Memorandum. Incremental Benefits and Costs to New England of Large-Scale Hydroelectric Energy Imports

Transcription

1 Memorandum Incremental Benefits and Costs to New England of Large-Scale Hydroelectric Energy Imports Prepared for the Massachusetts Department of Energy Resources December 31, 2013 (Preliminary Discussion Draft) AUTHORS: Rick Hornby Elizabeth A. Stanton, PhD Bob Fagan Max Chang David White, PhD Patrick Knight Patrick Luckow 485 Massachusetts Avenue, Suite 2 Cambridge, Massachusetts

2 Contents EXECUTIVE SUMMARY... 1 INTRODUCTION NEW HYDROELECTRIC ENERGY IMPORTS ARE A POTENTIAL SOURCE OF SIGNIFICANT ADDITIONAL CLEAN ENERGY TO NEW ENGLAND, WITH HYDRO QUEBEC (HQ) REPRESENTING THE GREATEST POTENTIAL THROUGH NEW HYDROELECTRIC ENERGY IMPORT PROJECTS CAN BE DEVELOPED THROUGH SEVERAL DIFFERENT APPROACHES. EACH APPROACH HAS DIFFERENT IMPLICATIONS FOR THE QUANTITY OF INCREMENTAL CLEAN ENERGY THAT WOULD BE DELIVERED TO NEW ENGLAND, AS WELL AS FOR THE COST OF THAT INCREMENTAL CLEAN ENERGY ADDING SIGNIFICANT QUANTITIES OF CLEAN ENERGY TO THE NEW ENGLAND ENERGY MIX WOULD PROVIDE SUPPLY DIVERSITY AND GREENHOUSE GAS REDUCTION BENEFITS WITH MINIMAL IMPACT ON AVERAGE ENERGY BILLS. THE MAGNITUDE OF THOSE BENEFITS, AND THE ASSOCIATED INCREMENTAL COST TO THE REGION, WILL DEPEND ON THE APPROACH THROUGH WHICH EACH PROJECT IS DEVELOPED AND THE MAGNITUDE AND MIX OF CLEAN ENERGY ASSOCIATED WITH THE PROJECT MODELING ASSUMPTIONS AND METHODOLOGY APPENDIX A: REPRESENTATIVE TRANSMISSION PROJECTS APPENDIX B: NEW ENGLAND BILL IMPACTS... 37

3 Executive Summary This memorandum discusses the significant increments of new hydroelectric energy available to New England by 2020 and beyond, discusses the major policy options for facilitating the addition of those increments to the region s energy mix, and estimates the main quantitative benefits and costs to New England of adding those increments. All dollar amounts in this memo are expressed in 2013 dollars, unless noted otherwise. The key conclusions from our analyses are as follows: 1. New hydroelectric energy imports are a potential source of significant additional clean energy to New England, with Hydro Quebec (HQ) representing the greatest potential through This memorandum defines significant additional clean energy as baseload quantities of 1,000 MW and above. 1 HQ and Nalcor Energy are the two potential sources of significant incremental hydroelectric imports to New England. 2 HQ appears to have the largest potential through 2020 because of its ability to support significant incremental imports within that timeframe with little or no upgrades to its existing transmission infrastructure. It does not appear that Nalcor Energy will have the ability to support baseload imports of 1,200 MW or greater at the New Brunswick border until after Imports of Newfoundland hydroelectricity of that magnitude hinge upon completion of major new transmission lines to deliver that power into Nova Scotia, scheduled to be completed in 2017, and upgrades to the Nova Scotia / New Brunswick transmission interface. It may be possible to achieve a material increase in hydroelectricity imports through the existing HQ Phase II line. However, even with incremental imports on that line New England would still benefit from incremental imports of clean energy resources via new transmission lines. 3 Other than a possible new High Voltage Direct Current (HVDC) transmission line through New Hampshire, the representative transmission paths for large incremental imports for which there are public cost estimates are, in order of increasing cost, a path through Vermont and two separate paths through Maine. Normalized capital costs for 1,200 MW lines range from $1.8 to $3 billion depending on the transmission path, and expected in-service dates range from 2018 to Synapse recommends that the Commonwealth ask HQ and ISO-NE to examine the feasibility and cost of a HVDC line to deliver imports from Quebec into the southwest corner of Maine 1 The transmission cable/converter systems being considered for New England are considered HVDC Light. They are often listed at maximum capacities of 1,200 MW but local conditions/local system limitations can limit them to 1,000 MW. 2 HQ and Nalcor Energy are provincial crown corporations of Quebec and Newfoundland respectively. 3 Clean Energy Resources in this document refers to hydro resources greater than 30 MW and Renewable Portfolio Standard (RPS) Class I eligible resources like wind and solar energy. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 1

4 and then parallel to the Maine / New Hampshire border, terminating at an appropriate interconnection with the existing ISO-NE transmission system in southern Maine or New Hampshire. Imports from such a line might require upgrades to the existing transmission system in order to allow delivery to the New England hub New hydroelectric energy import projects can be developed through several different approaches. Each approach has different implications for the quantity of incremental clean energy that would be delivered to New England, as well as for the cost of that incremental clean energy. Hydroelectric import projects can be developed through a range of financing and contractual arrangements, which can generally be grouped into one of two basic approaches. The two broad approaches differ according to who funds construction of the U.S. transmission line(s) and who determines the quantity of clean energy to sell into the New England energy market. This memorandum characterizes the approaches as Merchant Development and Merchant Energy Development plus Regional Transmission Funding. Under the first approach the project developer funds all supply and transmission in both Canada and the United States. Under the second approach the project developer funds of all project components required to deliver supply into transmission in New England and New England ratepayers ultimately fund the new transmission lines and associated upgrades to existing transmission. This memorandum analyzes the benefits and costs of developing projects under these approaches based on two major assumptions. First it assumes that under either approach the project developer would bear 100 percent of the cost of supplying the incremental hydroelectricity at the Canadian border in exchange for the revenues the developer would receive from selling that energy into the New England wholesale energy market as a price-taker. Second, it assumes that under the Merchant Development approach project developers would only sell hydroelectric energy in peak price periods while under the Merchant Energy Development plus Regional Transmission Funding approach they would agree to sell that hydroelectricity in most hours of the year. Thus, our analyses model the transmission lines operating at a 50- percent capacity factor (cf) under the former approach and at a 90-percent cf under the latter approach. Our study also provides an overview of policy levers to promote large-scale hydroelectricity imports. These levers include FERC-approved tariffs, coordinated regional procurement among states, and a new Renewable Portfolio Standard sub-tier. 3. Adding significant quantities of clean energy to the New England energy mix would provide supply diversity and greenhouse gas reduction benefits with minimal impact on average energy bills. The magnitude of those benefits, and the associated incremental cost to the region, will depend on the approach through which each project is developed and the magnitude and mix of clean energy associated with the project. 4 The New England hub is located in west-central Massachusetts. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 2

