) could be considered when calculating avoided costs.
103 FERC therefore confirms that if
99 CPUC Decision 11-04-033. April 19, 2011. http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/133787.htm. 100 www.energy.ca.gov/wasteheat/index.html. 101 Unless the client is a public agency as defined in 16 USC §824(f), a facility may apply to FERC for self-certification of qualified facility status, "by the applicant's own certification that the facility satisfies [applicable requirements for a qualified facility] status and does not include Determination of facility status by the Oregon PUC...However, self-certified applicants may receive a denial, invalidation, or request for a supplemental letter if, during the Periodic Facility Review of Compliance, your application is determined not to meet the relevant requirements.'See www.ferc.gov/docs-filing/forms/form-556/form-556.pdf For more information, visit www.ferc.gov/industries/electric/gen-info/qual-fac/obtain.asp 102132 FERC ¶ 61.047. 103 133 FERC ¶ 61.059.
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If the state requires a utility to obtain a certain percentage of its electricity from generators with certain characteristics, it can perform separate avoided cost calculations for generating facilities with the same characteristics in order to meet its public contracting obligations.
The purpose of AB 1613 is to help reduce project financing cost risk by providing an additional revenue stream. As of October 2012, 4 projects have been certified to meet the technical requirements of AB 1613 and 1 is under construction. However, no power purchase agreement has been signed. Some project owners and developers have expressed concern about barriers holding back interconnection and continued negotiations with the California ISO and local utilities.
104 The CPUC and CEC are aware of the difficulties and are expected to do so.
Solve the problem.
how to consider standards
policy object. The goal of the CPUC in implementing AB 1613 is to increase the adoption of cogeneration to help meet greenhouse gas reduction goals (providing salable surplus electricity encourages optimal farm size). combined heat and power projects) and "to ensure that payers who do not use the combined heat and power system will be indifferent to the existence of this charge."
105 Other rules referenced by the CPUC include consistent and transparent conditions
For each utility, lower transaction costs, offer payments sufficient to attract new projects but not overpay, and complement other programs such as self-generation incentive programs designed for on-site electricity consumption rather than export.
market signal. California AB 1613 provides clear guidance to the CPUC and state utilities that CHP is a priority resource and must be paid for at a cost that the utility cannot avoid. This sends a clear message to the market.
payer impact. AB 1613 requires planning and pricing of excess electricity paid to eligible CHP systems in such a way as to provide fair compensation and leave payers indifferent. The CPUC concluded that MPR is an avoidable cost that should be based on the cost of a combined cycle gas turbine and consists of fixed and variable components.
107 The CPUC further asserts that, to ensure payer indifference, the 10%
A location premium must be applied to eligible CHP plants located in high-value areas to take into account location, environmental and social benefits.
4.5.2 Oregon Standard PURPA and Evasion Rates
In 2004, the Oregon Public Utilities Commission (PUC) launched an in-depth investigation into the rates, terms, and conditions of PURPA-eligible facilities. Oregon PUC also employs a Supplemental Interconnection Program
109 and Dispute Resolution.
110 This section focuses on standard contracts and avoidance cost rates
Guidelines for qualifying installations of thermal power plants up to 10 MW and negotiating cost-avoiding contracts and rates for large projects.
104 California Energy Commission. Next Generation Cogeneration: Policy Planning to 2030. 2012. Prepared by BryanNeff.www.energy.ca.gov/2012publications/CEC-200-2012-005/CEC-200-2012-005.pdf. ICF interview with Bryan Neff, October 16, 2012. 105 Pub. Util. Code § 2841 paragraph. (b)(4). 106 CPUC Decision 09-12-042. December 21, 2009. http://docs.cpuc.ca.gov/published/FINAL_DECISION/111494.htm. 107 CPUC Decision 09-12-042. December 17, 2009. http://docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_DECISION/111494.PDF See Discussion, p. 69 and Fact Sheet 22. 108 Ibid., see Discussion, p. 69 and Legal Conclusions 3, 4, 10 and 11.109 The Oregon PUC has adopted an interconnection program and standard interconnection applications and protocols for cogeneration-eligible facilities and other generation facilities within state jurisdiction, up to 10 MW (see http://apps .puc state.or.us/orders/2009ords/09-196.pdf) and over 20 MW (see http://apps.puc.state.or.us/edockets/orders.asp?OrderNumber=10-132) . 10 MW to 20 MW distributed generation grid connection rules have not yet been formulated. 110 See Order No. 08-355 (doc. AR 526) at http://apps.puc.state.or.us/orders/2008ords/08-355.pdf. 111 Key decisions updating the PURPA rules for regulated utilities in Oregon are detailed in Orders 05-584, 06-538, and 07-360. Decrees 06-586 and 07-407 contain clarifications and corrections. See the case file for UM Docket 1129 at http://apps.puc.state.or.us/edokets/docket.asp?DocketID=11114.
http://www.energy.ca.gov/2012publications/CEC-200-2012-005/CEC-200-2012-005.pdfhttp://docs.cpuc.ca.gov/published/FINAL_DECISION/111494.htmhttp： //docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_DECISION/111494.PDFhttp://apps.puc.state.or.us/orders/2009ords/09-196.pdfhttp://apps.puc.state。 o.us/edockets/orders.asp?OrderNumber=10-132http://apps.puc.state.or.us/orders/2008ords/08-355.pdfhttp://apps.puc.state.or.us/ edockets/docket.asp?DocketID=11114
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Standard Contracts and Avoidable Cost Rates
PURPA requires utilities to offer standard contracts and avoid cost charges for qualified installations up to 100 kW.
112 State regulators have the authority to direct regulated utilities to increase this cap.
113 so reduce
Market barriers for small businesses eligible to sell surplus energy to public service companies. Additionally, minimum project sizes and other bidding requirements in utility and wholesale energy markets may preclude participation by small qualified firms.
