A Briefingon BC Hydro's

Transmission CapacityRequirements

Prepared byBe Hydro Executive Operations

September 2002

C34-30

TRANSMISSION CAPACITY REQUIREMENTS

Introduction:

In the last 10 years, no new significant transmission has been built in the westerninterconnection (Western Electricity Coordinating Council (WECC) \ which would directlysupport the large flows of energy now taking place between jurisdictions as a result of thewholesale generation market. The Western State Governors, as well as regional utilitiesBonneville Power Administration, PacifiCorp, BC Hydro, ESBI2, Altalink, and others, havebeen meeting to discuss the need for additional transmission capacity as a direct result ofreliability concerns. The seriousness of the situation is belied by these coordinationmeetings in advance of expected formalization/creation of regulatory agencies such asRegional Transmission Organizations. Given the importance of trade revenue growth toBC Hydro, it is entirely consistent to strategically review our intertie and domesticconstraints in moving energy to market. This issues paper outlines the scope of BeHydro's own transmission capacity needs within the context of the entire Northwesternregion and its volatile, highly active energy market.

Background - The Crisis:

Transmission is the transportation highway for electricity. It serves as the path for powerplants to deliver energy to the distribution systems which serve customers, and is integralto power reliability. The former Federal Energy Regulatory Commission (FERC)Chairman James Hoecker refers to the future operation of transmission as the heart of theenergy industry restructuring debate: "It is the strategic asset, the integrated networkplatform, upon which any competitive and transparent wholesale power market must bebuilt"3. A strong transmission network is essential to support competitive markets.

Yet according to the Cambridge Energy Research Associates, despite more than 200,000megawatts of new generation capacity announced in North America during the past twoyears, there has been no parallel investment in transmission infrastructure:

The North American electrical grid is a complicated network of electricalpaths for sending power from central generators to distributors and otherlarge wholesale customers. The system developed, utility by utility, withlinks added between utilities, mostly to permit greater economy inmeeting reliability goals. The system was not originally designed toaccommodate large power flows across regions - the job it is now beingcalled upon to do with the opening of transmission access.4

Based on US experience with a deregulating electricity market over the last five years,many would agree that the changing structure of the industry has introduced unanticipatedreliability risk. Electricity restructuring has exacerbated an existing nonfunctioning market

I The Western Electricity Coordinating Council (WECC) was created on April 18, 2002 by merger ofWSCC, the WesternRegional Transmission Association (WRTA), and the Southwest Regional Transmission Association (SWRTA).2 ESBI Alberta Ltd. is Alberta's independent Transmission Administrator. ESBI Alberta Ltd. is incorporated under the AlbertaBusiness Corporations Act. The sole shareholder is the Electricity Supply Board of Ireland (ESB). ..3 Comments by the U.S. Federal Energy Regulatory Commission (FERC) Chairman Hoecker at a US Senate hearing onproposed electricity legislation. _Cambridge Energy Research Associates (CERA), High Tension: The Future of Power Transmission in North America,Autumn 2000, p. 1-9.

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for transmission, and coupled with little new generation and increased market uncertainty,contributed to a rising probability of blackouts.

In December 2000, the North American Reliability Council (NERC) stated that the grid "isnow being used in ways for which it was not designed". In a deregulated market, open­access transmissionS is resulting in new or accentuated flow patterns across the network.These limitations affect BC Hydro's access to power during higher demand periods.

Following the 1996 disturbances in the Western Interconnection, transmission operatorsbecame more focused on meeting reliability criteria and on ensuring reliable operationunder all operating conditions. Prior to 1996, many paths did not meet all reliability criteriaand were often operated at transfers that had not been studied for the specific operatingconditions. One outcome of this heightened concern for reliability is that the operationallimits of the BC to Washington State interties were reduced for much of the time (althoughrecently the situation has improved). The Northwest to California interties have beensimilarly impacted. The result is that daily operating transfer capabilities for many pathsare often significantly less than the path ratings and lower than the transfer capabilitiesthat were acceptable prior to 1996.

Table 1: Regional Transmission is Not Keeping Up with Needs6

Northwest Power Pool 10 Year Forecast

1998 2008 % Increase

Winter Peak Load (MW) 59,972 66,952 12%Transmission Circuit Miles 61,415 62,352 2%

Barriers to Transmission:

Many factors have contributed to overall slowdown in grid construction. Rapid growth inthe urban and suburban centres limits land availability in areas in need of new powerinfrastructure, sugh as the highly urbanized local areas of the Lower Mainland and SeattleCity areas.