5 Synapse estimated the main quantitative benefits and costs to New England of adding increments of clean energy under a Merchant Development approach and under a Merchant Energy Development plus Regional Transmission Funding approach. This memorandum evaluates the following five possible Cases under each of those two development approaches: 1,200 MW Hydro Case (1,200 MW new transmission line delivering hydroelectricity starting in 2018); 2,400 MW Hydro Case (1,200 MW new transmission line starting in 2018 plus second 1,200 MW line starting in 2020); 2,400 MW Hydro plus Wind Case (2,400 MW Hydro Case plus new 1,200 MW line accessing wind in Northern Maine and hydro imports, operational 2020); 2,400 MW Hydro plus Pipeline Case (2,400 MW Hydro Case plus 0.4 Bcf/day additional pipeline capacities by 2017 and another 0.6 Bcf/day by 2018); and 3,600 MW Hydro Case (1,200 MW new transmission line starting in 2018, a second 1,200 MW line starting in 2020, and a third 1,200 MW line starting in 2022). The benefits and costs to New England of each possible Case are measured relative to a Reference Case that assumes no new increments. The supply diversity and carbon emission reduction benefits of each Case are greater under the Merchant Energy Development plus Regional Transmission Funding approach than under the Merchant Development approach because of our assumption that more hydroelectricity will be imported under that approach. In 2020 the net dollar benefits of the 2,400 and 3,600 MW Cases are less under the Merchant Energy Development plus Regional Transmission Funding approach. However, by 2030 the net dollar benefits of all five Cases are greater under the Merchant Energy Development plus Regional Transmission Funding approach. All of the Cases under each of the two approaches offer benefits in terms of supply diversity, greenhouse gas reductions, wholesale energy prices and retail bills. For example, the key benefits of the 2,400 MW Hydro Case under the Merchant Energy Development plus Regional Transmission Funding approach are: o o o Supply diversity: New England would reduce its dependence on natural gas for electric generation substantially. For example, by 2020 its dependence would reduce from 51 percent in the Reference Case to 42 percent in the 2,400 MW Hydro Case, a 19-percent. Greenhouse gas reductions: New England would reduce its carbon dioxide emissions substantially. For example, by 2020 regional emissions would reduce from 33.8 million metric tons in the Reference Case to 27.8 million metric tons in the 2,400 MW Hydro Case, an 18-percent reduction. Wholesale energy prices: New England could see somewhat lower wholesale energy prices. For example, by 2020 average annual energy prices under the 2,400 MW Hydro Case could be approximately 5 percent lower than under the Reference Case. The reduction in wholesale energy prices relative to the Reference Case decline by Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 3

6 o Retail bills: New England ratepayers would experience minimal impacts on their average bills. By 2020 average bills could be 1 to 2 percent lower under the regionally funded approach to the 2,400 MW Hydro Case than under the Reference Case. This result is attributable to the fact that savings in energy costs due to somewhat lower wholesale energy prices outweigh the incremental cost of the new U.S. transmission lines. By 2030 the 3,600 MW Hydro Case has the greatest level of benefits of all five Cases under either of the two development approaches. The 2,400 MW Hydro plus Wind Case has the next greatest level of benefits by Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 4

7 Introduction The Department of Energy Resources (DOER) has retained Synapse Energy Economics (Synapse) to assist them in analyzing various electric sector issues on a task order basis. One task is to help DOER analyze the impacts of adding one or more increments of large-scale hydroelectric energy to the New England energy mix, as well as the major options for procuring those increments. This task is driven by Massachusetts identification of new hydroelectric energy as a potentially important resource in meeting the Massachusetts Clean Energy and Climate Plan for (CECP) goals established under the Global Warming Solutions Act 6 (GWSA). Synapse completed this task by: 1. Assessing the major sources of incremental hydroelectric energy that could be added to the region s energy mix in the next decade, and the representative transmission projects that would be required to deliver those increments. 2. Identifying major possible approaches through which new hydroelectric energy import projects could be developed and funded. This analysis identifies policy and transmission options. 3. Estimating the economic and environmental benefits to New England of adding significant increments of new large-scale clean energy, primarily hydroelectric energy imports, over the period 2013 to The major categories of benefits are increased diversity of electricity supply and reduced CO 2 emissions, while the major categories of costs are the energy, generating capacity, and transmission costs associated with those increments. The analysis measures the benefits and costs of five illustrative hydroelectric Cases relative to a Reference Case that assumes no new increments of large-scale clean energy. 5 Office of the Secretary of Energy and Environmental Affairs. December Massachusetts Clean Energy and Climate Plan for Chapter 298 of the Acts of Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 5