As a result of the investigation, the Oregon PUC ordered regulated utilities to offer standard contracts and refrain from offering standard cost rates for eligible facilities up to 10 MW. In doing so, the Oregon PUC states:
"Standard contracts are designed to eliminate transactions and thus transaction costs...In addition to transaction costs (which in economics and related disciplines have traditionally been considered to cover only costs affecting economic exchange), the parties have identified other market barriers such as Information asymmetries and an uneven playing field make it difficult to negotiate non-standard contracts [qualifying services]. As with transaction costs, these market barriers may prevent certain [qualifying facility] projects from implement."
The Oregon PUC further requires qualifying facilities of any size to be able to enter into contracts of up to 20 years.
115 In reaching this conclusion, the Oregon PUC aimed to establish
The maximum period for which eligible institutions are allowed to obtain project financing. At the same time, the Oregon PUC limits the impact of standard (projected) avoided cost rates on deviations from actual avoided costs by only allowing fixed prices for the first 15 years of the contract and requiring market prices for the next 15 years. 5 years in 20 years. Contract period - years.
PUC Oregon's avoided cost rate distinguishes whether the utility is under-resourced or under-resourced. The avoided cost rate reflects long-term resource decisions that are delayed or avoided as a result of energy purchases from qualifying facilities when utilities are under-resourced. Therefore, the costs are based on the fixed and variable costs of a natural gas combined cycle gas turbine (CCCT). When the utility has sufficient resources (which may be the case early in the contract), the avoided cost rate is based on projected peak and off-peak market prices on the date the utility reports avoided costs.
Utilities must submit avoided cost charges every two years and 30 days after PUC Oregon issues a confirmation order for the integrated business resource plan. Notifications update CCCT costs and futures market prices and are validated through a public process with rates subject to Commission approval.
A guide to negotiating contracts over 10 MW
The Oregon PUC also employs a process for negotiating contracts for qualifying installations above 10 MW.
116 These procedures describe the steps in the timetable negotiation process and provide guidance for utilities.
Standard avoidable cost rates are adjusted to account for each factor published by FERC. These include the availability of electricity or energy at qualifying facilities during peak periods, the contribution of qualifying facilities to delayed capacity build-up, reduced fossil fuel use, and reduced pipeline losses.
117 Public services must be provided
112 Carolyn Elefant LLP. Revitalizing PURPA Goals: Circumvention of Existing State Limitations, Cost Appraisal Methodology and Proposed Reform Pathway in Support of Alternative Energy Development. 2011.www.cleanenergy.org/images/files/Elefant_Reviving_PURPA_Avoided_Costs_2011.pdf113 18 C.F.R. §292.304(c)(2). 114 Order No. 05-584 at 16. 115 The standard contract approved by PUC Oregon sets forth other important terms such as goodwill and guarantees against default. 116 See order numbers 07-360 and 07-407. 117 18 CFR 292.304(e).
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Instrument rating and description of each adjustment method. PUC Oregon also directed utilities to assess whether the location of qualifying facilities could prevent or delay transmission or distribution system upgrades. Utilities have been directed not to adjust standard evasion rates other than those listed or otherwise approved by the Oregon PUC.
Separate Fees for Qualifying Renewable Energy Installations
The Oregon PUC recently adopted a separate avoidable cost charge for eligible renewable facilities, including cogeneration facilities fueled by biomass resources that meet the state's Renewable Portfolio Standard.
118 Rates based on
The timing and cost of the next plant-scale renewable energy identified in the site integrated resource plan.
Through new PURPA contracts with utilities, eligible renewable energy facilities can choose either the renewable energy cost avoidance rate or the standard avoidance rate. Renewable avoided cost rates are only available during periods of renewable resource scarcity, when the utility anticipates a large-scale need for new renewable resources. This recourse is considered inevitable until the power company makes an irreversible commitment to acquire it after signing a power purchase contract or choosing an alternative to building the power plant after the tender process. To receive renewable energy rates, the utility must transfer your renewable energy credits to the utility.
During the initial years of the contract, when renewable energy is likely to be sufficient, the cost avoidance rate is based on forward market prices, similar to eligible non-renewable energy installations. During this period, RES plants retain their renewable energy credits.
In 2011, FERC concluded: “If a state requires a utility to obtain a certain percentage of its electricity from generators with certain characteristics, generators with those characteristics are the Related sources of cost.
how to consider standards
policy object. PUC Oregon's goal is to "encourage the cost-effective development of these [qualifying facilities] while protecting payors by ensuring that utility rates are equal to what they will incur instead of purchasing capacity at [qualifying facilities]".
120 Current results show that his method
achieve policy goals.
market signal. Oregon's avoided cost rate takes into account the difference in value of rated items when the tool is well-resourced and when it is under-resourced. When the utility does not require large-scale thermal or renewable resources (which may be the case early in qualifying installation contracts), the avoided cost rate is based on projected monthly market electricity prices. Peak hours and off-peak hours are at corresponding points. shopping mall. When the utility has insufficient resources, rates are based on projected costs for new CCCTs, the cost and schedule of which are validated through the utility's integrated resource planning process. Under the contract, the fuel price portion of the rate has been based on a monthly gas price index over the past five years.
121 Eligible sites can also be selected
These market options are within the contract term.
payer impact. Under PURPA, utilities cannot pay more than the avoided costs of a qualifying installation. The Oregon Public Utilities Commission's regulations for small and large qualifying businesses uphold this principle. In addition, the Oregon Public Utilities Commission's
118 See Order No. 11-505 (UM Doc. 1396) at http://apps.puc.state.or.us/orders/2011ords/11-505.pdf. 119 133 FERC 61.059, pp. 13-14. 120 Order #05-584 for 1. 121 Qualified Portland GE suppliers have an additional market option of a daily indexed rate based on the Dow Jones Mid-Columbia Electricity Price Index.