Pressure on Rights-of-Way: Municipal governments, forest companies, recreationalusers, aboriginal groups, other utilities and fish and wildlife agencies will continue to applypressure for alternative uses of our rights-of-way. Development in the Lower Mainland willlikely constrain future transmission reinforcement to rebuilding on existing routes.Transmission rights are important because they define property rights and because theyhelp hedge transmission price. risk.

Changes in Planning Drivers: FERC Order 888 required vertically integrated utilities toprovide an open access transmission tariff that was available to all interested transmission

5 FERC's Order 888 in 1994 required vertically Integrated utilities to provide an open access transmission tariff that wasavailable to all interested transmission users on an equal basis.6 From a Transmission Briefing for the Western Governors Association, by Vickie VanZandt, VP Operations and Planning,BPA, April 2001.

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users - on an equal basis with the vertically integrated utility itself. BC Hydro compliedwith the implementation of its Wholesale Transmission Services tariff and establishment ofGrid Operations, a separate group from the energy group within BC Hydro, to operate thetransmission system and implement the tariff. Even before the FERC Order 2000, whichrequires the transmission system operator to be independent of any utility generation ormarketing companies, BC Hydro has had a singularly strong firewall between the groupwhich plans and operates transmission \ facilities and the groups which use thosefacilities. The result, as probably mirrored in many vertically integrated utilities, isuncertainty as to where the appropriate value proposition may be applied in reviewing anynew transmission - particularly with regard to considering trade revenues. ·This isexacerbated in BC Hydro where the transmission grid was designed with the mandate toserve the domestic customers (which are mainly concentrated in the Lower Mainland andVancouver Island) and not with trade as the primary consideration, resulting in these twointerests vying for the same transmission capacity.

Uncertainty over Future Returns:Responsibility for transmission in the US is shifting from regional regulators to the FERC.While Be Hydro and other utilities in the west work towards a regional solution for gridplanning and operation in the WECC in the form of an RTO, there remain questions.Those include whether FERC will allow an adequate return on equity for transmissioninvestments, and whether it will approve pricing systems that provide financial incentivesfor efficient operation and expansion of transmission systems. Uncertainty around theregulatory environment has had a chilling effect on transmission investment.

Technology Solutions for Increasing Transmission Capacity:

One of the keys to creating competitive electricity markets is open unfettered access totransmission capacity. As deregulated markets try to push more electricity through limitedtransmission resources they encounter transmission line bottlenecks and system widetransmission stability limits. Utilities continue to research, and develop, solutions whichremain longer-term, and there continue to be practical short-term technology fixes:

Trials done in the past decade with Flexible AC Transmission System (FACTS) devicesshow promising results, affording the ability to control which transmission path electricitywill flow on. The potential of these devices is in optimizing the distribution of flows overthe transmission system, and gives utilities the ability to maintain the stability of the powersystem as it is operated closer to the limit.

Advanced metering technologies have permitted Power Marketers to carefully purchasetheir electricity supplies and monitor their customers' demands ensuring that margins areas low as possible. The development of distributed and renewable generationtechnologies may also have a big impact on future electricity markets, as microturbinesand fuel cells hold the promise to provide for reliability improvement and new wires-assetdeferral.

Direct current (DC) transmission has many advantages and BC Hydro has utilized thistechnology in moving energy to Vancouver Island. The energy from a standard ACtransmission line is converted to DC at a terminal. station then converted back to Ae atanother terminal station. The capital costs of the conversion equipment is fairly highrelative to alternating current (AC) transmission7, largely relegating this to a long distance,

7 While the capital costs of the AC - DC conversion equipment is fairly high relative to alternating current (AC) transmission7,it should be noted that the DC transmission cables themselves are normally less costly than AC cables.

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point-to-point transmission system. DC transmission may be used to cross bodies ofwater, between isolated networks, or in specific cases where there is a need to have fullcontrol over the amount of power flowing over the line. Because it is possible to havecomplete control over the flow of power the high voltage DC (HVDC) line resembles a gaspipeline in function, more than anAC transmission line, and will be seen to have a role toplay in new transmission infrastructure.

