# Stakeholders Meeting on Western Wind Integration Project May 23, 2007

Bob Anderson, West Wind Wires

Bob Wilson, WAPA

Orlando Reyes, WAPA

Karl Wunderlich, Bureau of Reclamation

Stew Jenkinson, TransCanada

Bob Johnson, Xcel

Gerry Stellern, Xcel

Larry Mansueti, DOE

Paul Schmidt, Sierra Pacific

Bob Easton, WAPA

Linda Desmond, National Grid

Dave Corbus, NREL

Craig Cox, Interwest Energy Alliance

Rob Kondziolka, Salt River Project

Brennan Smith, Oak Ridge National Laboratory

Gary Trent, Tucson Electric Power

Morey Wolfson, Governor's Energy Office

Tom Darin, Western Resource Advocates

Paul Denholm, NREL

Brad Nickell, WAPA on detail to DOE Wind

Jerry Smith, Westconnect

Vladimir Chadliev, Nevada Power

Bob Smith, Arizona Power

Charlie Smith, Utility Wind Integration Group

Jerry Vaninetti, TransElect

Greg Blue, EnXco

Steve Brown, CO PUC

Tom Green, Xcel

Tom Wray, SunZia

Mark Mehos, NREL

Charlie Reinhold, WestConnect

Tom Acker, Northern Arizona University

Michael Milligan, NREL

Richard Mignogna, CO PUC

Donald Bryce, Bureau of Reclamation

Ron Lehr, American Wind Energy Association

Doug Larson, Western Interstate Energy board

Tom Carr, Western Interstate Energy board

Rich Krauze, 3 Tier

Hugo Gill, 3 Tier

Brett Oakleaf, Xcel

Debbie Lew, NREL

Gary Jordan, GE

Nick Miller, GE

Kevin Porter, Exeter

Mark Graham, Tri-State

Megan Wood, USE

Michael Wood, USE

# On phone

Michael McDiarmid, N.M.

Dave Hawkins, CAISO

Harvey Boyce, AZ Power Authority

Tom Hanson, Tucson Electric Power

Jeff Anthony, AWEA

Rob Gramlich, AWEA

Brendan Kirby, ORNL

Abe Ellis, PNM

# Debbie Lew

The motivation for the study is to support the WGA CDEAi and the
President's Advanced Energy Initiative and help decision-makers in
several western utilities through a regional integration study that
examines the costs of operating impacts due to the variability and
uncertainty of large amounts of wind and solar power on the grid.

Wind map from Wind Vision 20% study

Not only want to look at operational costs but other factors as well:

-   Is it more cost-effective for Arizona to use in-state wind resources
    or import better class resources from out-of-state?

-   What are benefits of geographical diversity of wind resources, e.g.,
    for long-distance transmission of wind from Wyoming, Colorado and
    New Mexico to serve Las Vegas?

-   What are the benefits of balancing area cooperation to manage
    variability?

-   What is the role and value of wind forecasting?

-   How do wind and solar contribute to reliability and capacity value?

-   How can hydro help with wind integration?

### Key Tasks

### Data Collection

NREL will subcontract for wind and solar data development. Mesoscale
modeling of 10 minute wind at 2 km resolution for 3 years (likely
2004-06). Will also model 1 minute intervals for selected periods for
quasi-steady-state analysis.

Request wind data from utilities and developers to validate mesomodeling
and wind development information to help determine wind sites.

Rank sites by capacity factor and note distance from transmission

### Request load and generation data

Study will need 3 years of hourly load and generation

sub-hourly load samples

maneuverability and constraints for existing resource

historical output for existing wind and solar generation facilities

Transmission load flows by control area operator (obtain from WECC but
they don't have load forecast and load forecast errors). Larson: new
development; WECC has collected 20006 load and load forecast data for
2004-2010 will be in public domain). Gary: What about historical data?
Doug, new policy in December, not sure about availability of historical
data. Talk to Donald Davies. Rob K. said they will have access to
historical data but aggregated.

Abe Ellis: will scenarios include a lot of wind, will have to make
assumptions on transmission development scenario. Not on list, who are
you working with? Debbie: TEPCC working through transmission scenario
process, may be way to tap into TEPCC scenarios. Don't want to assume
transmission that is unrealistic.