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In case of default, the insurance also protects the payer. Additionally, the Oregon PUC has a separate tax rate for renewable resources from qualified facilities, leaving taxpayers indifferent. Under the State Renewable Portfolio Standard, utilities are required to purchase such resources, and the renewable energy avoided cost rate is based on the cost of the next large renewable energy company identified in the state's comprehensive resource plan.
4.5.3 Settlement Agreements for Eligible California Cogeneration Projects and Facilities
In December 2010, the CPUC accepted the settlement agreement122
It established the 2020 PURPA contract exchange program for qualifying combined heat and power plants above 20 MW located in the state.
New CHP Procurement Program includes Request for Proposals (RFOs) for CHP resources only, 124
Prices are negotiated based on specific contracts and contract terms, including CPUC-approved form contracts.
125 The agreement also adopted an overall greenhouse gas reduction target of 4.8 million
Equivalent to the CO2 emissions of all investor-owned utilities, electric service providers, and community-chosen aggregators to facilitate efficient combined heat and power systems.
The goal of the program is to preserve existing cogeneration plants until the expiration of the PURPA contract and to encourage the development of new cogeneration resources in the country. As part of the settlement, the parties agreed not to object to a joint application by three major investor-owned utilities to FERC to waive the PURPA requirements for new contracts for qualifying facilities greater than 20 MW.
127 combined heat and power plants up to 20 MW to choose from
Enroll in a new or traditional PURPA program.
The settlement agreement envisions three periods: a transition period, an initial planning period, and a second planning period. The agreement sets an overall target of purchasing 3,000 MW of combined heat and power plant capacity.
128 Utilities can achieve these goals through a combination of procurement options, including CHP-
Solo RFO, a bilaterally negotiated contract or one of several pro forma contracts approved by liquidation.
Table 1 shows individual public service targets as of November 22, 2015 (initial planning period), for three contracts: A, B, and C:
Table 1. California Utility Contracting Goals 130
Instrument Goal A Goal B Goal C Promissory Note Total
SCE 630 MW 378 MW 394 MW 1402 MW
PG&E 630 MW 376 MW 381 MW 1387 MW
SDG&E 60 MW 50 MW 50 MW 160 MW
Total 1320 MW 804 MW 825 MW 2949 MW
122 http://docs.cpuc.ca.gov/PUBLISHED/GRAPHICS/124875.pdf. 123 Decision No. 10-12-035. December 21, 2010. http://docs.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/128624.pdf. The CPUC also adopted Orders 11-03-051 (http://docs.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/132685.pdf) and 11-07-010 (http://docs.cpuc.ca.gov /WORD_PDF/FINAL_DECISION/139237.pdf). 124 The following types of combined heat and power systems with a capacity greater than 5 MW are eligible to submit bids: existing facilities, new facilities, modernized facilities, expanded facilities and facilities converted to pre-planned facilities – power generation and operating instructions. 125www.pge.com/includes/docs/pdfs/b2b/energiessupply/qualifyingfacilities/settlement/exhibit_5.pdf.126 Three Large Investor-Owned Utilities Need to Select Aggregators for CHP on behalf of Electric Service Providers and Utilities resource. Communities Reducing Greenhouse Gas Emissions to Meet Agreement Goals 127 FERC approved a joint application (135 FERC ¶ 61,234) on June 16, 2011, Docket No. QM11-2-000. 128 existing CHP plants can fully subscribe to the 3,000 MW target under the scheme. See California Energy Commission. Combined Heat and Power: Policy Analysis and Market Assessment 2011-2030. Prepared by ICF International. June 2012. www.energy.ca.gov/2012publications/CEC-200-2012-002/CEC-200-2012-002-REV.pdf. The contract is also available on an as-available basis, payable in short term as announced by the utility. Cost avoidance, but only at low MW levels per utility. 129 To achieve a total capacity of 3,000 MW, the CPUC directed SDG&E to purchase an additional 51 MW by 2018 (during the second timeline). 130 CPUs. CHP Billing Plans and Eligible Facilities, www.cpuc.ca.gov/PUC/energy/CHP/settlement.htm.
http://docs.cpuc.ca.gov/PUBLISHED/GRAPHICS/124875.pdfhttp://docs.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/128624.pdfhttp://docs.cpuc.ca.gov/WORD_PDF/ FINAL_DECISION/132685.pdfhttp://docs.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/139237.pdfhttp://www.pge.com/includes/docs/pdfs/b2b/energysupply/qualifyingfacilities/settlement/exhibit_5.pdfhttp: //www.energy.ca.gov/2012publications/CEC-200-2012-002/CEC-200-2012-002-REV.pdfhttp://www.cpuc.ca.gov/PUC/energy/CHP/settlement。 htm
March 2013 www.seeaction.energy.gov 27
During the second program period, utilities must purchase CHPresources to meet any portion of the megawatt goals they did not meet during the first program period. The CPUC may pre-specify in its long-term procurement plan any additional cogeneration capacity needed to meet the utility's GHG reduction goals. Each utility must report semi-annually to the CPUC on its progress towards its megawatt and greenhouse gas reduction goals.
Utilities issued their first RFOs in late 2011 or early 2012 and began submitting final contracts for CPUC approval. For example, SCE completed five CHP contracts in the first tender with a total installed capacity of more than 750 MW.