To date, however, there is not a single instance of FACTS or superconductors proposedfor the Western Interconnection. Proposals to relieve constraints are all traditional typesof upgrades: additional transmission lines, remedial action systems, systemreconfiguration, and upgrading existing lines. Recently there has been preliminaryconsideration given to long distance DC transmission from northern Alberta to markets inthe United States.

In the near-term BC Hydro continues to extend the transmission system's limits by addingstation equipment to maximize the utilization of the existing transmission lines. A recentexample is the modification to the BC Hydro generation shedding scheme for outages onthe BPA system, which resulted in recapturing 400 to 800 MW in transmission capacitythat would have been lost due to Washington State load reductions. BC Hydro hasplanned capital additions of$20M for Series Capacitors, which allow for higher flows onexisting transmission. Ultimately, however new transmission infrastructure will berequired to provide significant congestion relief.

Transmission Reinforcements for Electricity Trade

Be transmission reinforcements for electricity trade must be coordinated with potentialexpansions of capacity in the US and Alberta. CERA's analysis of congestion simulationand investment8 confirms that transmission investment affects the entire market. Aninvestment in an interconnected transmission network will affect flows on all parts of thenetwork.

While both economic and uneconomic congestion is present in current markets, in manycases the cost of congestion is greater than the cost of relieving the pertinent bottleneck.CERA suggests that cost recovery mechanisms will precede significant investment. Thisis because transmission investments designed to attack congestion may eliminate theactual energy price differentials as a potential revenue source.

Because congestion is linked to the location of the loads and power generationdevelopment, the location and magnitude of the growth in generating capacity is the keydriver in creating congestion. The multiclient transmission study by CERA also suggeststhat gas price differences are likely to drive future congestion - as the markets clear atprices established by gas-fired generation, the demands on the transmission network willchange.

Transmission infrastructure investment must therefore be linked to an ability to generate aprofit. As a likely precondition to significant investment in transmission, contracts, such asbilateral forward transmission contracting, will be established between investors and

8 CERA, High Tension.

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beneficiaries such as with the distribution companies and other wholesale takers ofenergy in the high-price markets to the south.

BC transmission expansion alternatives are discussed below, followed by current plansand proposals in the US. Alberta transmission expansion plans are not known at thistime, but expansion of transmission capacity from Alberta to BC, or to the US,must becoordinated with expansion of BC to US intertie capacity. It is clear that new generation isplanned to come on stream in Alberta however, and there is growing interest in thatmarket having access to the US markets. BC Hydro continues to work with transmissionplanners in neighbouring jurisdictions to ensure coordination of transmission plans.

Province of BC to Alberta

The connections with Alberta have a nominal capacity of 1,000 MW to BC and 1,200 MWto Alberta, though both are often limited to lesser amounts in operation due to systemconstraints. Transfers from BC to Alberta are normally limited to 800 MW, while transfersfrom Alberta to BC are limited to 100 to 200 MW during peak load hours, and up to 700MW during off-peak hours. Alberta entities have been looking at strengthening theirconnection to US markets, either via BC Hydro, or by constructing their own intertie withthe US. An Alberta to US corridor may traverse the southwest corner of BC to connect toa US terminus in the Northeast Washington/ldaholWestern Montana area. Alternatively,reinforcement of transmission between Alberta and BC would require the addition of asecond 500 kV transmission line from near Calgary (Langdon Substation) connected tothe BC Hydro system at Selkirk Substation.

Province of BC to USA Transmission Expansion:

BC Hydro has a number of alternatives for reinforcing transmission capacity to enhanceelectricity trade with the US. The intertie between BC and the US has a maximum ratingof 3150 MW north to south and 2000 MW south to north, although this is often constrainedto 1,100 to 2,000 MW depending on the situation in the Seattle City Light and PugetSound Energy service areas.9 The system is at capacity much of the time. Thepercentage of time the BC to US intertie is constrained10, by either BC Hydro or BPA,ranges from 1% to 29% over a period from May 2000 to April 2001. During the months ofMay through September 2001, which would be typically high export months for BC Hydro,the intertie was constrained an average of 24% of the time.

Over the past ten years, three main alternatives for increased capacity to the US havebeen investigated:

• Westside interties with BPA - reinforcement of the existing transmission system.

• A new Oliver to Coulee intertie - as originally envisaged for Canadian Entitlementreturns.

• Eastside intertie with BPA - expansion of the transmission between the Kootenaysand the Spokane area.

9 CERA, High Tension.10 Calculated as the number of hours the path is constrained divided by the total number of hours (730) in the month. Datafrom Yakout Mansour, VP Grid Operations, BC Hydro, May 2001.