8 1. New hydroelectric energy imports are a potential source of significant additional clean energy to New England, with Hydro Quebec (HQ) representing the greatest potential through This section discusses the major sources of incremental hydroelectric energy that could be added to the New England energy mix between 2014 and It also discusses the representative new transmission projects that would be required in New England to deliver those increments from the Canadian border to the wholesale electric energy market hub in central Massachusetts. New England currently imports hydroelectricity from Quebec through several existing interties, the largest of which is HQ Phase II. 7 The scope of work for this engagement did not request Synapse to identify the transmission upgrades required to allow existing interties to be used to their maximum capacity, nor to estimate the resulting incremental quantity of hydroelectricity imports. Sources of Major Incremental Hydroelectric Energy This memorandum defines significant additional clean energy as baseload quantities of 1,000 MW and above, as noted earlier. The two sources of major incremental hydroelectric energy imports available to New England over the next ten years are Quebec (via HQ), and Newfoundland (via Nalcor Energy). 8 Our memo refers to hydroelectric energy imports, but it is important to note that the electricity that these sources will be exporting is actually system power rather than hydroelectric energy from specific dams. This distinction is relevant to our estimates of the CO 2 emissions per MWh associated with these imports. Hydro Quebec HQ currently exports power to New York, Ontario, New Brunswick, Massachusetts (via the HQ Phase II HVDC line) and Vermont. HQ is the largest potential source of major incremental hydroelectric exports to New England through at least 2020 because our review indicates it has the capability to produce and transmit sufficient incremental hydroelectricity to support at least two new 1,200 MW interconnections at points along the Quebec / New England border by that date. First, HQ has an existing 735 kv transmission infrastructure that delivers power from its dams in the north to its load centers in Montreal and Quebec City as well as to the U.S. border. Figure 1 shows the geographical and rough electrical 7 An intertie is the circuit that connects two or more control areas or systems. See ISO-NE glossary: 8 Nalcor Energy is a provincial energy corporation of the Government of Newfoundland and Labrador. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 6

9 schematic arrangement of HQ s system, as well as its interconnections with its neighboring provinces and with New England. Figure 1. Quebec System Map with Surrounding Regions Schematic from Hydro Quebec Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 7

10 Second, while HQ may have to invest in some modest reinforcements to its existing transmission infrastructure, it is well positioned to support major new export projects that would come online between 2018 and 2020 along its border with the United States. This position is based on our review of HQ s most recent Annual Report, its Strategic Plan, its proposals for delivery into the proposed Champlain Hudson Power Express (New York) and Northern Pass (New Hampshire) lines, and various other reports describing the outlook for exports from HQ. Based upon HQ s existing 735 kv transmission infrastructure, the most economic locations for major incremental hydroelectric imports from HQ into New England appear to be at points along Quebec s border with Vermont, New Hampshire, or southwestern Maine. Two such points are illustrated as A and B in Figure 2. In contrast, the New Brunswick / Maine border does not appear to be an economic location for a major incremental import of hydroelectricity produced in Quebec. The existing transmission systems in Quebec and New Brunswick do not appear to have the capability to support an incremental import of 1,200 MW at the New Brunswick / Maine border near Houlton, Maine for example, illustrated as point C in Figure 2. A major import of HQ hydroelectricity at that location would require HQ to transmit hydroelectricity into, and then across, New Brunswick. Our review of the existing transmission systems in HQ and New Brunswick indicates that they would each have to invest in major upgrades to their respective transmission systems in order to deliver incremental hydroelectricity in excess of a few hundred MW at the Maine / New Brunswick border. 10 Exporting hydroelectricity on the order of 1,200 MW through that connection would require an upgrade of the existing HVDC interties between Quebec and New Brunswick, and would require New Brunswick to reinforce its 345 KV system. 10 Based on WKM Report on HQ imports to Nova Scotia. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 8

11 Figure 2. Illustration of locations for incremental HQ exports to New England Point A in Figure 2 indicates the general location of potential new 1,200 MW connections with HQ, either an interconnection with New Hampshire to support the proposed Northern Pass line or an interconnection with Maine to support a transmission line that would cross Maine in parallel with the Maine / New Hampshire border, terminating at an appropriate interconnection with the existing ISO-NE transmission system in southern Maine or New Hampshire. Imports from such a line might require upgrades to the existing transmission system in order to allow delivery to the New England hub. Synapse is not aware of any discussion of a line along this path. We have identified it simply on the basis of geographic proximity. That potential path is illustrated later in Figure 4 as ME Route 3 / overland. We recommend that the Commonwealth ask HQ and ISO-NE to examine its feasibility and cost. Nalcor Energy via Maritime Link Nalcor Energy has proposed developing major new hydroelectric capacity in Labrador, north of the island of Newfoundland, and building a major transmission project to deliver that power from Labrador to Newfoundland, and then from Newfoundland to Nova Scotia, terminating in the northern part of Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 9

12 Nova Scotia. This proposed transmission project from Newfoundland to Nova Scotia is referred to as the Maritime Link. Figure 3 shows the geographical relationship between Labrador, Newfoundland, Nova Scotia, New Brunswick and New England. The Maritime Link is shown in red. Figure 3. Map of Maritime Link Source: Atlantic Energy Gateway Transmission Modeling Study Report Figure 1. Available at The Nova Scotia Utility and Review Board (NSUARB) issued an order in July 2013 approving the Maritime Link subject to several conditions, and issued an order on November 29, 2013 approving the project based upon its review of the Maritime Link compliance filing. 11 Proponents of the Maritime Link are currently projecting it to be in-service by It does not appear that Nalcor Energy will have the ability to support baseload imports of 1,200 MW or greater at the New Brunswick border until after Imports of Nalcor Energy hydroelectricity of that 11 Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 10