131 The CPUC posted the latest results on its website.
how to consider standards
policy object. According to the agreement, "The goal of the National CHP Program is to encourage the continued operation of existing National CHP facilities, as well as the development, installation and interconnection of new, clean and efficient CHP facilities to increase diversity, reliable The benefits of energy resources available to consumers of government electricity and the protection of the environment. The agreement also provides for the retention of existing high-efficiency cogeneration units, support for operational changes at inefficient cogeneration plants, providing greater benefits to the country, and the attraction of new high-efficiency cogeneration facilities. Based on initial results, the program appears likely to achieve its policy goals.
market signal. The program provides greater regulatory and market certainty for CHP facilities, encourages the retrofit of inefficient facilities by replacing power or altering operations, and provides market-based compensation to maintain fair prices for California's CHP resources.
payer impact. The RFO will result in a competitive price, subject to final committee approval. Utilities will select the best bid for the CHP share they offer in the RFO at the target MW allocated by their CPUC. The process is similar to how utilities procure traditional power plants as well as resources that meet the state's Renewable Portfolio Standard. The utility may use the exorbitant offer as an excuse for not meeting its MW cogeneration target.
4.5.4 Ontario Hydro CHP Program
Ontario's existing supply resources are projected to halve by 2030, including the outage of 3,500 MW of coal-fired power plants. The province plans to add more than 8,000 megawatts of new renewable generation capacity by 2018, and expects transmission to reach capacity in some areas. The province sees combined heat and power as an important part of its future energy supply, with projects in densely populated or growing urban areas, industrial plants replacing inefficient boilers, and strategically located cogeneration as an alternative to transmission upgrades. Have the opportunity.
Beginning in 2005, the Ontario Minister of Energy issued a series of directives to the Ontario Power Authority (OPA), resulting in several directives for high-efficiency CHP plants to supply electricity to local distribution companies controlled by Independent System Electricity Operators (IESO) or end user. The original directive ordered OPA to purchase 1,000 MW of combined heat and power in the province.
134 In 2007, the Minister referred to the OPA
Establish a standard quotation procedure for small cogeneration plants. 135
Ask OPA to develop a
131 www.sce.com/EnergyProcurement/renewables/chp/rfo.htm. 132 www.cpuc.ca.gov/PUC/energy/CHP/settlement.htm. 133 Slides 9-11: https://cms.powerauthority.on.ca/sites/default/files/page/CHPSOP_Stakeholder_Presentation.pdf Slides 11 and 12: www.powerauthority.on.ca/sites/default/files/ page/CHPIV_Information%20Session_v4_0.pps; and slide 24: http://powerauthority.on.ca/sites/default/files/news/APPRO%202011%20Presentation%20by%20Amir%20Shalaby%20FINAL.pdf.
134 Saeki. www.powerauthority.on.ca/sites/default/files/619_15-06-2005_MOE_Letter_to_JCarr.pdf.135ive.pdf.136www.powerauthority.on.ca/sites/default/files/page/6933_April_10_2008_Procurement_RFP_CHP.pdf.
http://www.sce.com/EnergyProcurement/renewables/chp/rfo.htm http://www.cpuc.ca.gov/PUC/energy/CHP/settlement.htm https://cms.powerauthority.on.ca/ sites/default/files/page/CHPSOP_Stakeholder_Presentation.pdfhttp://www.powerauthority.on.ca/sites/default/files/page/CHPIV_Information%20Session_v4_0.ppshttp://powerauthority.on.ca/sites/default/files/新闻/APPRO%202011%20Presentation%20by%20Amir%20Shalaby%20FINAL.pdfhttp://www.powerauthority.on.ca/sites/default/files/619_15-06-2005_MOE_Letter_to_JCarr.pdfhttp://www.powerauthority.on。 ca/sites/default/files/page/4820_June_14,_2007_–_Clean_Energy_and_Waterpower_in_Northern_Ontario_Standard_Offer_Directive.pdfhttp://www.powerauthority.on.ca/sites/default/files/page/4820_June_14,_2007_–_Clean_Energy_and_Waterpower_en_ Northern_Ontario_Standard_Offer_Directive.pdfhttp://www.powerauthority . on.ca/sites/default/files/page/6933_April_10_2008_Procurement_RFP_CHP.pdf
28 www.seeaction.energy.gov March 2013
tender to meet the minister's target of a 100 MW combined heat and power plant to be powered by renewable energy, as the OPA had not received any bids for such a facility in previous tenders.
2010138 Ministerial Regulation
largely supersedes these earlier orders. Directs OPA to procure incremental cogeneration projects to achieve the targeted capacity of 1,000 MW by (1) individually negotiated contracts for cogeneration projects greater than 20 MW in capacity, and (2) Standard tender schemes are cost-effective and located where the local distribution system can accommodate them.
OPA must consider a number of factors when acquiring a CHP project under the current directive, including:
Heating Requirements Lifetime and Dimensions
Load the following capacity and other operational requirements
Reasonableness of Contract Terms and Risk-Benefit Ratio for Ontario Electricity Consumers.
Competitive order for a large combined heat and power plant
As part of the first combined heat and power contract in 2006, OPA awarded seven contracts with a total capacity of 415 MW to provide at least 5 MW of capacity (2 MW for regional power facilities) and operate until June 1 facilities open. June 2012. Second, the 2008 tender for CHP facilities with a minimum contract capacity of 10 MW resulted in no contracts. A third request for proposals was issued in 2009 for cogeneration projects using renewable fuels with a capacity of more than 10 MW, which resulted in two cogeneration contracts for an additional 45 MW.
In 2011, OPA launched its fourth tender for combined heat and power plants, culminating in tenders for 300 MW of projects larger than 20 MW, connected at the distribution or transmission level.
140 projects using natural gas, derivatives and renewable energy
Biomass, biogas and "underutilized" energy sources are eligible. OPA has identified five geographic areas where CHP projects can be located.
141 OPA determined that none of the submitted applications met the above criteria.
A solicitation does not offer a contract. 142
However, OPA also negotiates contracts with large CHP plants outside of the competitive process.
Standard Bidding Procedure for Small Thermal Power Plants
OPA is currently procuring grid-connected cogeneration projects with a capacity of up to 20 MW under the Clean Power Standard Offer Program, with a target capacity of 200 MW. Two songs from the show:
The initial allocation of standard offers for natural gas CHP projects is 150 MW. 144
The standard offer for energy recovery projects has an initial allocation of 50 MW. 145
Eligible projects include energy recovery from pressure reduction facilities, hot flue gas streams (except power generation facilities), and by-products of combustion processes.
