A New Probabilistic Reliability Guideline Based on the Equal Slope Criterion

8/6/2019 A New Probabilistic Reliability Guideline Based on the Equal Slope Criterion

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Southern Loop / Brattleboro Area Study andSynchronous Condenser Installation Report

November 5, 2006L. R. Kirby

Exhibit Petitioners KJ/LK-4


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Acknowledgements

Special thanks to Bruce Bentley for his contributions to the development of theSouthern Loop load growth model, and for his DSM screening analysis which formedthe basis for much of the DSM analysis in this study.

Special thanks to John Jockell for writing the key automation programs used in theloadflow analysis of this study.

Special thanks to Kim Jones for her assistance with the cost and financial analysisof this study.


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Table of Contents

I Executive summary...page 4

II Introductionpage 4

III Historical perspective.................................................................................page 6

IV Study objectives and guiding principles..page 7

V Study assumptions, methodology, and criteria.. page 8

VI The 5 root problems that afflict southern Vermontpage 10

VII Possible solutions to the 5 root problems .page 13

VIII Integration of solution components to form a strategic plan..page 19

IX The common thread (a synchronous condenser installation at Stratton)..page 23

X Technical analysis of a synchronous condenser installation (alone)..page 24

XI Capital / O&M / loss costs of a synch condenser installation (alone)page 32

XII Recommendationspage 32

Glossary..page 33

AppendicesA An Explanation of QV and PV Analyses.....page 39B Stability Discussion of Synchronous Condensers at Stratton...page 44C Basic Probability Theory.....page 46D Why Chester-Londonderry No Longer Makes Sense..page 53E A New Probabilistic Reliability Guideline Based on the Equal Slope Criterionpage 58F When and Where Load Growth Modeling in Southern Vermont...........page 69G Overcompensation of Network Systems, and its Relationship to the Southern Looppage 73H The Effect of Low Load Growth but High Load FactorGrowth on the Southern Loop...page 76I Derivation of Outage Probabilities for the Southern Looppage 79

J Strategic Solution Option Descriptionspage 83


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I Executive summary

The Southern Loop is a 46 kilovolt (46 kV) subtransmission line owned and operated by CVPS,extending from Bennington to Brattleboro. Over time, this line has been subjected to growingelectrical demand, particularly near its middle where it is weakest. Its reliability problems appear aslow (or high) voltage, not as equipment overloading, and occur more severely in the winter. In theearly 1980s, CVPS applied for a new Londonderry to Chester 46 kV tie line to reinforce the SouthernLoop. This application was denied by the PSB and the demand growth since that time has beenmanaged primarily with capacitor additions to prop up the weak voltage and load management effortsto limit peak demand.

There are other related area reliability problems including a vulnerability of Brattleboro to line ortransformer contingencies, a growing threat that the Southern Loops demand will exceed its capabilityeven with all facilities in service, a critical reliance on Vermont Yankees aged 345/115 kV T4transformer to support area voltage, and emerging regional reliability issues on the overlying 345 kVtransmission system operated by VELCO and NEPOOL.

Accordingly, CVPS and VELCO developed a spectrum of 10 potential solution options ranging fromthose emphasizing transmission solutions to those emphasizing distributed resources such as DG and

DSM, and with some that combine these approaches. These options are all capable of solving at leastsome of the areas problems described above, with varying costs and degrees of effectiveness, as wellas varying aesthetic, developmental, and environmental implications.

These 10 potential solution options were then studied by a group of affected citizens chosen from thepublic at large, based on a broad demographic mix of interests and perspectives (business leaders,environmental advocates, energy use experts, health care and emergency rescue providers, and localgovernment officials). This unprecedented public outreach process was administered under thedirection of a facilitation consultant known as the STAR Group. The final result of this collaboration isthat the original 10 solution options have been narrowed down to only 3 options.

A proposed synchronous condenser installation near Stratton, which is the subject of this report, iscommon to all three remaining solution options. Moreover, the public citizen group has explicitly

recommendedthat the synchronous condenser installation be done as soon as is practicable. Byitself, the synchronous condenser will not solve all of the problems cited above, but it will dramaticallyreduce the vulnerability of the Southern Loop to line or transformer contingencies, and willsubstantially increase the systems ability to serve the areas growing demand with all facilities inservice.

The reminder of this report provides a more in-depth account of the areas history, the technicalanalysis performed, the public review process, and the rationale for a synchronous condenserinstallation near Stratton.

II Introduction

The Southern Loop is a 46 kV subtransmission line owned and operated by CVPS, extending fromBenningtons Woodford 115/46 kV substation to Brattleboros Vernon 115/46 kV substation (seeFigure 1 with 46 kV lines in thin red, 69 kV lines in purple, 115 kV lines in black, and 345 kV lines inthick red). The line is 66 miles in length and supplies the town of Manchester, the Stratton andBromley ski resorts, various manufacturing plants, and several smaller towns.


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Southern Loop

VELCO 345 kV

Line

Figure 1

The Southern Vermont systems highest electrical demand occurs in winter and has been as high as120 Mw, comprising 11% of Vermonts highest demand. This 120 Mw includes approximately 25 Mweach in the Bennington and Brattleboro areas and 70 Mw distributed along the loop itself. Much of thisdemand is concentrated around its weakest point, in the vicinity of Stratton and Bromley, near the

middle of the loop. As would be expected in an area having seasonally-dependent economic activity,the summer demand of the 46 kV loop is significantly lower, is less concentrated near its middle, andis of less concern than the winter demand.

It is normally operated in a network configuration, and tends to be voltage-constrained, but notthermally constrained. Its pronounced weakness (i.e. its low short circuit strength) may causeexcessively low or high voltage during line contingencies that disrupt the main path. This weaknessalso inhibits the effectiveness of its protection and relay systems.

There is virtually no local generation connected to Southern Vermonts 46 kV and 115 kV transmissionsystems. The Vermont Yankee nuclear plant is more closely associated with the high-voltagetransmission system serving all of New England, than with the lower-voltage local systems. There is ascarcity of local generation because there are no significant water sources for hydro plants, as in otherparts of Vermont. Moreover, there is no gas distribution system and there are stringent environmentallaws which have historically made fuel-burning generators uneconomic in this region1. Also, there islittle opportunity for CVPS manure-to-methane Cow Power generators because of the lack of largefarms in the area. There have been some initiatives involving wind power, but these have all beenwithdrawn.

1 Fuel-burning generators in Vermont are often subject to permit conditions that restrict the number ofhours they are allowed to run (due to emissions). From the perspective of a project developer, suchrestrictions impact the economic viability of the project and may make it valuable only if peakinggeneration is required, or in other special circumstances.


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There is also a 69 kV line that supplies the Brattleboro area, running north from the Vernon RoadSubstation. The 46 kV and 69 kV systems that supply Southern Vermont are themselves fed by 115kV lines terminating at Woodford Road Substation near Bennington and at Vernon Road Substationnear Brattleboro. Woodford Road Substation is fed by two 115 kV lines, one from Hoosick Substationin New York and one from Adams Substation in Massachusetts. The redundancy of the Woodford 115kV supply makes loss of either line fairly inconsequential.

Vernon Road Substation is fed by a single 115 kV line from Chestnut Hill Substation in NewHampshire, denoted the N-186 line, which may be seen just to the right of the Vermont YankeeSubstation in Figure 1. The lack of redundancy of the 115 kV supply to Vernon Road poses a criticalweakness that will be explained in more detail later in this report.

At this point, the reader need only be concerned with wherethese systems are, not how they interact;their interaction will become apparent as this report progresses.

III Historical perspective

The issues concerning the Southern Loop, are best understood in the context of its recent history.

Throughout the 1960s and 70s the expansion of this regions ski resorts led to rapidly-growing electricloads. This growth occurred in facilities directly owned by the ski resorts (i.e. lifts, snowmaking, andcondominiums) and in supporting facilities (i.e. ski shops, hotels, restaurants, and the nearby homes ofpeople working in the resort industry).

Much of the growth occurred near the middle of the 46 kV line, in and around the Stratton resort. Bythe early 1980s CVPS had become concerned that the 46 kV Southern Loop was reaching its load-serving limit and that remediation was required to avoid voltage instability during contingencies athigher loads. In 1983, CVPS filed a 248 application to build a 46 kV line from Chester to Londonderry,in order to reinforce the middle of the loop. After a long and contentious hearing process, VermontsPublic Service Board rejected the application, citing several weaknesses in CVPS argument.

Since that time, additional load growth on the Southern Loop has been offset by adding dispatchable

shunt capacitors along the line, and by demand side management (DSM) including interruptiblecontracts for the ski resorts, fuel switching, load control, and conservation programs. EfficiencyVermont (EVT) has taken over some of these DSM efforts since the year 2000. Additionally a second115/46 kV transformer was added in 1995 at the Woodford Road Substation to share the demand withthe original transformer.