13 magnitude hinge not only upon completion of the Maritime Link by 2017, but also the construction of a new 345-kV tie line between New Brunswick and Nova Scotia and possibly upgrades to the existing transmission systems in Nova Scotia and New Brunswick. Absent those additional upgrades, our review indicates that the Maritime Link would be able to deliver, at most, 330 MW of non-firm incremental hydroelectricity from Nalcor Energy to the Maine / New Brunswick border. As a result the quantity of hydroelectric imports potentially available from Nalcor Energy via the Maritime Link through 2020 is expected to be relatively small, because major upgrades are required to the New Brunswick transmission system to enable exports of up to 1,200 MW. Representative Transmission Projects It may be possible to achieve a material increase in hydroelectricity imports through the existing HQ Phase II line. However, even with incremental imports on that line the region would still benefit from adding substantial quantities of low / no carbon resources to its energy mix. This section discusses the potential for increasing imports via the existing HQ Phase II line and through representative new transmission lines. We also reviewed other transmission options, a summary of which we provide in Appendix A. These include the Northern Pass option, which sources HQ energy at convenient locations in the region south of Montreal and contains significant 735-kV transmission infrastructure; and a second Champlain Hudson Power Express (CHPE), which would be characteristic of the original CHPE proposal, which included a 1,000 MW spur connection to southern Connecticut. Maximize Use of Existing HQ Phase II New England currently imports hydroelectricity from Quebec through several existing interties and transmission lines. The largest of these is the HQ Phase II line, which has a maximum transfer capacity of 2,000 MW but which is not currently being used to that full capacity due to concerns about adverse impacts on the New York and PJM systems under a contingency in which Phase II imports were interrupted dramatically and unexpectedly. ISO-NE is preparing an analysis of the incremental imports that could be achieved under various possible cases and energy flow profiles. 12 We understand that ISO- NE expects to report its preliminary results in early If the HQ Phase II line could be operated at its maximum 2,000 MW capacity and at a 90 percent capacity factor, it could deliver approximately 15,768 GWh into Massachusetts (15,768GWh = 2,000 MW * 90 percent * 8,760 hours). The quantity would represent incremental deliveries of 5,605 GWh over the 10,163 GWh our Reference Case is projecting for deliveries on HQ Phase II in 2020 absent any investments to maximize its transfer capability dy.pdf Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 11

14 Representative New Transmission Lines The representative paths for large incremental imports for which there are public cost estimates are the Northern Pass project through New Hampshire, a path through Vermont, and two separate paths through Maine. Synapse recommends that the Commonwealth ask HQ and ISO-NE to examine the feasibility and cost of a possible HVDC line to deliver imports from Quebec into the southwest corner of Maine parallel with the Maine / New Hampshire border. Figure 4 illustrates the paths of these representative new lines. We use the following labels: Northern Pass through New Hampshire, Vermont Route through Vermont, Maine Route 1 represents the proposed Northeast Link, Maine Route 2 the proposed Green Line, and Maine Route 3 the potential for a line parallel with the Maine / New Hampshire border. (A submarine line directly from the southern tip of Nova Scotia to Massachusetts is technically feasible, but the economic feasibility hinges on not only the cost of such a line but also the availability of 1,200 MW of Nalcor Energy hydroelectricity delivered via the Maritime Link and upgrades to the Nova Scotia transmission system.) Figure 4. Illustrative paths of representative new HVDC transmission lines in New England ME Route 1 / Overland C ME Route 3 / Overland Northern Pass A ME Route 2 / Overland + Submarine B VT Route / Overland + Submarine Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 12

15 For the purposes of analyzing the New England transmission costs associated with new large hydroelectric projects, we have developed estimates based upon three proposed projects, which are listed in Table 1 and discussed below. Table 1 shows the estimated cost at the capacity of the proposed project as well as the costs normalized to a 1,200 MW line. Normalized costs for a 1,200 MW line range from $1.8 to $3.0 billion. 13 Expected in-service dates range from 2018 to Table 1. Representative potential U.S. HVDC transmission paths/lines for delivering new hydroelectric imports Route / Path VT Route Northern Pass ME Route 1 ME Route 2 Proxy Clean Energy Express n/a Northeast Energy Link Green Line Capacity (MW) 1,000 1,200 1,100 1,000 Length (miles) Estimated Capital Cost (2013 $ B) Cost Normalized to 1,200 MW (2013 $ B) Injection Terminus Project Developer Estimated In-Service date Synapse modeling In- Service date 150 DC (100 submarine, 50 underground) 153 DC + 34 AC 85 existing AC DC 350 (combination of HVDC submarine and above ground + AC) $1.5 $1.4 $2.2 $2.5 $1.8 N / A $2.4 $3.0 Canada-VT border VT kv Southern Canada-NH border NH 345 kv, Deerfield Orrington MA - Tewksbury Orrington / ME Yankee MA - Boston NA 2018** 2018** ** Synapse modeled Cases with one 1,200 MW line in-service in 2018, a second 1,200 MW line in-service by 2020, and a third 1,200 MW line in-service by Vermont Route, Clean Energy Express The Vermont route has little available information other than an elective transmission upgrade interconnection request for study at ISO-NE (queue position #425) and a one-page information brochure. This proposed line would originate at the 735-kV system in Quebec, and terminate at a converter station in southern Vermont at one of three different 345-kV stations. Recently, the 345-kV system in Vermont has been upgraded, apparently allowing for this location to be an acceptable terminus point for an injection of this magnitude. Two 345-kV lines now reach north to the approximate location of the converter station from major 345-kV grid connections at Vermont Yankee to northcentral Massachusetts and east to New Hampshire. With the announced retirement of Vermont Yankee, 13 All dollar amounts in this memo are expressed in 2013 dollars. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 13