137 The complexity of the project rules and the form of the contract were cited as possible reasons for the absence of an offer. Thus, OPA increases outreach and education of market participants. 138 www.powerauthority.on.ca/sites/default/files/new_files/about_us/pdfs/MC-2010-4477.pdf. 139 www.powerauthority.on.ca/gp/procurement-archive. 140 http://powerauthority .on.ca/chp-iv-procurement. 141 http://powerauthority.on.ca/sites/default/files/page/Appendix%20K_v2%20(Eligible%20Areas)%20(Sent).pdf.
142 With the exception of bids that did not meet the required criteria, results were kept confidential. See also www.powerauthority.on.ca/chp-iv-procurement.
143 This information is currently classified.
http://www.powerauthority.on.ca/sites/default/files/new_files/about_us/pdfs/MC-2010-4477.pdfhttp://www.powerauthority.on.ca/gp/procurement-archivehttp:// powerauthority.on.ca/chp-iv-procurement http://powerauthority.on.ca/sites/default/files/page/Appendix%20K_v2%20(Eligible%20Areas)%20(Sent).pdfhttp://www .powerauthority.on.ca/chp-iv-procurement https://cms.powerauthority.on.ca/combined-heat-power-standard-offer-program-chpsop https://cms.powerauthority.on.ca/energy -recovery-program quotes standard ersop
March 2013 www.seeaction.energy.gov 29
Any remaining capacity under the overall target of 200 MW will be provided on a first-come, first-served basis for projects of any type. For new projects, CHP standard offer scheme contracts have a term of up to 20 years, and for existing projects built no earlier than 2005, 20 years less than the number of days between the occupancy period and the start of operation date. The capacity fee is $28,900 per megawatt per month, and is designed to cover capital costs, ongoing operating expenses and an expected rate of return, which increases 30 percent per year, according to the Consumer Price Index. The possible surcharges are determined according to a formula that takes into account the calculated gross revenue of the IESO energy market CHP plant and the calculated variable costs of operation and maintenance of the facility, including the daily price of natural gas. OPA makes a monthly contingent payment to the Project Owner if the fixed capacity payment exceeds the facility's estimated net revenue, or the project owner pays OPA if the estimated net revenue exceeds the fixed capacity payment.
The standard CHP incentive program is only available in certain regions147
With few exceptions, for an initial term ending June 30, 2011. The program is open to all locations during its second term, which ends later this summer. The same location restrictions apply to the standard energy recovery discount plan, which is offered within a similar time frame.
Application requirements include a fee of $1,000, a guarantee of $20,000 per megawatt of annual average contracted capacity, confirmation of initial discussions to merge with a local distribution company, and proof of sufficient site visits to construct and operate the project. The useful heat output of the unit will be at least 15% from the third year of the contract and averaged over the first 10 years. OPA performs transmission availability tests to determine whether cogeneration projects have sufficient capacity, even when connected at the distribution level; local distribution companies conduct distribution availability tests on systems connected to the distribution system.
In late 2011, OPA signed a standard offer contract for 6 MW and considered remaining applications for a total capacity of 300 MW for the first track. OPA staff and project developers are expected to sign more agreements in 2012.
148 At the end of 2011, OPA listed about 972 MW of non-renewable cogeneration plants
The second track was signed, and almost all commercial operations have been realized149
how to consider standards
policy object. The goal of Ontario's competitive procurement of large-scale combined heat and power facilities is to develop cost-effective and efficient resources to meet the province's electricity needs and provide a stable and reliable supply of electricity to either the IESO-controlled grid or local distribution companies. The standard offer scheme is designed to support the development of cost-effective and efficient combined heat and power plants and energy recovery facilities of up to 20 MW which, connected to the local electricity distribution system, can accommodate this generation efficiently. These goals are achieved through policies documented by the Organization of American States.
market signal. OPA selects cogeneration projects in its bids based on an economic assessment using the bid form specified in the bid and compliance with mandatory requirements such as facility qualification, site inspection, and certification that the facility will meet heating standards. Projects must also go through a verification process to ensure that distribution and transmission systems have or will
146 Based on data from various sources for a reference CHP plant with a capacity of 10 MW, OPA assumes a capital cost of $2,170 per MW. The scaling factor of 30% is the ratio of annual variable costs to fixed costs. The assumed thermal efficiency of the reference plant is approximately 6.0 MMBtu/MWh. Check out OPA's Combined Heat and Power Production Standard Bidding Program (CHPSOP) stakeholder meeting. February 25, 2011 (slides updated March 3, 2011). https://cms.powerauthority.on.ca/sites/default/files/page/CHPSOP_Stakeholder_Presentation.pdf.147 https://cms.powerauthority.on.ca/sites/default/files/page/CESOP%20Locational%20Eligibility_0 .pdf.148http://magazine.appro.org/index.php?option=com_content&task=view&id=1816&Itemid=60.149 https://cms.powerauthority.on.ca/sites/default/files/news/OPA_ProgressReportonElectricitySupply_2011_Q4%20Final% 20for %20posting%2020120508.pdf.150 Ibid.
https://cms.powerauthority.on.ca/sites/default/files/page/CHPSOP_Stakeholder_Presentation.pdf https://cms.powerauthority.on.ca/sites/default/files/page/CESOP%20Locational%20Eligibility_0.pdfhttp： //magazine.appro.org/index.php?option=com_content&task=view&id=1816&Itemid=60https://cms.powerauthority.on.ca/sites/default/files/news/OPA_ProgressReportonElectricitySupply_2011_Q4%20Final%20for%20posting%2020120508。 pdfhttps://cms.powerauthority.on.ca/sites/default/files/news/OPA_ProgressReportonElectricitySupply_2011_Q4%20Final%20for%20posting%2020120508.pdf
30 www.seeaction.energy.gov March 2013
Sufficient connectivity resources are online to service the CHP program within the stated time frame. 151
OPA's support for the Standard Bid Program is based on best-in-class cost estimates for small-scale high-efficiency cogeneration and energy recovery systems, taking into account daily natural gas prices and sales in the Ontario energy market. The good performance of the new CHP plant shows a positive market signal to potential CHP customers in Ontario.