However, these two strategies (capacitors and DSM) do have their limits, and it appears that the pointhas been reached where current efforts can no longer be counted on to manage the reliability of thisolder infrastructure. Aggressive DSM programs on the Southern Loop for the past 20 years have beensuccessful, but have now used up many of the available opportunities. Figure 2 is a graphicalsummary of added DSM savings from 1991-2004. Despite continued effort, the new savings are in agradual decline.

New demand does of course provide new DSM opportunities, and while these emerge at a rate that istoo slow to offset the growing threat to system reliability, they could defer capacity upgrades to servefuture load growth. Accordingly, CVPS is considering how DSM can be cost-effectively developed tohelp solve the Southern Loops problems, even though there is not enough DSM available to solve theproblems by this method alone.


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AnnualMWH

1990

1991

1992

1993

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DSM Energy Savings SL

EVT MWH

CV MWH

The use of capacitors to mitigate the effects of new demand growth has also run out of gas but forreasons that are more technical. Simply stated, adding ever more capacitors to meet ever higherdemand will indeed prop up a diminished voltage to the desired level, but with increasing difficulty forthe operating personnel who must manage their dispatch while the systems demand changes fromhour to hour. The oversight of so many capacitors is simply not practical. Furthermore, this heavyreliance on capacitors (sometimes referred to as overcompensation) makes the system morevulnerable to a blackout if something significant goes wrong, such as the loss of a nearby transmissionline. This problem is explained in greater detail in Appendix G.

Another important historic trend on the Southern Loop is that of an increasing demand factor.Although demand factor sounds complicated, it is simply the averagedemand of a customer orsystem, divided by the highest(i.e. peak) demand of that same customer or system. On the SouthernLoop, two of the DSM efforts (load control and special contracts) have had the effect of shifting

demand from peak-demand hours to low-demand hours. This has kept the peak-demand hours fromhaving their demand grow very much. But it has encouraged the low-demand hours to decline innumber and the high-demand hours to grow in number. This trend increases demand factor.Appendix H explains this concept in more detail.

The Southern Loop cannot adequately serve more than about half of its peak demand if it suffers theloss of an important facility, such as a nearby transmission line or transformer. Therefore, the morehours that become high-demand hours, the more time the Southern Loop is exposed to this danger,even though its peak load is growing only slowly or not growing at all. Appendix H explains thisconcept graphically if the reader wishes to explore it further. These various trends have caused orcontributed to a handful of distinct and difficult problems that we now face in Southern Vermont. Thenext section explains what these problems are, and more about how they have arisen.

IV Study objectives and guiding principles

When asked to describe their main objectives in a planning study, most utility planners will mentionacceptable reliability at the lowest possible cost or words to that effect. CVPS agrees with thisviewpoint but hastens to add that the quantification of acceptable reliability involves subtledistinctions that must be clearly understood.

First, it is generally acknowledged that the larger the system (in terms of voltage, capacity, or loadserved), the higher its reliability should be. 765 kV transmission facilities serving large regions ormetro areas should logically be held to a higher reliability standard than should 34.5 kV

Figure 2


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subtransmission facilities serving small localities or towns, and this is in fact the case throughout theUS power grid.

Therefore it is clear that reliability requirements are, and should be, variable. Unfortunately, there isconsiderably less agreement as to precisely what level of reliability is appropriate in each specificsituation. CVPS believes that, because reliability and costs are interdependent, reliability should notbe considered separately from cost unless there is a compelling reason to do so2. CVPS furtherbelieves that responsible stewardship of scarce capital resources demands a thoughtful approach indeciding cost and reliability tradeoffs.

Accordingly, CVPS planners have adopted a guiding principle known as most for less. The most forless principle recognizes that the expenditure of capital resources generally results in a diminishingreturn, and that the appropriate level of expenditure is therefore problematic. Ultimately, the most forless approach seeks to capture mostof the reliability benefit of a rigorous planning approach forsubstantially lesscost.

Appendix E describes the cost versus reliability tradeoff, as well as the most for less philosophy ingreater detail, and goes on to explain the consequent development of a new CVPS reliability standardknown as the Equal Slope Criterionthat dovetails with this philosophy.

In addition to the objective of striking an appropriate cost/benefit tradeoff, there are several moreobjectives for the present study, including the need to:

Satisfy the requirements of the Vermont 20 Year Plan Satisfy the requirements of the Section 248regulatory statute Develop a solution that is aesthetically unobtrusive Develop a solution that is environmentally responsible Develop a solution that responds to customer needs in a timely fashion

V Study assumptions, methodology, and criteria

Approximately four years ago, CVPS conducted loadflow studies in the vicinity of the Southern Loop toassess a proposed tap change on the Vermont Yankee 345/115 kV (T4) transformer. In the course ofthis analysis, it became apparent that the Southern Loop system had poor short circuit strength,excessive reliance on shunt capacitors, and exceptional vulnerability to voltage instability or collapse.

The concerns raised by this analysis eventually lead to the establishment of a larger and more formalstudy to address the deficiencies, which is that described herein. At the time it was initiated, CVPSdecided that the unique problems and weaknesses of the Southern Loop required the use of specialanalytical techniques and related criteria that went beyond conventional indicators such as voltageadequacy and thermal loading.

Problems much like those suffered by the Southern Loop (heavy loading in relation to voltage class,overcompensation with static var sources and voltage instability) have emerged in the past twenty

years on numerous mature systems throughout the US power grid. New analytical methods andremedial strategies have been developed to cope with these challenges. QV analysis and PV analysisare two of the newer analytical techniques that are intended for such problems. Both techniques areused in this study and are explained in Appendix A.

2 For example, members of regional power pools who operate bulk-power transmission systems maybe compelled to meet certain minimum reliability criteria on these systems, regardless of cost. Also,federal law now mandates additional minimum reliability standards for bulk transmission systems.Therefore, the owners of systems governed by these standards may have to settle for the leastexpensive option that meets the standards, as opposed to treating both the costs andthe standardsas interdependent variables.


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The use of QV and PV analysis requires the establishment of acceptance criteria for reactive powerand real power margins.The precise value that constitutes "adequate" reactive power margin is a

judgment call. A typical standard is to require sufficient margin to withstand any single contingencycoincident with loss of the largest reactive power source within the localized area of concern, or"reactive power basin", overlapping the loss of an important line, transformer, or generator.

For Stratton, the largest nearbyreactive power source (that is actually dispatched) is any one of the 3local 5.4 Mvar capacitors3. Given the voltage dependency of the these sources (shunt caps), the lossof a nominally-rated 5.4 Mvar bank may result in a further reduction in local reactive supply due to adrop in the output of the other two banks. Therefore it seemsreasonable to slightly increase therequired margin at Stratton to 6 Mvar(5.4 Mvar x 1.1).

The largest reactive power sources electrically close to West Dummerston are the two local 2.7 Mvarshunt caps, therefore, the required reactive power margin at East Jamaica (or West Dummerston)is judged to be 3 Mvar(2.7 Mvar x 1.1 @ W Dummerston). The largestreactive power source closeto S Shaftsbury is the 5.4 mvar cap at Manchester, therefore, the required reactive power margin atSouth Shaftsbury is 6 Mvar(5.4 Mvar x 1.1). Note that the larger 10.8 Mvar caps at Woodford Roadand Vernon Road are ignored because they are already "lost" during the initial critical contingencies

(including loss of the 115 kV N-186 line from New Hampshire and loss of the 46 kV Southern Loop ator near its eastern termination).

In the course of the study however, the 6 Mvar margins often resulted in requirements for substantiallyincreased expenditures that a 3 Mvar margin would avoid, particularly in the case of DG and othernon traditional solution options. Accordingly, this standard was relaxed to 3 Mvar in some cases,which is still more rigorous than a simple voltage criterion (the conventional approach).

As with reactive power margin, "adequate" real power margin is a judgment call - a typical standard isto require adequate voltage (greater than or equal to 0.90 P.U.) at up to 105% or 110% of peakloading (i.e. a 5% or 10% margin). The standard chosen for this analysis is a 5% margin, which is

judged to be prudent but not excessive.

In addition to the real and reactive power margin criteria, CV also recognizes related, but moreconventional planning requirements such as pre and post contingency voltage limits onsubtransmission and transmission equipment of 95% to 105% and 90% to 110% respectively, a delta-V limit for switching operations or contingencies of 5%, thermally-based loading limits for transformers,lines and other current-carrying devices, and angular stability requirements post-disturbance (transientinstability or sustained oscillations are not permitted).