16 this location becomes an electrically attractive source point for power injection. The proposed 1,000 MW line is described as 100 miles of submarine cable in Lake Champlain, and 50 miles of underground cable to access the 345-kV network in southern Vermont. Synapse has used an estimate of $1.5 billion for the 1,000 MW Vermont route based on our assessment of the information available from the New England Clean Power Express one-pager ($1.2 billion), a rough per-mile cost comparison with the New York Champlain Hudson Power Express, and an allowance for additional 345-kV system reinforcements in and around southern Vermont not necessarily captured by the developers estimate. Maine Routes As discussed earlier, the Maine / New Brunswick border is not an attractive location for accessing large quantities of hydroelectricity imports from HQ. In addition, it does not appear that Nalcor Energy will be able to deliver large quantities of hydroelectricity imports at the New Brunswick border until after Instead, incremental wind generation in northern Maine is the primary clean energy resource that a new transmission line through Maine would access prior to The two representative Maine transmission routes for which we have cost estimates are based on projects that have been proposed to access the wind generation potential in northern Maine as well as to access limited quantities of Canadian hydroelectricity imports. Those two representative routes, which were illustrated in Figure 4, are summarized below. Maine Route 1, Northeast Energy Link (NEL): The 230-mile HVDC line, proposed as a joint project between National Grid and Bangor Hydro (a subsidiary of Emera), is intended to deliver up to 1,100 MW of cost effective renewable and low carbon resources to southern New England customers from the Canadian Maritimes and northern New England. As noted previously, Emera is developing the Maritime Link. The Northeast Energy Link letter of interest (November 2012) indicates costs in the range of $2 billion (p.7-1). The website project description (accessed October 2013) states that the project is an investment of over $2 billion. Synapse has used an estimate of $2.2 billion for the purposes of this analysis, based on these sources and an appreciation of the uncertainties and contingencies associated with advance cost estimation for a project of this magnitude. The Northeast Energy Link is similar to an option put forth in the ISO-NE 2030 Power System Study, prepared for the New England Governors. That option was a scenario delivering 1,500 MW of new resources from New Brunswick and/or Quebec. Maine Route 2, Green Line: New England Independent Transmission Company (NEITC) is developing a proposal that consists of a 1,000 1,200 MW HVDC line to connect renewable and low-carbon resources in Maine (most notably wind) to electric markets in Massachusetts and Connecticut. The project would include 160 miles of terrestrial and 190 miles of submarine HVDC cable, in addition to a 345-kV AC link to the New Brunswick grid. We assume that imported Canadian hydroelectricity could flow on this line when the intermittent renewable resources are not generating. 14 Synapse has used 14 Incremental Hydropower Imports Whitepaper. New England States Committee on Electricity, Fall Page 31. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 14

17 an estimate of $2.5 billion for the 1,000 MW Green Line route, which would effectively be a second HVDC source point (in addition to the Northeast Energy Link) in northern Maine, tied into the New England grid in Boston via overland and submarine cable. Synapse has the least amount of information for this estimate. The proposal includes allowances for the submarine cable, the HVDC converters, significant AC reinforcement in both Boston and Maine, and new lines to connect the northern Maine collection point to sources of hydro energy at the Canadian border. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 15

18 2. New hydroelectric energy import projects can be developed through several different approaches. Each approach has different implications for the quantity of incremental clean energy that would be delivered to New England, as well as for the cost of that incremental clean energy. New hydroelectric energy import projects can be developed and funded through several different approaches, which we have grouped into two broad categories: Merchant Development, and Merchant Energy Development plus Regional Transmission Funding. This section summarizes each approach and discusses their implications for New England. Background: New England Electricity Markets and Regulatory Framework A proposal to develop a transmission line for the import of electricity from an adjacent control area will need to consider both existing New England rules and procedures and the potential changes to those rules and procedures pursuant to the requirements of FERC Order ISO-NE develops the market rules through a New England stakeholder process and then administers the rules pursuant to a FERCapproved transmission tariff. Economic transmission projects are non-reliability projects proposed by specific entities. Transmission facilities are designed by the project proponents in consultation with the incumbent transmission providers and ISO-NE. The costs of economic projects are assigned to the beneficiaries of the project. In the last ten years, there have been no economic transmission projects built in New England. FERC Order 1000 requires all planning authorities to demonstrate their compliance with certain specific rules and procedures. Two of the key elements of Order 1000 relevant to a new transmission line to import power from an adjacent control area are the elimination of the right-of-first-refusal and the development of Public Policy transmission projects. The elimination of the right-of-first-refusal means that incumbent transmission owners no longer have an exclusive right to build transmission projects that cross their service territories. The intent of this element of Order 1000 is to provide merchant transmission owners with an equal opportunity to build new transmission projects. The requirement to develop a process, including a cost allocation methodology, for transmission projects that meet public policy needs adds a third option (in addition to reliability and economic projects) to the regional planning process conducted by ISO-NE. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 16

19 Major Development Approaches and Assumptions There are a range of detailed and complicated approaches through which clean energy projects can be developed. This memo provides a bounding analysis for that range, by analyzing simple approaches at either end of the range. Below we describe the two basic approaches to project development analyzed in this memorandum, and the key assumptions underlying our analysis. Our analysis assumes that, under either approach, the supplier of hydroelectric imports will be responsible for all project development costs in Canada, and will commit to delivering that electric energy, and capacity if relevant, into a U.S. transmission line through an intertie at the border in exchange for the revenues the developer will receive from selling that energy and capacity into the respective New England wholesale markets. (This assumption does not apply to the wind or gas pipeline components of the resource Cases we analyze in this memorandum). The major differences between the two approaches are the party responsible for development of the U.S. transmission and the annual quantity of hydroelectricity that would be delivered. Those two differences are inter-related. As we discuss below, under the Merchant Development approach we assume the developer will determine the quantity of hydroelectricity to sell into the New England energy market each year based on a business model under which the developer limits its sales to onpeak hours when prices are highest. In contrast, under the Merchant Energy Development / Regional Transmission Funding approach we assume the developer will be required to supply hydroelectricity on a baseload basis, i.e., in most hours of the year. Those two differences have important implications for the total quantity of hydroelectricity that New England imports from the project each year, the CO 2 emission reductions associated with those imports, and the impact of those imports on customer bills. Merchant Development Under this approach the project proponents are responsible for all project development costs, both hydroelectric energy supply to the U.S. border and U.S. transmission costs. They are also responsible for the hours in which the hydroelectricity will be bid into the wholesale energy market and the prices that are bid in. For example, the project proponent may decide to bid prices such that it only sells in on-peak hours when prices are highest. Under that business model, the developer would only sell hydroelectricity in peak hours, which represent 48 percent of the hours of the year. This would result in a relatively low use of the line s capacity. One possible detailed development approach within the range of approaches alluded to above would involve one or more long-term contracts between a hydroelectricity import project developer and one or more buyers for some, or all, of the hydroelectricity. Such a contract would have to specify both the quantity of energy to be delivered each year and the price that would be paid. If that contract specified a single all-inclusive energy price, it is reasonable to assume that the project developer would require that single energy price to be sufficient to ensure recovery of the project developer s costs to supply the hydroelectricity plus the project developer s cost to construct a new transmission line in New England to deliver that supply. As such, that type of long-term contracting approach falls within the range of the Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 17