payer impact. Competitive ordering enables us to obtain the lowest prices among potential suppliers of well located and efficient combined heat and power plants. OPA rejected all bids in these solicitations because none of the proposals met the criteria set by the Ministry of Energy, including profitability and benefits to Ontario's grid. Applications for standard tender schemes for small cogeneration and energy recovery facilities must also meet these criteria, with payments based in part on electricity and gas market prices. In addition, all of these programs are subject to general capacity constraints that limit consumer costs, and within these constraints, OPA allocates the amount each program gets over time. In addition, OPA prioritizes the most energy-efficient and best-located projects for the greatest benefit to taxpayers.
Although this guidance does not discuss the advantages or problems of developing the markets discussed in this chapter; identifying how policies to promote this aspect of CHP can be effectively implemented where such markets exist. Cogeneration projects can use excess energy sales while helping to meet national energy goals. The most efficient CHP systems are designed to meet the heating needs of the host machine, so when considering a project it is important to ensure that the CHP system is sized for the user's needs. However, if surplus power is available due to efficiency improvements or high thermal demand of the facility, there is an option to sell this power to the utility. Access to export markets for thermal power plant surplus electricity at fair, reasonable and non-discriminatory surplus electricity sales prices is an important enabler. There are three mechanisms that states can use to ensure excess energy sales for cogeneration systems, and the following successful implementation methods:
151 For an example of a detailed review process, see CHP’s Fourth Request at https://cms.powerauthority.on.ca/sites/default/files/page/CHP%20IV%20RFP%20%28Posted%20on %20Aug%2031 %202011%29.pdf.
Successful Implementation Approach: Selling Excess Energy
Based on the state's plan to implement PURPA:
o CHP Technical Qualification Criteria (system size and capacity)
o Use contracts and standard prices
o Enable position adder to avoid investment in T&D
Feeding Rates and Variations:
o CHP Technical Qualification Criteria (system size and capacity)
o Use standard contracts
o Pricing based on avoidable cost rates for specific technologies (i.e. renewable energy)
Competitive procurement process:
o Establish a standard quotation procedure for small cogeneration plants.
o Competitive orders for large cogeneration plantshttps://cms.powerauthority.on.ca/sites/default/files/page/CHP%20IV%20RFP%20%28Posted%20on%20Aug%2031%202011%29.pdf
How much energy is needed to refine aluminum? ›
Aluminium production is energy intensive. About 17,000 kWh of electricity are required to produce 1 tonne of aluminium.What is the net zero by 2050 pathway? ›
The Net Zero Emissions by 2050 Scenario (NZE) is a normative IEA scenario that shows a pathway for the global energy sector to achieve net zero CO2 emissions by 2050, with advanced economies reaching net zero emissions in advance of others.What is the roadmap for decarbonization? ›
The Industrial Decarbonization Roadmap focuses on five of the highest CO2-emitting industries where industrial decarbonization technologies can have the greatest impact across the nation: petroleum refining, chemicals, iron and steel, cement, and food and beverage.What is net zero roadmap? ›
A Net Zero Roadmap identifies the key programmes of work needed for your business to achieve net zero. Within each programme it identifies the key projects that will be needed and the time period over which they will be run.How much energy is required to produce 1 ton of copper? ›
As depicted in Fig. 7, the specific electricity demand per ton of produced copper is currently about 12.0 GJ/t of copper (Cu) in both the concentrator and the LS-SX-EW processes.How many BTU does it take to melt aluminum? ›
Energy Required to Melt Aluminum
So, 500 Btu/pound are required to reach a casting temperature of 1370°F (743°C).
The group of world-renowned climate experts explain how, even if countries hit net zero by 2050, CO2 concentrations already in the atmosphere will leave “little to no room for manoeuvre”, and that there is only a 50% chance of holding global temperatures at 1.5°C above pre-industrial levels.What does net zero by 2030 mean? ›
It is international scientific consensus that, in order to prevent the worst climate damages, global net human-caused emissions of carbon dioxide (CO2) need to fall by about 45 percent from 2010 levels by 2030, reaching net zero around 2050.Which country has net zero by 2050? ›
Sweden and Germany have legally binding net zero targets for 2045. France, Denmark, Spain, Hungary and Luxemburg have set theirs for 2050. Japan, Korea, Canada, and New Zealand have passed laws committing to achieving net zero by 2050 while Ireland, Chile and Fiji have proposed legislation.How do I decarbonize my portfolio? ›
Steps to get started
We believe there are three practical steps to improving the portfolio from a climate perspective (taken in the following order): Adjust long-term assumptions for climate change. Improve the temperature alignment of the active components. Improve the temperature alignment of the passive components.
What are the three main decarbonization strategies? ›
Deep decarbonization rests on three pillars: energy efficiency and conservation measures, production of low carbon electricity, and fuel switching from high to low carbon energy carriers. Electricity plays a pivotal role in decarbonization.Which sectors are hard to decarbonize? ›
According to the Brookings Institution, “Steel, cement and chemicals are the top three emitting industries and are among the most difficult to decarbonize.”Is net zero by 2050 realistic? ›
Reaching net zero earlier in that range (closer to 2050) avoids a risk of temporarily "overshooting," or exceeding 1.5 degrees C. Reaching net zero later (nearer to 2060) almost guarantees surpassing 1.5 degrees C for some time before global temperature can be reduced back to safer limits through carbon removal.What is the difference between net zero and carbon neutral? ›
Net zero is similar in principle to carbon neutrality, but is expanded in scale. To achieve net zero means to go beyond the removal of just carbon emissions. Net zero refers to all greenhouse gases being emitted into the atmosphere, such as methane (CH4), nitrous oxide (N2O) and other hydrofluorocarbons.Does net zero still exist? ›
NetZero is an Internet service provider based in Woodland Hills, Los Angeles, California.How much copper is needed for EV? ›
The More Electric, the More Copper
Conventional gas-powered cars contain 18 to 49 lbs. of copper while a battery-powered EV contains 183 lbs.