## Preliminary Analysis

Significant amount of preliminary analysis before doing production
modeling.

-   Statistical analysis

-   Pre-analysis before model runs

-   Group sites into 10-20 wind regions

-   Statistical analysis with spatial and temporal slices, looking at
    wind/load variability and correlation

-   Production value of wind sites and rank by capacity factor

-   Transmission capability between wind regions

-   Develop preliminary costs for each wind region based on statistical
    analysis, production value and transmission capability

-   Best guess at high renewables scenario (30/5) that is good balance
    of resources, existing and new infrastructure and operability. 5%
    solar may be low; talk during stakeholder discussion. 30% came from
    WINDS analysis. Have less of a handle on solar. 30% energy, not
    capacity; Gary Jordan said that is a lot of capacity. If 30% breaks
    the system, ratchet it to 25% or 20% but start with high level first
    that is ambitious.

-   Develop scenarios to answer specific questions.

-   Meeting to review preliminary analysis and provide inputs into
    scenarios

Bob Smith: what breaks the system?

Debbie Lew: past integration studies said \$5/MWh. \$20/MWh cost would
break the system. Smith: include costs of new capacity?

Mark Graham: Look at existing hydro? Consider pumped storage?

Debbie: Yes, look at existing hydro. Pumped storage a big help to
Colorado study, can help with variability.

More from Debbie: scenarios on in-state, better to bring wind in from CO
and WY, etc. Will have another meeting to review preliminary analysis
and scenario selection.

Scenario Matrix

Run baseline with no new renewables, then 30/5 scenario and adjust level
if needed.

Vanetti: Why start at aggressive high level? Start at 20% that is
consistent with RPS standards.

???: How do you treat wind vs. solar? Aggregate, or separate and
distinct? Debbie: consider them separate; build up by virtual plants
such as CSP and PV plants in southern N.M. ???: from policy perspective,
all viewed as renewables,.

Nick: hold the thought; we talk about it in our presentation

Carr: no new renewables in baseline. TEPCC planning; compliance with RPS
policies. Hold renewables constant or have RPS compliance.

Debbie: CA study hardly leaned on neighbors in WECC. Will model WECC at
current levels and then at high levels in WECC, such as NW study, to
ensure that we are not exporting variability to other region. Answer may
be something in-between.

Bob Smith: baseline no new renewables; will tell us what to do and costs
on how to get to current RPS policies. With rest of WECC, best guess how
to get there; probably something in-between current and high levels of
WECC renewables.

Debbie on variation scenarios: diversified,

Gary ???: definition of mega projects?

Debbie: 1 GW or 2 GW projects.

Gary Trent: How are projects in queues or proposed or not announced?

Debbie: need to address this with six utilities.

Gary Jordan: reason for no new renewables is to give case you're
familiar with. Maybe look at existing renewables versus 15% versus 30%.

HBR?: Is there a scenario that falls between no baseline and currently
projected RPS?

Debbie: Did put something like that originally and still under
discussion. Went to aggressive level and see if you hit the system from
different directions. If it can accommodate 30% renewables at reasonable
cost, then it can handle 20% at even lower cost. Other questions is
impact of geographic diversity, wind forecasting and control area
consolidation.

HBR: maybe not 20%, but just levels equate to state RPS levels.

Bob, WAPA: need 4 volume set of hydro operations from Missouri and WAPA
and Army Corp of Engineers.

Nick: doing simulations; not going to capture all of the warts. Advocate
recognizable baseline and then see what has changed.

Bob, WAPA: and cost difference between using hydro as baseline versus
using hydro as regulation.

Milligan: would like to get folks to present information on hydro system
to work with GE for modeling without all the gory details; some range of
flexibility. Bob: what to do with Mt. Elbert or Cabin Creek. Milligan:
yes, and Hoover or Glen Canyon.

Bob Anderson: if you change the reservoir operating rules, then there
are foregone benefits, and will that be part of the cost calculation.

