Examining hydro's future role8 July 2008
A recent workshop in the US helped to redefine hydro power’s role in the changing generation mix. Report by Tom Key and Patrick March
With increasing pressure to reduce carbon emissions from the production of electricity, the role of hydro power in the generation mix is changing. Existing facilities may need to be operated in different ways, and opportunities may arise to modernise and expand these. To take advantage of such changes, hydro power operators and owners will need to stay abreast of emerging legislation, current incentive programmes and market opportunities.
In January 2008, the electric-power-research-institute (epri) sponsored a two-day workshop in the US entitled Hydropower in a Carbon-Constrained Future. The workshop was the first major North American workshop to bring together hydro power managers and hydro-environmental professionals to examine the position of hydro among other generation technologies, and explore opportunities related to the control of carbon emissions.
The workshop brought together individuals with diverse viewpoints and experiences of using hydro for emissions reduction. Participants included operators, owners, developers, consultants, hydro equipment vendors, regulators, policy specialists, scientists, and power marketers. Topics covered four broad areas: US climate policy and proposed climate related legislation; environmental review and certification protocols; carbon market approaches; and incentive programmes.
Two presentations looked at US climate policy and climate related legislation and their possible impacts for hydro generation.
Dr Thomas Wilson, a senior technical leader in EPRI’s climate change business area, provided an overview of carbon emissions related to the electric industry. Wilson noted that emissions come from all sectors (residential, industrial, commercial and transportation), with the US electric industry contributing about 40%. Stabilisation will require large end-use efficiency gains and massive deployment of low and non-emitting electric generation technologies, as illustrated in Figure 1.
CO2 policy can have a dramatic effect on generation costs, power prices and cash flows. For a coal-fired plant, a US$10/ton cost of CO2 is approximately equal to the plant’s investment cost. Also, the CO2 value will affect the market price and new revenue for each hour of dispatch. Revenues go up for non-emitters, such as nuclear and hydro power, and revenues for coal-fired plants decrease significantly, while the marginal cost set by natural gas increases. The implications of carbon economics for hydro are that a carbon price will increase power prices and net revenues for hydro assets, and there will be an increased (perhaps substantially increased) incentive to invest in efficiency improvements and extensions of capacity.
Wilson also reviewed US climate policy proposals focused on cutting emissions below historic levels. In the near term, by 2012, the primary way to cut emissions will be to build natural gas combined-cycle plants to displace coal, simple-cycle gas turbines and oil. For this to happen, a very high CO2 price, above US$70/ton, would be needed to cover the cost difference between coal and gas. In the longer term, new nuclear plants and technologies for carbon capture with storage will play a major role, and the cost differential will be about US$60/ton. Wilson noted that anticipated US climate policies may dramatically affect the economics of hydroelectric generation, as illustrated in Figure 2. Particularly in the near term, small increases in hydro power production may have a high value.
Jeff Leahey, senior manager of government and legal affairs for the national-hydropower-association (nha), summarised two areas of recent major US legislative activity. His first focus was the Energy Independence and Security Act of 2007. To get this act passed, a number of provisions that would have benefitted hydro power were taken out due to the ‘pay-as-you-go’ criterion. The placed-in-service deadline for the production tax credit (PTC) remains 1 January 2009, which does not allow the time needed for most hydro projects to bring energy online. The clean renewable energy bonds (CREBs) programme was put on hold, with many hydro projects not receiving money due to funding limits. A federal renewable portfolio standard (RPS), which included ocean, tidal, and incremental hydro power but excluded existing hydro, was one of several provisions dropped from the final bill.
Leahey also reviewed recent efforts for CO2 allowance legislation, using the Lieberman-Warner Climate Security Act (S.2191) as the main example. This proposed bill provides economy-wide caps on six greenhouse gas (GHG) emissions from US electric power, transportation and manufacturing sources. The cap starts at the 2005 level in 2012 and then lowers year-by-year, ultimately reaching a 70% reduction in emissions from the covered sources by 2050.
Of relevance to hydro power, emission allowances are allocated based on historic emissions, which would make hydro ineligible to participate in the market. New entrants only include fossil-fueled generation. However, hydro power resources may be able to participate in the offsets auction programme under S.2191. The proposed act provides for 25% of auction proceeds to go to a sustainable energy programme, but only incremental hydro power and ocean waves are included. Thirty two percent of auction proceeds go to zero or low-carbon technology deployment, which may represent an opportunity for hydro.