CVs protection and relay engineers also adhere to a variety of standards for maximum fault-clearingtimes, protection redundancy, fault current limits, fault duties of critical equipment, and protectioncoordination with internal and external systems.

Loadflow base cases are carefully developed and calibrated against recorded loads, real and reactivepower flows, voltages, generation dispatches, and capacitor dispatches. These base cases are then

modified to simulate proposed system remedies and modifications, contingencies, alternate generationand capacitor dispatches, intermediate and light loading, peak load growth, and other sensitivities.

Because this is a forward-looking study, there has been an attempt not only to identify existingproblems and issues, but to anticipate those that will emerge over the next decade or so. Central tothis effort is the forecasting and simulation of load growth. Owing to the unique character of the loadsin this area (prominent seasonal variation, growing load factor due to DSM, centralized concentration,etc) it was decided that conventional load growth forecasting and modeling was inappropriate.

3Column D of Table 6 (presented later in this report) denotes the size and location of all Southern

Vermont capacitors.


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Therefore a more sophisticated modeling method (when and where) was developed specifically forthis study, and is explained in Appendix F.

All loadflow cases assume constantreal power and constantquadrature power components in theirload models, as opposed to constant current or constant admittance components.

The reader may be unfamiliar with the terms T0+ and steady state which refer to the two timeframes typically assumed for contingency simulations. T0+ is the time frame very soon after acontingency (typically ten to thirty seconds). It comes after fault clearing and attenuation of systemtransients, but before operator action such as generator and capacitor re-dispatch and systemswitching. Steady state refers to a later time frame (typically ten to thirty minutesafter thecontingency) in which all operator actions and automatic tap changes have ceased, and during whichthe systems parameters are unchanging or changing only slowly.

VI The 5 root problems that afflict southern Vermont

Each problem will be discussed separately in the subsections below. The reader may wish to referback to Figure 1 while reading the descriptions of the five root problems.

All other things being equal, equipment failure during periods ofhigh demandtends to result in theworst problems, and therefore represents the greatest threat to system reliability. The Southern Loophas its highest demand in winter and is therefore most vulnerable to reliability problems during thatseason. These problems usually appear as low voltages. However, there may be situations duringhigh summer demand in which equipment heatingproblems become important. These problemsusually involve transmission wires or transformers carrying too much demand during hot weather.Both types of problems (low voltage and equipment overheating) will be addressed where applicable.For now, we will defer the presentation and discussion of loadflow or other analytical evidence.

Root Problem #1 - The present-day Southern Loop system is vulnerable to an unplannedloss of a transmission line or a transformer much of the time.

The 46 kV system that supplies Southern Vermont is itself fed by 115 kV lines terminating at theWoodford Road Substation near Bennington and at the Vernon Road Substation near Brattleboro. Asmentioned earlier, Woodford Road is fed by two 115 kV lines, one from Hoosick Substation in NewYork and one from Adams Substation in Massachusetts. The redundancy of the Woodford 115 kVsupply makes loss of either line fairly inconsequential. Vernon Road Substation however, is fed by alone 115 kV line from Chestnut Substation in New Hampshire, denoted the N-186 line. Vernon Roadsdependence on this single line means that its loss may cause unacceptably low voltage in southernVermont, including the Southern Loop, even at as little as 45% of peak demand. The demand on theSouthern loop is at least this high 66% of the time, meaning that the Southern Loop is exposed to apossible blackout from this one line failure almost two-thirds of the time. Although primarily a winterproblem, this exposure does include some higher-demand summer hours as well.

During periods of high demand on the Southern Loop 46 kV line, much of that demand is concentratednear its geographic center (at Stratton, Bromley and Manchester) where it is weakest. The worst

failures on the 46 kV loop itself are line failures at one of its two ends, which leave most of its demandbeing fed by a long single 46 kV line. Long single lines tend to have more voltage problems than shortsingle lines because the voltage gradually drops along the length of the line, like the water pressure ina long hose. However, because of the Southern Loops centric load dispersal, line failures occurringanywherealong its length may cause unacceptably low voltage, because they generally lead to arelatively long single span of line supporting a relatively heavy demand.

Failure of the Vernon Road 115/46 kV transformer feeding the eastern end of the Southern Loopwould be electrically equivalent to losing the 46 kV line itself near the eastern end. Transformerfailures tend to be less frequent than line failures but they generally take longer to repair. Moreover,


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this particular transformer is CV-owned, not VELCO-owned as with most 115/46 kV transformers inVermont, and is therefore not backed up by VELCOs spare and transportable units. This outage wasidentified in the 2004 Transformer Failure Study Updateas the leading threat to the CVPS transformerinfrastructure. At the time of that study, it was recommended that remedial action be deferred,pending the outcome of the in-progress Southern Loop Study, as it was hoped that a common solutionmight be found.

There are several ways to quantify the exposure to poor reliability that threatens the Southern Loop.Perhaps the most intuitive way is to calculate the span of time sufficient to cause a 50% probability offailure as well as that for a 90% probability of failure. 50/90 probabilities are often used as handyand meaningful benchmarks. For the Southern Loop, loadflow simulations and statistical analysishave lead to a prediction that a contingency serious enough to cause some loss of load is at least 50%likely within 3 years and at least 90% likely within 10 years if no remedial actions are taken and if theload remains constant. Appendix I explains the analysis that lead to this conclusion.

Root Problem #2 - The present-day Brattleboro area system is vulnerable to an unplannedloss of a transmission line or a transformer 100% of the time.

The Brattleboro areas 69 kV system is fed by a single (i.e. radial) 69 kV line from Vernon Road

Substation. Vernon Road substation is itself fed by a single 115 kV line (the N-186 line that runs toNew Hampshire, mentioned earlier). At present, there is no 115 kV circuit breaker to separate thissubstation from a 115 kV line failure. Therefore, the loss of the N-186 line invariablyresults in loss ofthe transformer that supplies most of Brattleboro. Simply adding the requisite circuit breaker will notremedy the problem because the only other source of power available to the Brattleboro 69 kVsystem, is the weak Southern Loop 46 kV line fed from Bennington. This long chain of lines would becompletely inadequate to supply Brattleboro following a failure of the N-186 line, regardless of demandlevel.

Failure of the (radial) 69 kV line feeding Brattleboro will also black out most of that city. Failure of theVernon Road 115/69 kV transformer is electrically equivalent to losing the 69 kV line, but would likelybe of longer duration. Although there are operating remedies available to promptly restore Brattleborofollowing an outage, this much load (approximately 20 Mw at peak) being continually vulnerable to afirst contingency is a serious problem. As it grows, and as the reliability of the electric grid becomesmore indispensable for commerce and public safety, the need for a remedy will become more acute.Furthermore, it is conceptually difficult to reconcile CVPSs endorsement of the equal slopesubtransmission reliability criterion (see Appendix E) with a substantially-loaded 69 kV system that hasno ability whatsoever to withstand certain first contingencies.

These comprise the main threats to Brattleboros reliability due to unplanned equipment failures.

Root Problem #3 - The Southern Vermont system (and the South Western New Hampshiresystem) are vulnerable to a long-term outage of the T4 345/115 kV transformer at theVermont Yankee nuclear plant.

The T4 is a large transformer located at the Vermont Yankee nuclear plant. It supplies the local 115kV transmission system, including the crucial N-186 line. This transformer (owned and operated by

Vermont Yankees Entergy Corporation) is 33 years old and has no on-site backup, nor is there acomparable unit within a reasonable distance that has been earmarked as a backup.

Although less damaging to voltage than certain other potential equipment failures, the unavailability ofthis unit could last for as much as a year if it failed catastrophically, thereby escalating the risk of anoverlapping outage oftwokey system components (i.e. the T4 and some other component).

Additionally, Nuclear Regulatory Commissionrules would force the shutdown of the plant if the T4remained unavailable for more than 7 days. Although the shutdown would have little effect on systemreliability, it would necessitate the purchase of alternate power by Vermonts utilities, probably at muchhigher cost. Ultimately this increased cost would be born by Vermonts electric customers.


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Root Problem #4 - The Southern Vermont system will soon be unable to supply peakdemand even with all facilities in service, due to demand growth.

All of the problems mentioned thus far are related to possible equipment failures, but there is also aconcern that this areas demand may grow to the point where the Southern Loop cannot operateproperly at peak demand even with all facilities in service. Computer simulations indicate that,

depending on the location and dispersal of future demand growth, the 46 kV loop will begin toexperience unacceptably-low voltage after only 3 to 5 Mw of additional growth in peak demand.