Vanetti: what extent use Frontier and other work on costs of resources,
and model sensitivities to greenhouse gas adders? (Jordan: yes).
Vanetti: use inputs from FEAST model.

Bob Smith: kind of data get here will be useful in FEAST model because
it doesn't do hourly dispatch.

Bob, WAPA: Steve something from EPRI has done work on costs of carbon
sequesteration.

## Nick Miller and Gary Jordan, GE presentation

Intent is to describe the type of work that will be done, from Ontario,
California and New York, but not to describe the results of the studies.
Starting on ERCOT study and will help them design ancillary services
market for support of wind.

Time Scale: where does it hurt? How does system function? How does
system operate with lots of wind? Not worried about capital and carrying
costs, but more on operational costs.

### Types of Analysis

World already uncertain; load uncertain and always moving. Add in
intermittent renewables; add to variability and uncertainty. Will stress
system; goal is to find when and where.

Statistical analysis is based on uncertainty. How to plan and operate
for them changes based on how close or far off it is.

Production cost with MAPS; 8760, who gets displaced, congestion.

QSS: minute-by-minute power flows; dynamic responsiveness of resources.
Do you have right resources, at what time, and if not, what are the
costs and consequences

Bob Smith: using results of second to determine commitment and dispatch?
(yes). Doing security-constrained dispatch and that's adequate? Yes,
haven't found a problem and have gotten intelligent results. In West,
hesitant to say because more granular system.

### 2010 Scenario

most all results from CEC study. Meso-scale modeling; have identified
specific wind sites connected to the grids and worry about temporal and
spatial impacts. 2010T scenario.

### Temporal Patterns: July 2003

Average versus day-to-day data. Wind anti-cycling with load. Solar more
predictable.

### Spatial Pattern: July 21, 2003

Sum of all MW at Tehachapi site. Think of Tehachapi as monolithic. With
5,000 MW; covers a million acres, lots of different signatures. Lots of
plant to plant variation within Tehachapi. If take one 500 MW plant,
scale it up ten times, then get wrong answer.

### Nomenclature

Always worry about agility of system; things move more with wind and
solar and less predictable. What are changes in system from one time to
the next (from 5 minutes to next five minutes, from hour to hour, etc.).

### Operational Implications

Divide into three time frames: 1-minute, 5-minute and 1-hour. Not
perfect; a lot of spillover.

Bob: difference between operators define regulation and academics define
regulation?

Nick: the labels used has caused us great grief. Define regulation as
contracted to respond to AGC output. LF is to respond to economic
dispatch or laid-in schedules.

Bob: definitions differ (Nick agrees).

Bob Smith: capacity value definition. 10% of its peak? Anyone using it?
Gary: PJM and New York. Do full LOLP analysis, look at ELCC, how many MW
of gas to get to same level of responsibility, and then compared to
simple way. In New York analysis, find capacity factor of wind at when
load is within 10% of peak. A lot easier and close enough.

### 2010 Hourly Load Duration Curves

3 years of data; 26,300 hours. See something different year-to-year but
didn't learn anything year-to-year. Start at 50,000 MW and bottom out at
20,000 MW. Compare actual load with 2010T and 2010X. About 5,000 MW
displacement in middle of time. Divide into deciles of peak versus light
load. Find world gets messy with light load. 6% of total hours below
current minimum for 2010T, much worse for 2010X. Makes people gulp.
Recommend that California should have runback down to about 20 GW;
anything below 20 GW to use other strategies. Not rational for system to
accept every kWh of wind output. Not rational.

### Wind Total Power and Penetration

What's wind penetration for next hour versus load that needs to be
served? On average, wind penetration 15% but sometimes above 40%. Not a
single hour where 12,500 GW of wind resulted in 12,500 GW of production.
Less than 1% of time resulted in10,000 MW of wind. Watch for ends of
hooks but don't necessary to have all the infrastructure to handle it.

### Hourly Wind Penetration

*2010 1-Hour Load and L-W-S Deltas*

1-hour change of net load and load. At peak load, CA load up 1800 MW or
down 1000 MW. Variability increases as load picks up then drops back to
minimum load. Whiskers are worse. At peak, load rise 5 GW. Is it a
problem? Can't tell. It's just more.