20 two broad approaches we analyze in this memorandum, i.e., Merchant Development and Merchant Energy Development plus Regional Transmission Funding. Merchant Energy Development / Regional Transmission Funding Under this approach the project proponents are responsible for only the project development costs to get hydroelectric energy supply to the U.S. border. We assume the U.S. transmission component would be viewed as a public policy driven project under FERC Order 1000, and its costs would be allocated among each New England state according to a method approved by ISO-NE. 15 The design of that method, and its method of cost allocation, remains the subject of debate. Our analysis takes no position regarding the choice of a cost allocation method. For illustrative purposes the analyses in this memo allocate these costs among New England states according to annual sales. Because the region pays for the U.S. transmission line, we assume the region or ISO-NE could require the project proponent to operate the line on a baseload basis and bid the hydroelectricity into the wholesale energy market accordingly. Under that pricing strategy, hydroelectricity imports would be maximized, at about a 90 percent capacity factor. The CO 2 emissions reductions associated with those imports would be allocated among the New England states per a shared mechanism. Table 2 presents a comparison of the two development approaches. Table 2. Transmission Options and Possible Impact on New England Transmission Development Approach Description Transmission Funding Basis Impact on New England Merchant Development Developer bears 100 percent of project cost of delivering energy into new U.S. transmission line plus cost of U.S. transmission line. Developer chooses annual quantity of energy to sell and receives all wholesale energy market revenues Developer funds U.S. transmission from wholesale energy market revenues and capacity market revenues where applicable Reduction in gas-fired generation and CO 2 emissions, as well as impact on wholesale energy prices, depends on annual quantity of energy the developer chooses to sell Merchant Energy Development + Regional Transmission Funding Developer bears 100 percent of project cost of delivering energy into new U.S. transmission line. U.S. transmission lines developed pursuant to some form of regional funding. Transmission line funders specify annual quantity of energy to be delivered Transmission line costs allocated among load serving entities (LSEs) in New England. Costs could be allocated per ISO-NE tariff under Public Policy method approved by FERC pursuant to Order 1000 Reduction in gas-fired generation and CO 2 emissions, as well as impact on wholesale energy prices, depends on capacity factor requirement negotiated in exchange for regional transmission funding. LSEs recover U.S. transmission line costs in retail rates 15 If ISO-NE determined a line was needed for reliability purposes it would apply the cost allocation method that has been established for such investments, while the costs of a line developed solely on economic basis would be allocated to the beneficiaries of that line. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 18

21 Within the context of these two categories, we have identified several policy levers that are summarized in Table 3. We present a brief and broad overview to identify possible policy levers that the DOER may wish to examine in more depth. Table 3. Policy Levers Policy Lever Description Examples FERC Approved Tariffs Coordinated Regional Procurement Among States Project is developed pursuant to regional transmission expansion planning processes under Public Policy section of FERC Order 1000 Revise NESCOE RFP and PPA process to include large hydropower Regional Network Service NESCOE coordinated RFP for renewables RPS Sub-Tier State Central Procurement Process Creation of renewable obligation to procure large hydropower State agency that would procure large hydro and assign long term contracts Connecticut Class I RPS Sub-Tier State central purchasing agency Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 19

22 3. Adding significant quantities of clean energy to the New England energy mix would provide supply diversity and greenhouse gas reduction benefits with minimal impact on average energy bills. The magnitude of those benefits, and the associated incremental cost to the region, will depend on the approach through which each project is developed and the magnitude and mix of clean energy associated with the project. This section presents estimates of the benefits and costs to New England over the period 2013 to 2030 of adding various increments of new large-scale hydroelectric energy imports, either alone or in combination with additional wind or additional pipeline capacity. The memorandum estimates the benefits and costs to New England of each of those five Cases relative to a Reference Case that assumes no new increments. As with any such analysis, the estimates are a function of the assumptions used to model each Case. All of the Cases are based on the same load forecast, derived from the 2012 ISO-NE forecast, of peak load growth of 0.79 percent per year and annual energy growth of 0.18 percent per year. The assumptions used to model the Reference Case are described in Section 4. With the exception of load, most of the input assumptions to the Reference Case are drawn from the 2103 Avoided Energy Supply Costs in New England study (AESC). 16 Those assumptions, which were reviewed by the various stakeholders from each of the New England states who participated in AESC 2013, include forecasts of fuel prices, REC prices, CO 2 prices and electric transmission system upgrades. It also assumes that local gas distribution companies (LDCs) will contract for approximately 0.4 Bcf/day of incremental pipeline capacity from the Algonquin Incremental Market (AIM) and Tennessee Gas Pipeline (TGP) Connecticut Expansion projects effective November Based on that assumption AESC 2013 assumes that when that additional capacity comes into-service the basis differential between New England and the mid- 16 AESC 2013 projects energy supply costs that could be avoided due to reductions in electricity, natural gas, and other fuels resulting from energy efficiency programs offered to customers throughout New England. The study is funded by energy efficiency program administrators and stakeholders include utilities, regulators, and consumer and environmental advocates. July Available from Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 20