Generators use 1,900 pounds of copper in the 1.5MW Wind Turbine. The shaft from the wind-driven blades is connected to the nacel-located generator, and drives the generator to produce electricity. The generator is then connected by cables to the switchgear, and to the step-up transformer.How much copper is needed to make an electric car? ›
A typical hybrid can have as much as anywhere from 85 to 132 lbs of copper, while plug-in electric cars can have about 182 lbs of copper on average.What metal can you melt on a stove? ›
Zinc is a good metal for a kid to use for casting. It's easily available at a scrap metal dealer (at least it used to be) for next to nothing. It melts at a low enough temperature that you can melt it on the stove, with effort, or with a propane torch. And it's quite non-toxic, certainly far less toxic than lead.Can you melt aluminum foil on a stove? ›
The melting point of aluminum is 660.32 °C or 1220.58 °F. This is much higher than the heat produced by an oven or grill (which is why aluminum is great for cookware), but lower than the melting point of iron (1535°C or 2795 °F) or stainless steel (around 1500 °C or 2750 °F).
What torch can melt aluminum? ›
Aluminum has a low melting point, so you can easily melt it using a propane torch or a DIY foundry.What is getting to zero 2030? ›
The Getting to Zero Coalition is an industry-led platform for collaboration that brings together leading stakeholders from across the maritime- and fuels value chains with the financial sector and others committed to making commercially viable zero-emission vessels a scalable reality by 2030, towards full ...How long would it take for us to get to net 0? ›
The Long-Term Strategy shows that reaching net- zero no later than 2050 will require actions spanning every sector of the economy. There are many potential pathways to get there, and all path-ways start with delivering on our 2030 Nationally Determined Contribution.How will us reach net zero? ›
For example, President Biden's Federal Sustainability Plan directs the U.S. government to achieve net-zero emissions across its operations by 2050 by transitioning Federal infrastructure to zero-emission vehicles and energy efficient buildings powered by carbon pollution-free electricity.Is net zero really net zero? ›
We've all heard the term net zero, but what exactly does it mean? Put simply, net zero refers to the balance between the amount of greenhouse gas (GHG) that's produced and the amount that's removed from the atmosphere.How many countries have committed to net zero? ›
As of March 2022, 33 countries and the European Union have set such a target, either in law or in a policy document.What is the biggest carbon emitter? ›
Transportation (28% of 2021 greenhouse gas emissions) – The transportation sector generates the largest share of greenhouse gas emissions. Greenhouse gas emissions from transportation primarily come from burning fossil fuel for our cars, trucks, ships, trains, and planes.What country has no carbon emissions? ›
Bhutan has a small population (approximately 784,574 as of Jan. 2023) and is sparsely developed, which reduces the demand for electricity, food, and other resources whose production and distribution can generate carbon emissions.Which country is co2 free? ›
Mainly because of its extensive forests, covering 70% of the land, the Kingdom is able to absorb more carbon dioxide than it produces. How did Bhutan get here and how can the country be an example for the rest of the world? Bhutan is both the happiest and also the greenest country in the world.Is China going net zero? ›
China's net-zero transition pathway
derive more than 80% of its energy from non-fossil fuels by 2060. This will require coal, oil and gas consumption to peak by 2025, 2030 and 2035 respectively, energy efficiency to continue to improve until 2035, and carbon capture, utilisation and storage to scale up.
Can you make money from carbon capture? ›
Producing and selling carbon offsets is finally becoming a lucrative business in the United States, and first movers will have a huge advantage. Small farmers, ranchers, and landowners can earn additional revenue by optimizing their operations to produce carbon offsets.What is the best way to invest in carbon capture? ›
One of the best ways to invest in carbon capture is through Occidental Petroleum, one of the world's largest oil and gas producers. Occidental Petroleum is a US oil and gas firm based in Texas founded in 1920.How do I withdraw my savings from carbon? ›
- Tap on the menu at the top left of your Carbon app,
- Tap on investment,
- Select the desired investment you would like to liquidate,
- Tap on the three dots at the top right of your Carbon app and.
- Tap liquidate.
One strategy for decarbonization of heating loads is to switch (in all climates) away from gas, propane, or oil-fired appliances, to electric heat pumps, which, combined with adding a lot more wind and solar to the electric grid, would result in zero-carbon heating.What are the 2 ways we can achieve decarbonization? ›
- Electrification with storage. Renewable energy has helped dramatically reduce the carbon intensity of electricity across the globe. ...
- Heat pumps. ...
- Waste heat recovery. ...
- Green gas and biomass. ...
- Hybrid heating. ...
- Hydrogen. ...
There are four main types of low-carbon energy: wind, solar, hydro or nuclear power.Which sector is easiest to decarbonize? ›
The electric power sector is often regarded as the “easiest” sector to decarbonize, compared with highly diffuse sectors such as transportation, because of the large number of solutions available and the relative ease of transitioning a relatively limited number of generally centralized assets.Why is net zero by 2050? ›
As part of the Paris agreement, countries around the world agreed to pursue efforts to limit global warming to well below 2 degrees Celsius, preferably to 1.5 degrees Celsius, compared to pre-industrial levels. To achieve this, countries must reduce their greenhouse gas emissions to 'net zero' by around 2050.What vehicles are zero emission? ›
Zero-emission and near-zero emission vehicles such as battery-electric vehicles, hydrogen fuel cell vehicles and plug-in hybrid electric vehicles have ultra-low smog-forming and GHG pollutants, even over the life of a vehicle, which includes the vehicle's fuel production emissions.How much will it cost to reach net zero by 2050? ›
$125 trillion of climate investment is needed by 2050 to meet net zero, with investment from now until 2025 needing to triple compared to the last five years to put the world on track.