Given the modest rate of average growth over the past several years (only 0.5% per year on the 46 kVloop itself), one might assume that this crisis is still years away. However, as the graph in Figure 3aindicates, this systems peak demand growth has not been smooth and predictable, but instead hasbeen quite irregular. This irregularity is due to weather variances, economic fluctuations, and otherunpredictable factors. Note that the peak demand on the 46 kV loop jumped by over 7 Mw betweenthe winter of 2003/2004 and the winter of 2004/2005. Another sudden jump to a peak demand levelbeyond the capability of this system, is a distinct possibility.

Also, keep in mind the earlier discussion in Section III (Historical Perspective) that the Southern Loopsdemand factor has increased significantly over time, despite its slowing rise in peak demand. This

slow growth in the peak value should not lead to complacency, for beneath it lies an expanding periodof high demand (although not peakdemand) during which blackouts may occur if a critical line ortransformer fails.

Southern Loop Peak Winter Demand History(On the 46 kV loop i tself between Bennington and Brattleboro)

62.0

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Year

Dem

and

(M

w)

Peak Winter Demand

Trendline (0.5% per year)Figure 3a

Southern Loop Average Demand History(On the 46 kV loop itself between Bennington and Brattleboro )

25.0

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1995/96 1996/97 1997/98 1998/99 1999/00 2000/01 2001/02 2002/03 2003/04 2004/05

Year

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Trendline (1.3% per year)

Figure 3b


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Figure 3b illustrates this hidden demand growth. Although the peakdemand in the previous graph isonly growing at 0.5% per year, the averagedemand seen in this graph is growing at 1.3% per year.Moreover, this growth is steadier, as it is less affected by weather abnormalities. It is causingincreasingly-long periods of high demand that represent a mounting threat to reliability.

Root Problem #5 - Future problems that are related to the Southern Vermont system, willsoon emerge on the wider regional transmission system.

Several issues relating to the regional transmission system and the demand growth in southeasternVermont, southwestern New Hampshire, and central Massachusetts are peripherally involved with theSouthern Loop and Brattleboro areas. These include the effects of possible transmission line failuresin the Monadnock area of southern New Hampshire, a possible failure of VELCOs Coolidge toVermont Yankee 345 kV line (post NRP), and a significant increase in exposure to regional reliabilityproblems following possible loss of the Vermont Yankee T4 transformer. There are serious reliabilityproblems in this area that would be exacerbated by a long-term failure of this transformer. A regionaltransmission project in New Hampshire and Massachusetts, called the Monadnock project is beingconsidered by ISO-NE and the local transmission owners to address these problems, with possibleconstruction in 2007/ 2008. Although this project is not designed to remedy Vermonts reliabilityproblems, it would improve several of them.

VII Possible solutions to the 5 root problems

To facilitate the discussion of solutions, it is necessary to introduce a simplified schematic (i.e. agraphical representation) of the Southern Vermont system. Figure 4 depicts the Southern Loop andBrattleboro areas, using color-coded lines to denote transmission and subtransmission lines, and shortdashes intersecting these lines to denote connected substations. Transformers are denoted as zig-zag shapes connecting lines of different colors (i.e. different voltages). Other important facilities in thearea include the Vermont Yankee nuclear plant and its associated substation, and VELCOs 345 kVtransmission line, referred to as the 340 line. Notice that the information presented in Figure 4 isvery similar to that in Figure 1. Although Figure 4 is not a scale drawing, it is conceptually correct asto its orientation of important features. Figure 4 and variations of it will be used to describe potentialsolutions to the five root problems afflicting Southern Vermont. Note the critical N-186 115 kV linefrom New Hampshire in the lower right corner.


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The five root problems will be addressed momentarily, in terms of potential solutions. First however,there must be a discussion of general solution approaches. Although many solutions are available torectify the problems in Southern Vermonts overburdened transmission system, they all tend to fall intoone of four categories:

1. Transmission upgradesthat involve adding new transmission lines or replacing existing

transmission lines at substantially higher voltage (e.g. adding 115 kV lines to an areapredominantly served by 46 kV lines). The new or upgraded lines take over much of theburden of serving customer demand, thereby relieving the burden on the existing linesand/or transformers.

2. Generation additionsthat involve either large centralized units or smaller dispersed unitsreferred to as DG (distributed generation). In either case, the generation sources aremost effective if located near the customers that use their output. This relieves the burdenon the transmission system by reducing the amount of net load it must carry, and avoidsthe unintentional severance of these sources from their intended customers, should a linefail.

3. Voltage support devicesThese tend to fall into one of four subcategories:

Series capacitorsare passive devices installed directly in the conductor path to lower net transmission

impedance and thereby improve voltage. They have no moving parts. Shunt capacitorsare passive devices in substations that inject reactive power into the transmission system

and thereby improve voltage. They have no moving parts. Synchronous condensersare active devices in substations that inject reactive power into the transmission

system and thereby improve voltage. They are more effective than shunt capacitors but also moreexpensive. They have rotating components like a motor.

Thyristor-based voltage controllersare active devices in substations that inject reactive power into thetransmission system and thereby improve voltage. They are more effective than shunt capacitors but alsomore expensive. They have no moving parts, although their ancillary support systems may include fans orpumps.

4. Load management / load reduction These strategies are also referred to as DSM(demand side management) and tend to fall into one of four subcategories:

Conservationmeasuressuch as retrofitting incandescent lighting with high-efficiency florescent lighting, oradding insulation to buildings.

Special rates and contractsthat encourage customers to conserve power and/or to move their demand to

off-peak hours, in order to avoid overburdening the transmission system that supplies them. Load controlsystems that disable non-essential customer appliances during peak load hours, such as hot

water heaters. Fuel switchingmeasures that replace electricity-based heating, cooking, and drying equipment with

combustion-based equipment, such as the replacement of electric ovens with gas ovens.

Of course, some solution alternatives may utilize elements from severalof these categories, and aretherefore combinational or hybrid alternatives. This approach combines the advantages of multiplestrategies to fit the unique dimensions of a problem, often making the hybrid solution better than thosethat rely on a single strategy.

The various potential solution alternatives that will be discussed below have been shown throughengineering analysis to be effective at solving one or more of the five specific root problems. Butthese are really just pieces of a larger puzzle that has yet to be put together. Some of these pieces

will be used and some will not in the ultimate plan that solves the full range of problems in a cost-effective manner.

Having explored the five root problems and some general solution categories, we now turn ourattention to Table 1, which is organized in terms of these five problems. Notice that the potentialtransmissionsolutions are depicted in the mini schematic diagrams just below the table, which aresimilar to Figure 4. Note that the N-186 line is left out of each one due to lack of space. Except for thesynchronous condenser installation, the solution options involving DG and DSM are presented onlytextually in the table.


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We will re-consider the five root problems one by one, and discuss the potential solutions to each, assummarized in Table 1. The way in which each solution works to remedy each root problem is rathertechnical, but their basic workings will be explained.

The discussion of costs, funding sources, aesthetics, and environmental impacts will be deferred fornow. Instead, we will focus simply on what measures can potentially solve the root problems. Oncewe have a list of workable candidates we can begin to consider their relative merits and how theymay be combined in a strategic solution that cost-effectively solves all of the five root problems, withdue consideration to environmental factors, aesthetics, and economic risk.


Beginning with potential transmissionsolutions, the best transmission solution to this root problemappears to be the installation of the following three components:

A new synchronous condenser installation at a new Stratton 46 kV substation. A new Vermont Yankee to West Dummerston 115 kV transmission line on the existing VELCO

345 kV line right-of-way between Vermont Yankee and Coolidge substations (possiblyconstructed for future operation at 345 kV).

A new substation at West Dummerston with a 115/46 kV transformer, connecting the new 115kV line from Vermont Yankee with the 46 kV Southern Loop.

The synchronous condenser installation helps to hold up the voltage near the middle of the 46 kVloop. This locality has heavy demand in winter and is distant from the nearest strong source of voltagesupport at Bennington, whenever part of the 46 kV line just west of Dummerston fails. It is also distantfrom the nearest strong sources of voltage support at Brattleboro and Dummerston, whenever part ofthe 46 kV line just east of Bennington fails. The proposed new 115/46 kV substation at Dummerstonfed by the new 115 kV line from Vermont Yankee provides a strong source of voltage support for theeastern portion of the 46 kV loop that is presently vulnerable to a failure of the 115 kV N-186 line. Thiscompletes the list of likely threats that contribute to this root problem, and the ways in whichtransmission solutions can help.

Moving now to potential DGsolutions, the best DG-only solution (as opposed to a hybrid solutioninvolving some DG) to this root problem appears to be 80 Mw of DG, dispersed as follows: 100%offset of the Stratton demand (21 Mw), 100% offset of the Bromley demand (6 Mw), 100% offset of theBrattleboro demand with islanding capability (16 Mw) and partial offset of the remaining demand onthe 46 kV loop (37 Mw out of a remaining total of 56 Mw), and no offset of the Bennington demand.This concentrates the DG near to the demand that is most detrimental to voltage during an outage ofthe same transmission or subtransmission line segments noted above.