23 Atlantic level will decline from the unusually high levels currently being experienced to levels closer to those New England traditionally experienced pre The differences between each of the five Cases and the Reference Case are discussed in terms of: Capacity mix and wholesale capacity prices, Energy mix and wholesale energy prices, Carbon emissions, Net cost (benefit) to New England, and Customer bill impacts. Hydro Increment Cases Our analysis models imports of hydro under five different Cases. They are: 1,200 MW Hydro Case (1,200 MW new transmission line starting in 2018); 2,400 MW Hydro Case (1,200 MW new transmission line starting in 2018 plus a second 1,200 MW line starting in 2020); 2,400 MW Hydro plus Wind Case (2,400 MW Hydro Case plus new 1,200 MW line accessing wind in Northern Maine and hydro imports, operational 2020); 2,400 MW Hydro plus Pipeline Case (2,400 MW Hydro Case plus 0.4 Bcf/day additional pipeline capacity by 2017 and another 0.6 Bcf/day by 2018); and 3,600 MW Hydro Case (1,200 MW new transmission line starting in 2018, a second 1,200 MW line starting in 2020, and a third 1,200 MW line starting in 2022). The key assumptions used to model each of the five hydro-related Cases are as follows: Each 1,200 MW line is modeled as a separate HVDC transmission line that terminates at, and interconnects with, the existing New England transmission system and assumes upgrades to the existing system that allow the power to be delivered to the New England hub. None of the transmission lines delivering baseload hydroelectricity are assumed to have qualified capacity for ISO-NE capacity planning or capacity market purposes. 18 As a result we model those lines as energy-only resources. We base this assumption on several factors. First, since HQ is winter peaking, it needs its hydro capacity as a source of capacity in winter months and thus may not offer capacity as part of an export project. Second, we did not find discussions of capacity value in the documents describing proposed hydro transmission projects. Third, it is not clear how ISO-NE would treat capacity offered from projects with regional funding of the transmission line 17 Ibid. Exhibit ISO New England defines qualified capacity as the amount of capacity a resource may provide in the summer or winter in a Capacity Commitment Period, as determined in the Forward Capacity Market qualification processes. ISO New England Transmission Market and Services Tariff Section I.2.2. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 21

24 components. Finally, assuming no capacity revenues provides a conservative estimate of net benefits. If developers of one or more of the hydro projects employ approaches through which they can claim some capacity value, and associated wholesale capacity market revenue, the net benefits of their specific project will be greater than we have estimated. The 2,400 MW Hydro plus Wind Case assumes the new 1,200 MW transmission line through Maine accesses generation from 2,000 MW (nameplate) of wind capacity in northern Maine. It assumes the wind is produced according to the Ventyx model wind profile for northern Maine and sold at a premium over wholesale energy market prices. (Our modeling assumes a premium equal to the MA REC Class 1 prices listed on page F-2 of Exhibit F-1 in AESC 2013, which in 2020 is $18.40/MWh in 2013$. The aggregate wind generation is higher in the winter than in the summer and over the course of a year averages about 600 MW. It also assumes the line accesses up to 200 MW of Canadian hydro imports that would be available during non-winter months. We assume ISO-NE would credit this Case with qualified capacity of 425 MW. The 2,400 MW Hydro plus Pipeline Case assumes 0.6 Bcf day of pipeline capacity will be added by 2018, in addition to the 0.4 Bcf/day of new pipeline capacity assumed in the Reference Case. We assume that 0.6 Bcf/day will be added at a levelized cost of $0.45/Dth/day at 100 percent load factor. 19 Based on this cumulative addition of 1 Bcf/day by 2018, i.e. 0.4 Bcf/day in reference case and 0.6 Bcf/day in this Case, we assume the traditional basis between New England and the mid-atlantic market will reduce to zero. We use the basis for Texas Eastern M-3 (TETLP M-3) as an index for the mid-atlantic market. 20 Our forecast of basis is drawn from AESC This 100 percent reduction assumption is a low bound that Synapse assumed for modeling purposes. It is more optimistic than the 62 percent reduction assumption for a.9 Bcf to 1.2 Bcf/day addition presented in a 2012 study that Concentric Energy Advisors prepared for Spectra Energy Corporation. 21 Impacts on New England Capacity Mix and Prices Under the Reference Case, plotted in Figure 5, New England becomes increasingly dependent on natural gas capacity as older oil- and coal-fired units retire. Our analysis assumes approximately 5,900 MW of capacity is retired by 2020, consisting of the Vermont Yankee nuclear unit and various oil- and coal-fired units. The plant retirement assumptions are presented in Table 6. Our analysis assumes that, except for 19, Natural Gas Infrastructure and Electric Generation: Proposed solutions for New England. Prepared by Black& Veatch for New England States Committee on Energy, August 26, 2013.page TETLP M-3, as defined by Platts, is a price index for deliveries on Texas Eastern from the Delmont compressor station in Westmoreland County, Pa., east to the Hanover and Linden stations in Morris County, N.J. Included are deals delivered from Texas Eastern anywhere in zone M-3, including at interconnects with New York City distributors city-gates and at interconnects with AGT at Lambertville in Hunterdon County, N.J., and at the Hanover station. 21, New England Cost Savings Associated with New Natural Gas Supply and Infrastructure, Concentric Energy Advisors, May 2012, page 40. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 22