Environmental review and certification protocols for hydro power were also analysed. Fred Ayer, executive director of the Low Impact Hydropower Institute (LIHI), noted that LIHI certification aims to identify those existing hydro power dams whose impacts are low relative to other hydro facilities, although low impact does not mean no impact. Certification applies only to existing dams.
LIHI criteria evaluate river flows, water quality, fish passage and protection, watershed protection, threatened and endangered species protection, cultural resources protection, recreation use and access. LIHI certification helps to assure customers of environmental credibility and provides facility owners and operators with a basis for seeking price premiums for existing hydro.
Ayer also pointed out that LIHI certification provides a market incentive to reduce the impacts of hydro power generation, establishes a credible and accepted standard for consumers to use in evaluating hydro power, and introduces a market ‘carrot’ to address improvements at hydro dams. The certification complements, rather than replaces, Federal Energy Regulatory Commission (FERC) regulation. He reported that LIHI has certified a total of 31 hydro power projects with 63 dams in 21 states, for a combined installed capacity of 1988MW.
In a hypothetical example, Ayer described a river flow criterion where a facility releases 1.13m3/sec, but this limits fish habitat. The state fish and game agency and the US Fish and Wildlife Service recommend 2.27m3/sec. FERC orders 1.7m3/sec for a new operating licence but LIHI certification requires 2.27m3/sec
In a discussion about other certification programmes, Ayer identified several differences between the approaches taken by LIHI and ASTM International (formerly known as the American Society for Testing and Materials). LIHI compares hydro to hydro, and the voting members of its governing board are almost exclusively representatives from environmental organisations. The ASTM approach, based on life-cycle analysis, compares hydro to all other generation options.
Karin Seelos, senior advisor for strategic environmental issues at Hydro-Québec’s strategic planning and government relations branch, discussed the potential role of hydro power in the context of climate change mitigation. She noted that hydro power currently offsets 2.1 B tons of CO2e per year and has the potential to offset a further 7B. Each year, current hydro power generation avoids GHG emissions equivalent to the combined emissions of all cars on earth. If 80% of the remaining economically feasible potential is developed, the contribution of hydro could be multiplied by approximately three.
Seelos also pointed out that climate change will increase risks associated with floods and droughts. In this context, dams provide enhanced water management opportunities, and reservoirs offer increased freshwater storage capacity. She also described the international-hydropower-association’s sustainability guidelines and sustainability assessment protocol as the most comprehensive certification standard for hydro power projects, taking into account not only environmental considerations but also critical social and economic issues in a sound, sustainable development approach.
The current science on reservoir emissions and hydro’s potential supporting role for wind power deployment were also discussed by Brennan Smith, programme manager for wind and water power technology at Oak Ridge National Laboratory.
The idea that hydro reservoirs could be net sources of GHG emissions was first raised in the early 1990s. Research suggests that, in the vast majority of cases, reservoirs do not have significant net emissions. However, a study in 1993 found that GHG production per MWh from reservoirs is not zero. Another study, summarising the state of research in 1996, concluded that cold climate GHG emissions per MWh are 30 to 60 times less than fossil fuel generation alternatives. However, the scientific basis for making claims regarding emission levels is far from robust.
Only 10 to 15 years of monitoring data has been accumulated, and long-term monitoring is needed to include the effects of drought and floods. Overall, this research needs much more scientific work to enable hydro power interests to make realistic, defensible claims that are not unduly conservative. Potentially at risk are green certifications, tradable emissions credits, PTCs, and utility investments in hydro improvements. Smith noted that considerable effort needs to be devoted to advancements in measurement technology and predictive models.
Smith also discussed US wind power resources and variability and provided an overview of how hydro can support the addition of wind power generation within the national grid. He made reference to several wind integration studies that have been completed. Although it is generally recognised that hydro can often support the addition of wind power, the specific circumstances within a balancing area require careful assessment, and hydro constraints need to be taken into account.
Carbon market approaches
Several speakers discussed opportunities for hydro power facilities in carbon markets.