Last are the potential DSMsolutions. DSM solution options tend to be more limited than transmissionor DG because the opportunities to reduce existingdemand are finite, whereas DG and transmissionadditions are basically limited only by their cost. On the other hand, whatever modest DSM potentialmay be available is usually worth considering because its cost is typically low or negative4 and itseffect on electric system reliability can only be beneficial.

A preliminary screening of the Southern Vermont area shows a potential for approximately 26 Mw ofcost-effective DSM dispersed as follows: 7.2 Mw in Bennington, 5.4 Mw on the 46 kV loop west ofStratton, 0.4 Mw at Bromley, 1.6 Mw at Stratton, 4.2 Mw on the 46 kV loop east of Stratton, and 7 Mwin Brattleboro (note however that this 7 Mw is only useful in one particular solution option). Thisestimate was subsequently verified by an independent consultant, Optimal Energy. Its analysisdetermined the total available economic DSM to be about 29 Mw, which is judged to be close enoughto the initial estimate to preclude a reassessment of the DSM-related analysis.

4The cost of DSM may be negative because it avoids many other costs such as building new

distribution, transmission, and generation systems, and the cost of fuel for generators.


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Table 1 - Root Problems and Potent

oot problem #1 Existing S Loop contingency reliability exposure #2 Existing Brat contingency reliability exposure #3 Existing VY T4 long-term outag

ppropriate reliability guideline equal slope criterion equal slope criterion deterministic (N-1 / N-2

otential transmissionsolution(s) sync cond and VY-Dumm 115 kV line (below) VY-Dumm 115 kV line (below) spare T4 or VY-Dumm-Cool 115 kV

TF funding none none either option would receive significant

esthetic considerations low visual impact low visual impact low visual impact for either, but lower f

nvironmental considerations synch. cond. noise, new 115 kV line, but no new ROW new 115 kV line but no new ROW new 115 kV line but no new R

omments

otential DGsolution(s) requires complete offset with islanding capability (16Mw) only transmission can solve

TF funding none none N/A

esthetic considerations low visual impact low visual impact N/A

nvironmental considerations most DG technologies generate noise and emissions most DG technologies generate noise and emissions N/A

omments best cost effectiveness at ski resorts (27 Mw) N/A

otentialDSMsolution(s) 26 Mw distributed around Southern VT Brattleboro DSM could supplement Brat DG only transmission can solve

TF funding none N/A N/A

esthetic considerations virtually no visual impact N/A N/A

nvironmental considerations positive environmental impact (reduces emmissions) N/A N/A

omments works best in combination with other solutions N/A N/A

potential transmission solution potential transmissionsolution potential transmissionso

or


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#5 future regional reliability problems

deterministic (N-1 / N-2)

VY-Dumm-Benn or VY-Dumm-Cool 115 kV line (below)

either option would receive significant PTF funding

new 115 kV line on existing 46 kV line ROW

new 115 kV line on existing 46 kV line ROW

VELCO input needed

none

low visual impact

most DG technologies generate noise and emissions

VELCO input needed

none

virtually no visual impact

positive environmental impact (reduces emmissions)

potential transmission solutions

or (better for regional reliability )


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Based on these estimates, DSM will not be sufficient by itself to completely remedy any of the 5 rootproblems in Southern Vermont, but may be regarded as a useful part of potential combinationstrategies that also rely on transmission and/or DG.

Root Problem #2 - The present-day Brattleboro area system is vulnerable to an unplannedloss of a transmission line or a transformer 100% of the time.

The best potential transmissionsolution to this root problem, of those identified, appears to be theinstallation of the following three components:

A new Vermont Yankee to West Dummerston 115 kV transmission line on the existingVELCO 345 kV line right-of-way between Vermont Yankee and Coolidge substations(possibly constructed for future operation at 345 kV).

A new substation at West Dummerston with a 115/46 kV transformer, connecting the new115 kV line from Vermont Yankee with the 46 kV Southern Loop.

A new 115 kV circuit breaker at the existing Vernon Road Substation to separate its 115/69kV transformer (and hence the 69 kV line feeding Brattleboro) from the 115 kV N-186 linewhen it fails. Note that this circuit breaker cannot be seen in the schematic.

Interestingly, two of these three transmission components are included in the three transmissioncomponents cited earlier as the best transmission solution to the first root problem. An examination ofthe transmission schematics in Table 1 will confirm this commonality.

Why are these same two components effective for this distinctly different problem? As noted earlier,the new 115/46 kV substation at Dummerston fed by the new 115 kV line from Vermont Yankee,provides a strong source of voltage support for the eastern portion of the 46 kV loop that is presentlyvulnerable to a failure of the 115 kV N-186 line to New Hampshire. This outage will not only cause lowvoltage on the Southern Loop, but will unavoidably black out most of Brattleboro as well because thereis no breaker to separate Brattleboro from the faulted N-186 line. The addition of such a breaker inthis solution allows the strong voltage source created at Dummerston to not only carry the 46 kV loop,but also the Brattleboro 69 kV line after the N-186 fails. Of course, the failure of the single (i.e. radial)

69 kV line feeding Brattleboro will still result in its immediate blackout, but it can be quickly restored inmost cases by switching in supplies from the north and south.

Turning now to potential DGsolutions; recall that most of Brattleboro is presently fed by a single(i.e.radial) 69 kV transmission line. Therefore, the failures that affect Brattleboro are generally ones thatcompletely cut it off from the rest of the electrical system. Any DG solution that may be proposed mustrecognize and address this problem. The only way for DG to work under these circumstances is for itto be capable of operating in an island configuration. This requires enough DG to carry the entiredemand of the island (presently 16 Mw, at peak), as well as special controls to match the islandsdemand to the output of its generators. These two requirements make the DG solution expensive inrelation to the amount of demand that is jeopardized by this root problem.

Because of the islanding issue, DSMis not technically capable of solving this root problem by itself,but could offset some of the required DG cited in the paragraph above.

Root Problem #3 - The Southern Vermont system (and the South Western New Hampshiresystem) are vulnerable to a long-term outage of the T4 345/115 kV transformer at theVermont Yankee nuclear plant.

There are two potential transmissionsolutions to this root problem. The first is to simply connect asecond transformer at the Vermont Yankee substation, similar in capability and design to the onepresently operating, as a backup or spare.

The second potential transmission solution is to build the following two components:


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A new Vermont Yankee to West Dummerston 115 kV transmission line on the existing VELCO345 kV line right-of-way between Vermont Yankee and Coolidge substations (possiblyconstructed for future operation at 345 kV).

A new West Dummerston to Coolidge 115 kV line on the existing VELCO 345 kV line right-of-way between Vermont Yankee and Coolidge substations (possibly constructed for future

operation at 345 kV).The effect of the first transmission alternative (the spare T4 transformer) is self-explanatory.

The effect of the second transmission alternative is to provide a strong 115 kV source to the VermontYankee 115 kV Substation from Coolidge 115 kV Substation, in order to back up the source of 115 kVsupply provided by the T4 transformer. Coolidge is very strong because it is supplied by a high-voltage transmission line (VELCOs 345 kV 340 line). Therefore the line coming from it to VermontYankees 115 kV substation would also be strong. With this strong new source of 115 kV supply, thefailure of the T4 transformer would be of little consequence.

For various reasons, neitherDGnorDSMappears capable of providing a practical solution to this rootproblem. First, the N-186 lines voltage weakness following a failure of the T4 transformer, is a resultnot only of the demand in Vermont, but also of that in New Hampshire. And, because DG/DSM

installations are most effective when located at or near the demand they seek to offset, much of theDG/DSM would need to be put in New Hampshire (outside the jurisdiction of CVPS, VELCO, and theState of Vermont).

Furthermore, it is likely that DG/DSM would be an unacceptable backup to the T4 in the event of itsfailure. This means that the Vermont Yankee nuclear plant would likely have to shut down for a long-term outage of the T4, leading to long-term power supply disruptions and high power replacementcosts for Vermont customers.

Root Problem #4 - The Southern Vermont system will soon be unable to supply peakdemand even with all facilities in service, due to demand growth.

Based on the analysis done thus far, the best transmissionsolution to this root problem appears to bethe installation of the following five components:

A new synchronous condenser installation at a new Stratton substation. A new Vermont Yankee to West Dummerston 115 kV transmission line on the existing VELCO

345 kV line right-of-way between Vermont Yankee and Coolidge substations (possiblyconstructed for future operation at 345 kV).

A new 115/46 kV substation at West Dummerston, connecting the new 115 kV line fromVermont Yankee with the 46 kV Southern Loop.