25 new renewable resources added to comply with Renewable Portfolio Standards (RPS), new capacity additions are a mix of natural gas-fired combined-cycle and combustion turbine capacity. New England s dependence on natural gas capacity in the Reference Case increases from 45% in 2012 to 51% in 2020 Figure 5. New England Capacity Mix in the Reference Case (MW) None of the five increment Cases have a material impact on the region s capacity mix. Figure 6 provides a snapshot of New England s capacity in This figure plots only one column for all Cases for two reasons. First, all Cases except the 2,400 MW Hydro plus Wind Case have the same capacity mix as the Reference Case. This is because we assume that the hydro baseload supply projects are energy-only resources. Second, the 2,400 MW Hydro plus Wind Case attributes 425 MW of qualified capacity to the 1,200 MW wind line component of that Case, but that difference is not material relative to the region s capacity mix. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 23

26 Figure 6. New England Capacity Mix in 2020 (MW) Capacity prices under each of the hydro increment Cases are the same as those under the Reference Case, which are plotted in Figure 7. Four of the five hydro increment Cases have the same capacity prices because we have assumed that the incremental resources in each of those Cases would be energy-only, and hence each of those Cases would have the same capacity mix as the Reference Case. We have assumed that ISO-NE would attribute 425 MW to the 2,400 MW Hydro plus Wind Case, which would defer the need to add 425 MW of new natural gas capacity in However, even with that deferral New England would still need to add new capacity in 2020, and as a result we assume that prices in the wholesale market for capacity in 2020 would still be set by the cost of the marginal units assumed in the Reference Case. Therefore capacity prices in the 2,400 Hydro plus Wind Case are also the same as in the Reference Case. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 24

27 Figure 7. New England Capacity Price Forecast ($ per kw-month) $9.00 $8.00 $7.00 $ $/kW-month $5.00 $4.00 $3.00 $2.00 $1.00 $ Impacts on Energy Mix and Wholesale Energy Prices Under the Reference Case, plotted in Figure 8, New England continues to remain very dependent on natural gas generation over the study horizon. For example, by 2020 New England reliance on natural gas for generation is 51 percent. This is approximately equal to the 52 percent dependence New England actually experienced in 2011 and The Reference case projects that New England dependence on natural gas will continue in the 50 percent range from 2020 to , 2012 Annual Markets Report, ISO New England, Table 4-5. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 25

28 Figure 8. New England Energy (Generation) Mix in the Reference Case (GWh) Electric Generation (GWh) 160, ,000 Existing Imports (Net) 120,000 Renewables 100,000 Natural Gas 80,000 Coal, Oil, and Other 60,000 Nuclear 40,000 New Hydro 20,000 Hydro An overview of the impact of the new hydro imports on the New England electric system is shown in Figure 9 for the Hydro 2,400 MW Case. Note the two increases in the hydro generation in 2018 and 2020 corresponding to the two steps of new hydro imports. Neither renewable nor nuclear generation is affected by these hydro additions, but natural gas generation is reduced considerably. Natural gas generation falls by 13,200 GWh in 2020 in the 2,400 MW Case. Existing imports are lower in this Case than in the Reference Case but imports of hydro on the HQ Phase II line, which are subset of total existing imports, are essentially unchanged. The reduction occurs in existing imports from New York and elsewhere. Figure 9. New England Energy (Generation) Mix in the 2,400 MW Hydro Case Merchant Energy + Regional Transmission Approach (GWh) Electric Generation (GWh) 160, , , ,000 80,000 60,000 40,000 20, Existing Imports (Net) Renewables Natural Gas Coal, Oil, and Other Nuclear New Hydro Hydro Note: Other includes demand response and the combustion of tires. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 26

29 Each of the increment Cases reduces New England s dependence on natural gas generation, as illustrated in Figure 10 for For example, under the Hydro 2,400 MW Case New England increases its reliance on hydro generation from 5 percent to 19 percent and reduces its dependence on natural gas from 51 percent to 42 percent, a reduction of 19 percent. Under that Case annual gas-fired generation in 2020 would be reduced to 2013 levels, reducing the need for additional pipeline capacity post Figure 10. New England Energy (Generation) Mix Comparison 2020, Merchant Energy + Regional Transmission Approach (GWh) Note: In 2020 the 3600 MW Hydro Case results equal the 2400 MW Hydro Case results because its third line is not in-service until Projected wholesale electric energy prices are somewhat lower under each of the increment Cases than under the Reference Case. Wholesale energy prices are driven primarily by the cost of producing energy from the marginal unit, which in turn is a function of fuel prices and the unit s heat rate, or conversion efficiency. Energy prices in the increment Cases are somewhat lower than in the Reference Case because each Case adds energy at no variable cost to the supply curve, and as a result the market price is set by a somewhat more efficient marginal unit (i.e., lower heat rate) that is lower on the supply curve. Figure 11 plots the wholesale energy prices under each of the Cases. Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 27

30 Figure 11. New England Energy Price Forecast - Merchant Energy + Regional Transmission Approach Cases vs. Reference Case $75 Energy Prices (2013 $/MWh) $70 $65 $60 $55 $50 $45 $ Reference Case 1200 Case 2400 Case 2400 Wind Case 2400 Pipeline Case 3600 Case Note: In 2020 the 3600 MW Hydro Case results equal the 2400 MW Hydro Case results because its third line is not in-service until Impacts on Carbon Emissions The reduction in natural gas generation also results in a decrease in CO 2 emissions (see Figure 12). New England CO 2 emissions from electric generation are 18 percent lower in the Hydro 2,400 MW Case than in the Reference Case. Figure 12. New England CO 2 Emission Comparison 2020, Merchant Energy + Regional Transmission Approach Cases vs. Reference Case Note: In 2020 the 3600 MW Hydro Case results equal the 2400 MW Hydro Case results because its third line is not in-service until Synapse Energy Economics, Inc. Regional Analysis of Large-Scale Hydro CONFIDENTIAL Preliminary Discussion Draft 28