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The high-level estimate for each option range from $50M to over $500M, with anundetermined amount of cost sharing with SPA. Though these are examined asalternatives, a solution is dependent on coordination with USA reinforcements and theProvince of Be's priorities. The $500M cost for the Westside intertie Reinforcementincludes a BC interior transmission estimated at $250M, that is required for native load.The shorter intertie reinforcement proposals are roughly equivalent, at $60M for the line atOliver, and $50M for the eastside intertie near Cranbrook. Estimated in-service dates arebetween 5 to 10 years.

• Westside Intertie Reinforcement:Further reinforcement of the westside intertie would ultimately require an additional500 kV transmission line from Nicola Substation (near Kamloops) to the LowerMainland (possibly the Abbotsford area), which is about 200 km. This line would alsobe useful for supplying increasing demand in the Lower Mainland. An additional 500kV transmission line from the Lower Mainland to the BC/US border, connecting to aline in the US would be beneficial for trade during the high value summer peak periodsand would increase our import capability as long as a new corridor was used part-waythrough Washington.

Westside reinforcement will be complicated by the limited right of way in the LowerMainland and may require removal of existing lines to build higher capacity 500 kVlines. In addition, ongoing experience with US westside capacity restrictions makes itclear that close coordination is necessary between BC upgrades and complimentaryinvestment in the US.

The proposed SiteC project on the Peace River would potentially be served withexisting transmission reinforcement north of Kamloops, already completed in part toserve the formerly planned Kemano Completion Project. The Westside Intertiereinforcement from the south interior to the Lower Mainland would also be required tosupport Site C.

• Oliver - Coulee Intertie:The Columbia River Treaty envisaged returns of Canadian Entitlements 11 at a pointnear Oliver, which would have required the construction of a new intertie from the USto BC. Negotiations on return of the Canadian entitlement culminated in replacing theOliver return option with reinforcement of the existing interties. This transmission plancould be constructed and would consist of a new substation in the Oliver area toconnect to BC Hydro's existing 500 kV line. The US terminus would be in the "Mid-Citarea, possibly at Coulee or Chief Joe Generating Stations. This interconnection wouldbe on a new corridor and be exclusively for electricity trade.

• Eastside Intertie Expansion:The existing low capacity eastside intertie with BPA could be expanded with either a500 kV or a 230 kV line, the latter providing lesser capacity. This intertie expansionwould coordinate with Alberta better than the other alternatives. The US terminuswould be in the Northeast Washington/ldaho/Western Montana area. Thisinterconnection would be exclusively for electricity trade.

11 This power, known as the Canadian entitlement to downstream power benefits, as the result of the Columbia River Treatyratified in1964, is currently about 1,200 - 1,400 MW of peak capacity and over 4.500 gigawatt-hours of electrical energy peryear -- enough power to meet the needs of close to 500,000 BC households.

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USA Transmission Reinforcement Plans and Proposals~

BC Hydro transmission reinforcements to support electricity trade need to be coordinatedwith transmission reinforcement plans in the U.S. In the Northwest U.S., BPAandPacifiCorp are presently formulating transmission plans that can be coordinated withreinforcements in B.C. They are estimating capital spending in the order of $2.0 B at bothBPA and PacifiCorp. An inland intertie through Idaho and Nevada, paralleling the existingCalifornia/Oregon Border (COB) and Northern California (NOB) interties, has been in theplans for many years.

BPA's plans have included 500 kV reinforcements in the 1-5Corridor from Everett throughto Tacoma. These reinforcements will provide capacity for Entitlement Returns andaddress ongoing restrictions on exports from BC. The additional BC to US trade thesereinforcements will support is dependent on a number of factors including load andgeneration developments in the Puget Sound area. BPA is also proposing transmissionreinforcements from Western Montana through to Coulee. These reinforcements wouldsupport the expansion of the eastside intertie. In addition, BPA plans to reinforce its"North of John Day" path, which will improve access to COB and NOB, which would bebeneficial for all BC alternatives.12

PacifiCorp is proposing transmission reinforcements from the Mid-C area through Idahointo Utah. These reinforcements would coordinate with a Be transmission expansionsouth from the Oliver area.