A new West Dummerston to Stratton 115 kV transmission line on the existing Southern Loop46 kV line right-of-way.

A new 115/46 kV transformer at a new Stratton substation.

The synchronous condenser installation and the new 115 kV transmission line from Vermont Yankeeto West Dummerston to Stratton, would help support future demand growth on the Southern Loop,particularly that near the middle of the 46 kV loop, where robust growth is expected over the next

several years. These two sources of voltage support would also back each other up if one suffered afailure, thereby permitting the expected new demand to be served even during a contingency.

As explained earlier, the strong support of the 46 kV system at Dummerston provided by the new 115kV reinforcements would help to support the voltage at the Vernon Road Substation and therefore thatof the Brattleboro 69 kV system as well (because it is fed from the Vernon Road Substation). Thisimprovement would support future Brattleboro demand growth.

Based on the analysis done thus far, the best DGsolution to this root problem is simply to build newgeneration in the same quantity as new demand, and dispersed in the same locations, to the extentpossible. The amount of new demand in Southern Vermont over the next 10 years is forecast to be


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approximately 29 Mw. This matching of new generation to new demand means the transmissionsystem supplying the area would experience no change in its net burden. DSM could offset some ofthe necessary DG.

Root Problem #5 - Future problems that are related to the Southern Vermont system, willsoon emerge on the wider regional transmission system.

Based on the analysis done thus far, the best transmissionsolutions to this root problem are newnetwork (not radial) transmission lines that run parallel to the existing lines, like parallel roads. And,like new parallel roads, these new parallel lines share the traffic (i.e. the demand) and therebyreduce the burden on the original pathways.

Two potential transmission solutions have been identified, both of which provide parallel pathways forexisting regional transmission lines that may become overburdened, especially after one of them hasfailed. The individual components of each of the two solutions are listed below:


A new West Dummerston to Stratton 115 kV transmission line on the existing Southern Loop46 kV line right-of-way.

A new Stratton to Woodford Road (Bennington) 115 kV transmission line on the existingSouthern Loop 46 kV line right-of-way.

- or -


A new West Dummerston to Coolidge 115 kV line on the existing VELCO 345 kV line right-of-way between Vermont Yankee and Coolidge substations (possibly constructed for futureoperation at 345 kV).

The increased connectivity created by these new transmission lines would help electricity to move

more freely across central New England, even if some transmission pathways were to fail.

Potential DGand DSMsolutions, sufficient to defer the need for regional transmission improvementsfor 10 more years, would require generation additions and/or demand reductions on the order ofhundreds of mega-watts. The precise amounts and dispersal of these resources will require in-depthengineering studies, yet to be performed5.

VIII Integration of solution components to form a strategic plan

Having explored the five root problems of Southern Vermont and a broad spectrum of potentialtransmission, DG, and DSMsolutions, we may now consider how these puzzle pieces may fittogether to create an overarching solution.

5In an on-going Vermont regulatory investigation (Docket 7081) parties have proposed to establish the

responsibility for these studies within the state. An association of affected distribution companies,VELCO, and public representatives operating under the supervision of a new planning authority knownas the VSPC (Vermont System Planning Committee) is expected to perform this task in the nearfuture, if the proposal is approved.


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So far, this report has emphasized the discrete technical problems of Southern Vermont and theassociated solution elements that might be used to solve them. Now we advance from thesefundamentals to the more nuanced process of synthesizing a long-term strategy for SouthernVermonts electric system.

The best way to describe the many combinations of solution components that are to be discussed, isto develop a streamlined nomenclature, that is, a special shorthand. Figure 5provides a referenceschematic for this nomenclature.

Notice that Figure 5 is very similar to Figure 4, upon which it is based. The dotted facilities arepotential new 115 kV transmission lines, 115/46 kV substations and transformers, and a synchronouscondenser installation at Stratton. Cost-effective DSM achievable within 10 years is quantifiedaccording to its location, in boxes. It adds up to 26 Mw, which is the amount estimated to still beavailable in Southern Vermont.

The potential new 115 kV transmission lines are assigned names according to the blue segments:

A is a new Vermont Yankee to West Dummerston 115 kV transmission line on the existingVELCO 345 kV line right-of-way between Vermont Yankee and Coolidge.

B is a new West Dummerston to Coolidge 115 kV transmission line on the same right-of-way.

C is new West Dummerston to Stratton 115 kV line on the existing West Dummerston toStratton 46 kV right-of-way. D is a new Stratton to Woodford Road (Bennington) 115 kV transmission line on the existing

Stratton to Woodford Road 46 kV right-of-way. The blue S denotes the synchronous condenser installation.

Most of the reasonable and practical strategic solutions for the Southern Loop and Brattleboro areascan be described using this schematic. However, DG installations are difficult to portray graphicallyand must be described textually instead, because they tend to be dispersed in many locations and indifferent sizes.


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Note that this nomenclature will assume any new transmission lines to include whatever newsubstation and transformers are located at their end points. For example, the A,C combination ofnew transmission lines, and the A,C,D combination of new transmission lines would both beassumed to include the new West Dummerston and Stratton 115/46 kV substations and transformers.

CVPS and VELCO have developed 10 strategic solution options using the solution componentsdescribed earlier, most of which may be visualized by using the reference schematic. These 10possibilities may not be exhaustive, but capture the most effective of the strategic solution options thatCVPS and VELCO have identified for Southern Vermont. Table 2 lists these 10 options, with somegeneral categorization and a few brief comments. Appendix J provides detailed descriptions for all 10solution options.

Table 2 - Strategic Solution Options

Option option components option type comments

0 Existing System N/A

1 A,B,S pure transmission

2 A,B,C,S pure transmission

3 A,B,C,D pure transmission

4 A,B,C,D,S pure transmission

5 A,C,D,S pure transmission

6 A,T4,S pure transmission The "T4" component is a backup transformer for the existing Vermont Yankee T4

7 A,B,S,DG (25 Mw) hybrid initial configuration

A,B,S,DSM (19 Mw) / DG (21 Mw) final configuration (by 10th year)

8 A,T4,S,DG (25 Mw) hybrid initial configuration

A,T4,S,DSM (19 Mw) / DG (21 Mw) final configuration (by 10th year)

9 S,DG (42 Mw) hybrid initial configuration

S,DSM (26 Mw) / DG (38 Mw) final configuration (by 10th year)

10 DG (80 Mw) pure generation initial configuration

DG (105 Mw) final configuration (by 10th year)

As explained earlier, the table uses our special nomenclature for describing the components of each

strategic option. For example, Option #7 includes the following transmission components(compare with the Figure 5 reference schematic):

S- A new synchronous condenser installation at a new Stratton substation. A - A new Vermont Yankee to West Dummerston 115 kV transmission line on the existing

VELCO 345 kV line right-of-way between Vermont Yankee and Coolidge substations. B- A new West Dummerston to Coolidge 115 kV line on the existing VELCO 345 kV line

right-of-way between Vermont Yankee and Coolidge substations. Implied by A and B- A new substation at West Dummerston with a 115/46 kV

transformer, connecting the new 115 kV line from Vermont Yankee to the 46 kV SouthernLoop.

The reader will notice that Option #7 has two color-coded listings in the table instead of just one. Thefirst listing is for the current year, and the second listing is for the tenth year. No immediate DSM load

reduction is assumed to be possible, so the first years DSM value is zero. However, over a period of10 years, it is predicted that 19 Mw of useful DSM will have been achieved6. This will permit relianceon DG to be reduced from 25 Mw in the first year to 21 Mw in the tenth year, despite the growth indemand over the same period. So in summation, this option includes several transmissionimprovements, some immediate DG installations, and steady progress in DSM load reduction over tenyears time that will permit gradual reductions in required DG use.

6An additional 7 Mw of DSM would be available in Brattleboro but is not needed with a strong West

Dummerston source.


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Table 4 - Strategic Solution Option Effectiveness Summary#1 - Ex is ting Southern #2 - Exist ing Bra tt leboro #3 Exis ting T4 #4 Future load #5 future combined

Southern VT root problem Loop contingency contingency long-term growth in regional effectiveness score

Option reliability exposure reliability exposure outage exposure southern Vermont reliability problems (on a scale of 10)

0 Existing System 0

1 A,B,S 8

2 A,B,C,S 10

3 A,B,C,D 8

4 A,B,C,D,S 10

5 A,C,D,S 9

6 A,T4,S 6

7 A,B,S,DSM (19 Mw) / DG (21 Mw) 10

8 A,T4,S,DSM (19 Mw) / DG (21 Mw) 9

9 S,DSM (26 Mw) / DG (38 Mw) 6

10 DG (105 Mw) 7

Legend . = very effective = somewhat effective = ineffective

Note: The "combined effectiveness score" for each solution option is determined by assigning 2 points for a full circle,

1 point for a half circle, and zero points for an empty circle, in each problem category.