What big companies are carbon neutral? ›
- Compensating for greenhouse gas and carbon dioxide emissions is the goal of a carbon offset programme. ...
- 10: Green Mountain Energy. ...
- 9: Disney. ...
- 8: General Motors. ...
- 7: Delta. ...
- 5: Cemex. ...
- 4: Microsoft. ...
- 3: Shell.
The big difference between GreenPower and carbon neutral energy, is that the GreenPower program is Australia-based, while carbon offsets can be applied anywhere.What is better than carbon neutral? ›
Climate positive means that activity goes beyond achieving net-zero carbon emissions to create an environmental benefit by removing additional carbon dioxide from the atmosphere. Carbon negative means the same thing as “climate positive.”Does anyone still use NetZero? ›
Today, the scrappy startup from 1998 is barely what it was. I say "barely," because NetZero's parent company, United Online, still claims 595,000 subscribers through its paid Internet service, down from 7 million in 2001. And now it's staging a comeback.Why is net zero now? ›
The science of 'carbon budgets'
Climate science is clear that, to a close approximation, the eventual extent of global warming is proportional to the total amount of carbon dioxide that human activities add to the atmosphere. So, in order to stabilise climate change, CO2 emissions need to fall to zero.
By 2050, global industrial energy consumption reaches about 315 quadrillion British thermal units (Btu).How much energy does it take to produce 1 ton of aluminium? ›
15,700 kWh of electrical energy are required to produce one tonne of primary aluminium.How much energy does alumina refinery use? ›
The average energy consumption for all refineries is approximately 13.8 GJ/tonne of calcined alumina, with a range from 7.2 to 43 GJ/tonne. The average energy consumption of Bayer refineries is 12 GJ/tonne and ranges between 7.2 and 21.9 GJ/tonne.How much energy does an aluminium smelter use? ›
The smelting of aluminium is the most energy-intensive stage of aluminium production, with each tonne of aluminium requiring around 15 MWh of electricity.How much energy is required to melt 1 ton of aluminium? ›
Power usage can vary from 400 to 550 kWh to melt a ton of aluminum depending upon the type of melter and operating practices.
How many aluminum cans make a ton? ›
An empty aluminium can approximately weighs around 17g. That means you'd need roughly 58 cans to have 1kg, & for 1ton you would need 58,928 cans.How much energy is needed to produce 1 ton of steel? ›
The energy value of the type of coal used for steelmaking is about 8 megawatt hours (MWh) per tonne. So each tonne of 'new' steel has typically required about 6 MWh in the process of getting from iron ore to a finished steel product, such as coil used for making the exteriors of cars.How much energy is in a ton? ›
A ton of TNT or tonne of TNT is a unit of energy equal to 109 (thermochemical) calories, also known as a gigacalorie (Gcal), equal to 4.184 gigajoules (GJ).Who is the world's largest alumina producer? ›
The six largest alumina producers in the world are Aluminum Corporation of China, South32 Limited, Hangzhou Jinjiang Group, Rio Tinto, Norsk Hydro ASA and Alcoa. About the product: Alumina is an oxide that is extracted from bauxite and is the basic raw material used to produce primary aluminum.Who is the largest alumina producer? ›
During the 2020 financial year, China-based Chalco was the leading alumina producing company, extracting some 14.5 million metric tons of the metal. It was followed closely by the American Alcoa, which had an output of around 13.5 million metric tons in that same year.Who is the largest exporter of alumina? ›
China is the world's leading exporter of aluminum and aluminum products. In 2021, China's aluminum exports were valued at 34.7 billion U.S. dollars, approximately 16 billion U.S. dollars more than Germany, the second-largest exporter at around 18.8 billion U.S. dollars.What is profitable ore for extraction of aluminium? ›
Aluminium ore is called bauxite. The bauxite is purified to produce aluminium oxide, a white powder from which aluminium can be extracted.Does recycling aluminum save energy? ›
The energy savings applies to all recycling sectors: Aluminum. Recycling of aluminum cans saves 95% of the energy required to make the same amount of aluminum from its virgin source. One ton of recycled aluminum saves 14,000 kilowatt hours (Kwh) of energy, 40 barrels of oil, 130.How much will aluminium smelter project cost? ›
1 MTPA capacity 5th Stream Alumina Refinery brownfield project at existing Alumina Refinery at Damanjodi Estimated project cost: Rs. 5,540 cr, Expected Completion: April, 2021.How many kWh does it take to melt steel? ›
To produce a ton of steel in an electric arc furnace requires approximately 400 kilowatt-hours (1.44 gigajoules) per short ton or about 440 kWh (1.6 GJ) per tonne; the theoretical minimum amount of energy required to melt a tonne of scrap steel is 300 kWh (1.09 GJ) (melting point 1,520 °C (2,768 °F)).
How do you melt aluminum with electricity? ›
Fill your crucible with some pieces of aluminum and place it on the element. Place the thermocouple probe near the top of the crucible and put the lid on the furnace. Plug in the power cord and monitor power and temperature as the aluminum heats up and melts.How much power is needed to melt a metal? ›
A good rule of thumb is 25 kWh of useful energy to heat each ton of material by each 100ºC. (1) Thermodynamics 101. Heating and melting materials requires energy, inducing particles to vibrate more (specific heat) and ultimately to break the bonds that hold them together as a solid or liquid (latent heat).