The Southwest Intertie Project (SWIP), being proposed by Idaho Power, would be a new500 kV intertie from Idaho to the Las Vegas area. This line would provide access toArizona and Southern California markets in conjunction with the PacifiCorp proposaldiscussed above, and hence a BC transmission interconnection from the Oliver area. ABe eastside intertie expansion could also coordinate with the SWIP, but would be bettercoordinated if the northern terminus of the PacifiCorp proposal were in easternWashington, rather than central Washington.

Policy and Regulatory Timelines:

The US National Energy Policy makes strong commitments to enhance ability to transmitelectric power between geographic regions: The NEPD Group recommends that thePresident direct the Secretaries of Energy and State, in consultation with the FederalEnergy Regulatory Commission, to review their respective ... electricity cross-boundary"Presidential Permitting" authorities, and to propose reforms as necessary to make theirown regulatory regimes more compatible for cross-border trade. 13

The U.S. Federal Energy Regulatory Commission (FERC) issued a notice of proposed. rulemaking (NOPR) on 31 July 2002 directed at remedying undue discrimination throughopen access transmission service and standard market design (SMD). BC Hydro andPowerex have been actively engaged in FERC's consultation process leading to releaseof the NOPR. The SMD NOPR is a new set of standardized set of rules that will govern

12 For further information on SPA's proposed infrastructure projects see the website: www2.transmission.bpa.gov/projects.13 U.S. National Energy Policy Development Group, National Energy Policy: Reliable, Affordable, and EnvironmentallySound Energy for America's Future, May 2001, p. 8-18.

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the wholesale electricity industry, intended to address current inefficiencies in thewholesale market and provide customers with the benefits of a competitive bulk powersystem. Be Hydro is reviewing the impacts of the NOPR, in consultation with RTO ­West, and may file comments to FERe within the 75-day comment period. Althoughmany questions remain to be answered and issues addressed through the consultationprocess, the new NOPR is seen by many as a major step forward towards standardizingelectricity market design across North America. There are vociferous opponents fromwithin the States themselves however, as such wide-sweeping regulatory powers areviewed by some as unconstitutional.

FERC's Declaratory Order on the RTO - West, on September 18, 2002, approved thefiling made in late March by BC Hydro and other RTO - West filing utilities, concerningformation of a regional transmission organization (RTO): .....the hard work of all partieshas resulted in a proposal that, with some modification and further development of certaindetails, will satisfy not only the Order No. 2000 requirements, but also can provide a basicframework for a standard market design for the West.14

Regulatory uncertainty surrounding Sumas II power project has delayed transmissionstudies which, among other issues, would clarify the potential impact to the intertie.Sumas II was approved by Washington State Governor Locke on August 23, 2002. TheNational Energy Board (NEB) has scheduled a Hearing on Motions for October 1.8,2002,to clarify some procedural and environmental matters associated with Sumas II'sApplication to Construct an International Power Line, prior to setting out a revisedSchedule for an oral hearing in connection with the proceeding. They were removed fromthe queue for transmission service in Summer 2001 when they failed to sign anagreement for service. As of September 14 , 2002, Sumas \I had not yet re-applied fortransmission service.

Conclusions:

The societal costs of transmission outages, and the direct economic costs of congestion,combined with the inadequate level of transmission infrastructure in the WEeC, seem tosuggest that that something must be done, even in advance of the formalization ofRegional Transmission Organizations. RTO's may provide solutions when they are upand running, but they are likely 3-4 years away from operation and would then need timeto determine the transmission plan. Thus it could very well be 5 years before the RTO isready to advance a plan which would then take as many or more years to energize.

Any Be Hydro transmission reinforcements to support electricity trade need to becoordinated with transmission reinforcement plans in the U.S. The momentum within theNorthwest, as evidenced by the Western Governors' plans to continue coordinateddiscussion of regional transmission infrastructure upgrades, and the announcement ofSPA and PacifiCorp estimates of capital spending in the order of $2.0 B each, wouldsuggest that Be Hydro is in an excellent position to begin firming up plans for our owntransmission investments.

14 U.S. Federal Energy Regulatory Commission, "Declaratory Order on Regional Transmission Organization Proposal",(Issued September 18, 2002), FERC Docket Nos. RT01-35-005 and RT01-35-007, p. 2.

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I..

Appendix A

NW Constrained Paths

~

NWToIdaho

BPA illustration of theNorthwest and theidentified transmissionsystem constraints.

15 From a Transmission Briefing for the Western Governors Association, by Vickie VanZandt. VP Operations and Planning,BPA. April 2001.

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