Table 5 - Preliminary Strategic Solution Option Cost Summary

New England VT

Option Capital cost ($M) PTF ($M) Non-PTF ($M) 20 yr PWRR ($M) 20 yr PWRR ($M)

0 Existing System $ZERO $ZERO $ZERO $ZERO $ZERO

1 A,B,S $79.6 M $65.2 M $14.4 M $124.7 M $73.0 M

2 A,B,C,S $106.6 M $65.2 M $41.4 M $146.5 M $94.8 M

3 A,B,C,D $136.1 M $115.2 M $20.9 M $186.2 M $94.9 M

4 A,B,C,D,S $146.6 M $115.2 M $31.4 M $200.7 M $109.4 M

5 A,C,D,S $108.0 M $76.6 M $31.4 M $147.0 M $86.3 M

6 A,T4,S $71.0 M $30.0 M $41.0 M $111.7 M $87.9 M

7 A,B,S,DSM (19 Mw) / DG (21 Mw) $161.6 M $65.2 M $96.4 M $50.0 M ($1.8 M)

8 A,T4,S,DSM (19 Mw) / DG (21 Mw) $153.0 M $30.0 M $123.0 M $36.8 M $13.0 M

9 S,DSM (26 Mw) / DG (38 Mw) $130.5 M $ZERO $130.5 M ($51.4 M) ($51.4 M)

10 DG (105 Mw) $105.0 M $ZERO $105.0 M $504.5 M $504.5 M

A final decision has not yet been made by CVPS as to which of these strategic solution options shouldbe selected for a 248 application. That decision will depend, in part, on the recommendationsreceived from the public through the USC / CWG process. In making this decision, the tradeoffbetween solution costs and solution effectiveness must be carefully considered because both willimpact CVPS customers. We wish to strike a balance, and to avoid an unreliable system on the onehand, or an overly expensive system on the other. Of course, there are further considerations such asenvironmental impact, noise (of possible generators), and aesthetics (particularly of transmissionlines).

At the time that this report was issued, the CWG had recommended that CVPS and VELCO narrowtheir consideration to only Solution Options #2, #4, and #7, but had decided not to recommend asingle option.

IX The common thread (a synchronous condenser installation at Stratton)

The problems on the Southern Vermont system have by now become a serious and immediate threatto reliability. Windows of opportunity to perform maintenance on critical lines, transformers, and other


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equipment have diminished to the point where CVPS can only remove certain equipment from serviceduring temperate weather coinciding with weekends.

On September 27th

2005 an equipment failure at the Woodford Road substation in Bennington, duringsuch a maintenance operation, lead to a blackout of several hours for tens of thousands of SouthernVermont electric customers. Had this maintenance been necessary during a much higher demandperiod, a rolling blackout would have been required even without the coinciding equipment failure.

Conversely, had the equipment failure occurred during a much higher demand period, even withoutthe coinciding maintenance operation, an unplanned blackout would have occurred.

Accordingly, CVPS must act to restore Southern Vermonts reliability in the short run. This issue wascarefully considered at the two-day USC meeting on January 30/31 of 2006. The USC recommendedthat the synchronous condenser installation be added as soon as possible because it appeared tohave the best benefit-to-cost ratio of any single solution component and was compatible with most ofthe solution alternatives defined thus far. CVPS agrees with this rationale therefore intends to file a248 application for the synchronous condenser installation, using 2 x 15 Mvar (capacitive) machines.

In support of this objective, consider that eight of the ten strategic solution options in this report include

the synchronous condenser installation as one of their key components. A synchronous condenser isa relatively low-cost device that has been shown in extensive engineering studies to permit dramaticreductions in the durations of exposure on the Southern Loop to critical equipment failures. The onlytwo strategic solution options that exclude the synchronous condenser installation are StrategicSolution Option # 3 (A,B,C,D) and Strategic Solution Option #10 (pure DG).

Let us briefly consider these two options. Note that the synchronous condenser installation does notreally preclude the use of Strategic Solution Option # 3 (A,B,C,D) because Strategic Solution Option #4 (A,B,C,D,S) is effectively the same option with the synchronous condenser installation included, andits reliability performance is significantly better in the summary tables, with only a modest costpremium. The conclusion is that the opportunity cost of pre-installing the synchronous condenserfacility in this case would be small or zero.

Turning now to a comparison with Strategic Solution Option #10 (80 mw of DG to start and eventually105 Mw of DG), we note that once again, a synchronous condenser installation would not reallypreclude the use of Strategic Solution Option #10 because Strategic Solution Option #9 (S, 42 Mw ofDG to start and eventually 26 Mw of DSM, and DG reduced to 38 Mw), is effectively the same optionbut with the synchronous condenser installation included and DSM, which reduces the necessary DGamount. Its performance is significantly below that of Strategic Solution Option #10, but its cost ismuchlower. So again, the conclusion is that the opportunity cost of pre-installing the synchronouscondenser facility in this case would be small or zero.

However, the synchronous condenser installation would provide little or no relief for the Brattleboroexposure, but this problem could be managed in the short run in a variety of ways.

One possible remedy is the installation of a relatively inexpensive capacitor at the Brudies Road

Substation, to support voltage following system restoration via the 69 kV line to Bellows Falls. Recentanalysis and operating experience with a temporarily-installed portable capacitor have verified theeffectiveness of this approach.

There are also proposals by National Grid to make system changes that may result in upgrades to, orreconfigurations of the 69 kV line to Bellows Falls. These changes may mitigate, or at least partiallymitigate the voltage weakness in this area.

X Technical analysis of a synchronous condenser installation (alone)


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So far most of this report has described the system inadequacies in Southern Vermont and hasexplained the benefits and costs of possible strategic solution options. However, the ultimate purposeof this document is to justify a synchronous condenser installation at Strattonas the first step of abroader strategic solution still to be determined. Therefore additional technical detail about thesynchronous condenser installation, operating without further reinforcements, is now in order.

Table 6 provides the results of various load flow computer simulations of the Southern Vermontelectric system with and without the synchronous condenser installation. The table may be referencedby row and column using numbers and letters respectively. The columns are organized as follows:

Column A provides the name of the simulation case, which is probably useful only to the author.

Column B provides the assumed load level as a percentage of peak winter load (100%). Note thatcases at each simulated load level were calibrated according to actual substation loads in southernVermont, recorded within the last several years. Column C provides the annual percent durationduring which loading is equal toor lowerthan that simulated. Column D, which is really 13 adjacentcolumns, denotes the assumed shunt capacitor dispatch in each simulation. The stars indicate adispatched capacitor. The Vernon and Brudies capacitor columns have a gray background becausethey are more closely associated with the Brattleboro area than with the Southern Loop. Column E

provides the amount and location of assumed interruptibleload that has actually been shed in thesimulation (usually zero). Column F provides the amount and location of assumed non-interruptibleload that has actually been shed in the simulation (always zero). Column G denotes the assumedcontingency (if any).

Column H provides the assumed time frame of the simulation. Some cases assume the time frameimmediately following a contingency, just after breaker operations (T0+) and attenuation of systemtransients. These cases help determine whether the unfaulted system will successfully ride throughthe disturbance without criteria violations or system instability. Other cases assume a longer timeframe following a contingency, including the time required for corrective actions by system operators(steady state). These actions, which are simulated, may lessen the systems burden (for example,dispatching additional capacitors) or they may increase it (for example, restoring loads that werepreviously tied to the fault, by re-sectionalizing). These simulations help determine how much

disrupted load (if any) may be successfully restored post-contingency, prior to repairing the faultedelement itself.

Column I denotes whether the simulation assumes the added support of the synchronous condenserinstallation or not.

Thus far, the columns described have denoted independentparameters, that is, inputs to the loadflowsimulations, chosen by the engineer performing the analysis. The remaining columns denoteparameters that are dependent, that is, outputs from the loadflow simulations.

Columns J, K, and L provide the per-unit voltages at three representative locations across theSouthern Loop, moving west to east from S Shaftsbury 46 kV to Stratton 46 kV to West Dummerston46 kV. Columns M and N provide the lowest and highest per-unit voltages and their locations on the

46 kV loop.

Columns O, P, and Q provide the reactive power marginsat specific locations across the SouthernLoop, again moving west to east from S Shaftsbury 46 kV to Stratton 46 kV to West Dummerston 46kV. Appendix A explains these important measures of system strength. Column R provides the realpower marginof the Southern Loop as a whole. Appendix A also explains this important measure ofsystem strength.

Column S provides special commentary where appropriate. Additionally, Table 6 contains explicitfootnotes and general end-notes that provide further clarification.