Scott Zimmerman, director of energy at C-Lock Technology, looked at the current status of carbon markets in the US. He described the market as voluntary but transitioning to regulated. In the US during 2006, about US$91M in carbon trades occurred in the voluntary market. Forty states have GHG reporting registries. Thirty states have climate action plans. Two states have cap or offset requirements, and 14 states have legislation in progress.
Current federal GHG legislative initiatives being drafted employ a variety of strategies, including a cap on point emitters, taxes on distributed emitters, conservation or efficiency incentives (tax breaks), and renewable portfolio requirements. Market-based approaches are favoured over command and control.
Marcus Krembs, director of GHG programmes for Sterling Planet, described opportunities in renewable energy certificates (RECs). RECs are environmental commodities that represent certification of proof that a megawatt of electricity was generated from an eligible renewable energy source. RECs can be used as a debit against generators’ scope 2 (indirect) CO2 emissions to mitigate their carbon footprints. In voluntary markets, customers voluntarily pay more for renewable energy, and 22 voluntary programmes are available in six states. These markets have seen the number of customer participants grow by nearly 40% per year since 1999 and are projected to reach more than US$6B. In mandated markets, which are expected to reach US$53B, RECs are sold to utilities to enable them to meet Renewable Portfolio Standards (RPS). Eligibility for voluntary markets is open to hydro power from new generation capacity on a non-impoundment, or new generation capacity on an existing impoundment that meets one of the following criteria:certified by LIHI; a run-of-river facility = 5MW; and a turbine in a pipeline or irrigation canal.
Krembs provided the example of a small hydro project in Alaska. The 6MW Power Creek project, which began commercial operation in 2002, has now been deemed eligible for the Green-e Energy certification programme in the US. It is seeking to provide the certified green power supply for the city of Cordova, Alaska, under the city’s Green Power Community Challenge (launched in June 2008). Sterling Planet, in partnership with Cordova Electric Cooperative, will cooperatively seek non-residential end-user demand for the green power product in consideration of the EPA Green Power Partnership goal of 3% of total end-user demand in the city.
Gregg Carrington, director of external affairs of the Chelan County Public Utility District (PUD), described his utility’s participation in the Chicago Climate Exchange (CXX). Launched in 2003, the CXX is North America’s only and the world’s first legally binding rules-based GHG reduction and trading system.
Since 1999 Chelan has made a number of operational and efficiency improvements to its 1300MW Rocky Reach dam, which is located on the Columbia river near the centre of Washington State. The work which has been carried out includes project modernisation, control system and optimisation improvements and reduced spill. These have created additional capacity and increased efficiency. Approximately 1.75M additional megawatt hours generated at the dam, as a result of operational and equipment efficiency improvements since 2003, are eligible to be traded as carbon offset credits. These are estimated to be worth US$1.5–$3M at recent prices. Chelan PUD has full flexibility to decide whether to market its offsets, which qualify to replace the equivalent of about 700,000 metric tons of CO2.
Eric Barreveld, policy and communications associate with Enel North America, recounted the utility’s use of state financial grants to increase incremental hydro production. He noted that approximately 38 grant programmes exist in 18 states to promote renewable energy production. Many states are using the proceeds from RPS penalties to provide incentives for renewables and efficiency programmes. In Massachusetts, for example, hydro power is receiving monetary assistance for completing a variety of projects, including additions, upgrades, rewinds, replacements and refurbishments.
Barreveld described a multi-million dollar 2007 Enel project to install an inflatable flashboard system along the entire length of a 274m dam, which would incrementally increase hydro production, lessen the dam’s environmental impact, and increase safety. The Massachusetts Technology Collaborative (MTC) awarded ENEL US$1.1M for the project. The MTC also sponsors the Small Hydropower Initiative, which is a US$3M fund for the development and improvement of facilities in the region of the Independent System Operator–New England. The fund is limited to projects under 30MW and cannot increase any existing impoundment.
In addition, Barreveld also offered the example of Enel’s Summersville (Gauley) hydroelectric project, an 80MW scheme in Summersville, West Virginia. The facility was certified by the LIHI and eligible for RECs from three compliance markets (Maryland, Pennsylvania, and the District of Columbia). Achieving LIHI certification also allows the project to participate in the national market and makes the project Green-e eligible for retail sales.