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The key question now before us is How effectively will the synchronous condenser installation, byitself, remedy the five root problems that afflict Southern Vermont? An examination of Table 6,coupled with some deductive reasoning can provide the answers.

The first root problem is restated below:


Table 6 entries 1 through 8 provide the results of a set of non-contingency (all facilities in-service)simulations with gradually declining southern Vermont loading, and tests of performance withversuswithoutthe synchronous condenser installation. Although Root Problem #1 is specifically aboutcontingency issues, not non-contingency issues, these non-contingency entries provide insight as tosystem vulnerabilities that may be exacerbated under contingency.

Entry 1 indicates that the existing system is showing signs of stress at 100% of peak winter load evenwith all facilities in service. Shunt capacitors have been optimally dispatched. Despite this, the 46 kVsystem voltage at Stratton is only 94% of nominal, which is slightly out of compliance with the criterionfor a non-contingency condition (95% minimum). The reactive power margin at Stratton is 2.9 Mvar

which is moderately out of compliance with the criterion of 6.0 Mvar. The real power margin of 5.7 Mwis in compliance of the 5.0 Mw criterion, but this standard is based on a minimum of 90% voltage.Some authorities would insist on a 95% minimum voltage for a non-contingency, which would renderthis too out of compliance. In any event, the system is clearly near its load-serving limit.

Entry 2 is the same simulation, but with the proposed synchronous condenser installation added. Itshows a dramatic improvement over the marginal results of the previous simulation. The Strattonvoltage is now at its ideal nominal voltage, with all reactive and real power margins substantiallybeyond minimum criteria (the Stratton reactive power margin is now at 32.9 Mvar and the real powermargin is at 46.3 Mw) indicating stable and robust system operation.

Entries 3 and 4 provide a similar comparison withoutand withthe synchronous condenser installation,again assuming no contingency, but now at 90% of peak load instead of 100%. The existing system,even without the synchronous condenser installation, is now comfortably in compliance with all criteria.However, the corresponding system withthe synchronous condenser installation still has bettermargins. Entries 4 through 8 assume successively lower load levels for the existing system. Despitethe declining use of shunt capacitors in this series of cases, the margins of the existing system growsteadily more robust, as expected.

Entries 9 through 13 provide our first glimpse ofcontingencyperformance. The assumed contingencyis the loss of the West Dummerston-North Brattleboro 46 kV line (steady state). Both simulationswithoutand withthesynchronous condenser installation are non-convergent

9 at 100% of peak load(entries 9 and 10). This indicates a likely voltage collapse under both of these conditions. The sametwo simulations run at 90% of peak load still indicate a voltage collapse without the synchronouscondenser installation (entry 12), but show acceptable performance with the synchronous condenserinstallation (entry 13). Entry 11 is an ancillary simulation, testing the effect of supervisory load-shedding at Stratton, at 100% of peak load with the synchronous condenser installation.

9Non-convergenceis the failure of the load flow simulation to achieve a mathematically acceptable

answer. This may indicate an ill-conceived simulation model or it may be a portent of actual voltagecollapse. All simulations in this study exhibiting non-convergence were carefully reviewed and testedfurther to determine its true origin. Non-convergent cases presented in this report have been verifiedto be genuinely indicative of severe voltage depression or collapse, and are not the result of modelingerror.


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Entries 14 through 19 assume the loss of the 115 kV N-186 line coming from New Hampshire (T0+).This is a severe contingency that has proven to be definitive throughout this study. It is among the twoor three worst contingencies in this area and its remediation has driven much of the recent planningeffort for Southern Vermont. All simulations exceeding 70% of peak load (entries 14 through 17) werenon-convergent and would likely result in voltage collapse. The simulation at 70 % of peak load withthe synchronous condenser installation (entry 19) was marginally acceptable, having a reactive powermargin at West Dummerston of 3.1 Mvar versus a minimum criterion of 3.0 Mvar. The samesimulation without the synchronous condenser installation (entry 18) was non-convergent andindicates a likely voltage collapse.

Entries 20 through 27 assume the loss of the Woodford-Manchester 46 kV line (T0+). All simulationsexceeding 70% of peak load (entries 14 through 17) were non-convergent and would likely result involtage collapse. The simulation at 70% of peak load with the synchronous condenser installation(entry 27) was marginally acceptable, but the same simulation without the synchronous condenserinstallation (entry 26) was non-convergent.

Entries 28 through 34 assume the loss of the Woodford-South Shaftsbury 46 kV line (steady state).Interestingly, this contingency is closely related to the prior contingency (loss of the Woodford-Manchester 46 kV line) in that it shows the effect of the simulated response of the operators. The

results are strikingly similar to those observed before supervisory actions were taken, because theadded burden of the load restoration between Manchester and South Shaftsbury has beencounterbalanced by the dispatch of more capacitors. The system, with support from the synchronouscondenser installation, can withstand the contingency up to the same 70% of peak load.

Clearly, the three worst contingencies tested thus far are the loss of the 115 kV N-186 line comingfrom New Hampshire (T0+), the loss of the Woodford-Manchester 46 kV line (T0+), and the loss of theWoodford-South Shaftsbury 46 kV line (steady state). Moreover, all three of these, when managedwith the help of the synchronous condenser installation, can be withstood up to 70% of peak winterload.

But the results presented thus far provide little insight as to the load limit of the existingsystem forthese same three contingencies. We only know is that the existing system is quite incapable of

withstanding them at or above 70% of peak load. Entries 35 through 37 are intended to provide abetter sense of the existing limit. All three contingencies are simulated at 50% of peak winter load.This load level still does not correspond to the precise limit, but is close enough that we may infer itsvalue from the associated margins and voltages.

Entry 35 assumes loss of the 115 kV N-186 line (T0+) at 50% of peak winter load. All voltages arewithin criteria. The reactive power margins at Stratton and West Dummerston, although positive, arebelow par. The real power margin is also positive but below par. Based on extensive simulationexperience with this system, it is estimated that the load limit at which these criteria would be at leastmarginally acceptable is 40% to 45% of peak winter load.

Entry 36 assumes loss of the Woodford-Manchester 46 kV line (T0+) at 50% of peak winter load. Allvoltages are within criteria. The reactive power margin at Stratton, although positive, is below par. It

is estimated that the load limit at which this criterion would be marginally acceptable is 45% of peakwinter load.

Entry 37 assumes loss of the Woodford-South Shaftsbury 46 kV line (steady state) at 50% of peakwinter load. All voltages are within criteria. The reactive power margins at South Shaftsbury andStratton, although positive, are below par. It is estimated that the load limit at which these criteriawould be at least marginally acceptable is 45% of peak winter load.

Entry 38 is a special test of the systems potential forovercompensation, a condition caused by over-reliance on shunt capacitors to prop up voltage as demand increases. Appendix G explains thisphenomenon in more detail.


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In summation, it appears that the existing systems load limit is approximately 45% of peak winter loadfor the three worst contingencies. Our earlier analysis indicates that the addition of the synchronouscondenser installation increases this limit to approximately 70% of peak winter load for the same threecontingencies.

The derivation of these load limits is useful, yet they still fall short of providing an intuitive sense of ourexposure to voltage collapse, and the degree to which the synchronous condenser installationprovides mitigation. Better insight may be gained by correlating the load limit information with load-duration information, as in figures 6a and 6b. Both figures depict the same load duration curve. Aload duration curve is simply a cumulative record of system load levels over a period of time (typicallyone year). The longer the time spent at a given load level, the flatter the slope of the curve will be inthe vicinity of that time value.

The load-duration curve depicted in figures 6a and 6b is that of the Southern Vermont system,including the Bennington and Brattleboro areas and the Southern Loop that connects them. Durationis noted as a percentage on the horizontal axis and load level is noted as a percentage on the verticalaxis. The load-serving capability (i.e. the load limit) of the existingsystem is depicted in Figure 6a,and that of the system with the synchronous condenser installationis depicted in Figure 6b.

Southern Loop / Brattleboro Existing Load Duration Curve

With Exposure Duration for Existing System

0.0

20.0

40.0

60.0

80.0

100.0

120.0

100.

0

Duration (annual %)

Load(%o

fpeak)

45.0Critical Load Level (%) =

116.0

65.9

Peak Load of Base Curve (MW) =

Exposure Duration of Base Curve (%) =

Load Factor of Base Curve (%) = 52.3

load-serving capability

(45% of peak, or 52 Mw)

52 Mw

Southern Loop / Brattleboro Existing Load Duration Curve

With Exposure Duration for Option S

0.0

20.0

40.0

60.0

80.0

100.0

120.0

100.

0

Duration (annual %)

L

A New Probabilistic Reliability Guideline Based on the Equal Slope Criterion

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Transcript of A New Probabilistic Reliability Guideline Based on the Equal Slope Criterion