Presentations were made on incentive programmes available to hydro power, including renewable portfolio standards (RPS), production tax credits (PTCs), and clean renewable energy bonds (CREBs).
David Moore, an attorney with Troutman Sanders LLP, reviewed current state and proposed federal RPS’s. He noted that 25 of 26 state RPS include hydro. Fifteen of 25 have restrictions related to size (large and mid-sized hydro are not favoured in some states) or whether the facility is new construction, diversion, incremental hydro, or second-class renewable. Currently proposed federal RPS legislation, such as the Climate Security Act and the Renewable Energy and Energy Conservation Act, include incremental hydro only.
Patrick March, principal consultant for Hydro Performance Processes outlined opportunities for incremental hydro power that would make the facilities eligible for PTCs. He said that conventional opportunities include improvements to existing turbines and generators, new turbines and generators, new capacity for non-hydroelectric dams, and other improvements such as new transformers. Often overlooked, however, are innovative opportunities, including avoidable losses (such as trash-raking improvements), optimisation improvements (such as optimisation-based automatic generation control), and best practices improvements.
Dave Culligan, director of hydro development for Brookfield Power Corporation’s eastern US generation development group, described Brookfield’s utilisation of existing incentive programmes for hydro power projects. He noted that in 2005, Brookfield initiated programmes in direct response to both the New York State RPS (NY-RPS) and the Federal Energy Policy Act of 2005 to capture incentives at existing assets. To date, ten individual incremental projects are moving forward, representing about 15MW and 55,000MWh of incremental capacity and energy. Between these and other past qualifying upgrades, 13 certifications were received under the NY-RPS incentives (US$8-10/MWh), and two projects were certified under federal PTC incentives, with more pending.
Tom Brendiar, manager of bank and investor relations at Oglethorpe Power Corporation, discussed his utility’s use of CREBs. Oglethorpe is an electric membership cooperative, headquartered in Atlanta, Georgia. Oglethorpe’s 848MW Rocky Mountain pumped storage facility in northwest Georgia has been operable since 1995. As part of a 10-year major overhaul at the facility, pump-turbine runners are being upgraded on all three units, providing increased capacity of about 180MW. The total cost is US$35M, of which US$26M is Oglethorpe’s share. The utility plans to finance US$24M of the total using CREBs.
The 2008 workshop was very informative and successful in bringing key players together. EPRI will host a follow-up workshop in January 2009. Interested parties should contact Tom Key ([email protected]).
Tom Key is the technical leader of EPRI’s renewable and hydro power programme ([email protected]), and Patrick March is the president of Hydro Performance Processes Inc and is a consultant to EPRI ([email protected]).
|Glossary of terms|
CREB (clean renewable energy bond) – financial instruments established by the Energy Policy Act of 2005 to provide cooperatives and public power systems with an incentive programme, comparable to PTCs, for financing renewable generation projects. CREBs are issued as zero coupon bonds with the bondholder receiving a federal income tax credit. Qualifying projects include wind, landfill gas, solar, geothermal, biomass and hydro power.
Incremental hydro – an increase in generation at an existing hydro power facility, achieved through efficiency improvements. The term is typically used in conjunction with the PTCs.
Low-impact hydro – hydro power facility certified by the Low Impact Hydropower Institute. (www.lowimpacthydro.org)
PTC (production tax credit) – inflation-adjusted federal tax credit for electricity produced using qualifying renewable energy sources. Section 1301 of the Energy Policy Act of 2005 amends the US Tax Code (Section 45) to apply the credit to incremental production gains from hydro power efficiency improvements, or capacity additions to existing hydroelectric facilities placed into service after 8 August 2005 and before 1 January 2009; and to turbines or other generating devices placed into service at existing non-hydroelectric dams during the same period.
REC (renewable energy credit) – environmental commodities, tradable in voluntary markets, that represent some certification of proof that 1MWh of electricity was generated from an eligible renewable energy source. RECs are sold and traded, and the REC owner can claim to have purchased renewable energy.
RPS (renewables portfolio standard) – local, state, or federal mandate requiring that a certain percentage of total energy generation or consumption be provided by renewable energy sources, typically on a specified schedule.