### 2010X ABC across day

Notes holiday light load rise. Solar not there and wind "thinking about
it." More stressful and uncertain with more wind.

*2010 3-Hour Duration Curves*

Each year, 50 hours where load increase 8100 MW or more under present
circumstances. Very worse is 9500 MW over 3 hours. Or 11,000 MW over
three years. Do you have to plan for it? Require change? How do you
prepare for it?

*2006-2010 Statistical Analysis*

what are current impacts, what are impacts with renewables, and how do
you plan for it?

Light load conditions a particular area of focus.

### Commitment Week of May 10^th^

Is system agile to handle changes? Does right resource mix exist? Use
production simulation. May in California has heavy hydro, loads not high
so worries about light load conditions. Sum of units that are committed.

### Dispatch---week of May 10^th^

Combined cycle moves around, wind moves a lot (price taker); combined
cycle moves. Who is rationally dispatched? Who gets pushed back when
renewables added? Hydro gets moved temporally a little bit; hydro
production unchanged. Gas generation gets displaced.

### Ramp and Range Capability---week of May 10^th^

At light load, units dispatched way down. Converse at peak load. Look at
chance to move up. Not an issue at peak load. At light load, run out of
range to move down; get some pinch although never went to zero.

### 2010X Ramp Rate Down Capability

At light load, run out of room to move down and run out of range. If
collapses, can't operate system. Either change operating to liberate
maneuverability or add generation.

### Change in Hydro Operation 2010T

Difference in hydro output\-\--shifts hydro but hydro output doesn't
change

### Arizona to California: Path 21

Congestion. Add generation in California; reduces congestion on AZ to
CA.

### California Spot Prices 2010 Analysis

Peak load; wind forecast not perfect. Wind doesn't show up; run
something more expensive; spot prices go up.

Light load---people scrambling to get off.

### WECC Operations Impact 2010

Incumbent generators lose business two ways: spot price goes down and
get less money and sell less generation.

### Total Operating Cost Impact of Intermittent Forecasting

No forecast (U.C. made as wind is zero). \$250 million a year penalty.

Use state-of-art forecast. Get this benefit. Relatively small benefit
from perfect wind forecasting. Increases value of renewables by
\$4.37/MWh. Perfect adds another \$0.95/MWh.

Bob Smith: forecast hourly output? (Day-ahead).

Bob, WAPA: Compare versus load? Yes, compare with load forecasting.
Philosophical question: load forecasting not perfect, costs associated
with it but there are huge costs towards not doing wind forecasting.

Bob Smith: Yellow bars costs of in-hour regulation. Nick: No, lost
benefit. Realize less benefit of renewables if you didn't see it coming.
Wind is less valuable.

Hawkins: added cost of operations without forecast?

Miller: Penalty of less economic operations. Instead of a \$35 benefit,
see a \$30 benefit.

### Monthly Capacity Factors

Seasonal pattern. Not windy in summer.

### 2001 Average Load Versus Average Wind

NY peak July August Sept. Average wind output statewide by month. Not
good wind during peak times, although not zero. Value of wind generation
in NY about 10%. Ontario more like 17%. Middle East study---value higher
than capacity factor; wind screams at middle of highest day. Site in
Mediterranean.

Wind in NY not a great capacity resource.

### 2010 Load Duration Curve

what happens at light load---do you need to adjust resource mix to shut
down at light load?

Dig in and look at 50 3-hour windows out of three years of data. Look
for high load, high wind, light load with high wind, fast load rise with
low wind.

Bob Smith: July 21; load about 47 GW where peak load 53 GW. Don't
believe it.

Nick: different ways to quantify intra-hour variability.

### Night Demo

Three hours of light load condition. System way down. Tons of wind.
Producing 10 GW of wind.

Down power ramp exhausted. Load dropping; short resource stack to draw
on. Run out of down range. Fudged this case---took some resources out of
stack. Actually didn't find hours in simulation.

Happens once in a while. Curtail wind by 500 MW. Relieves regulation
problem. Lose 1,140 MWh out of 30,000 MWh.

Bob \_\_\_: part of PPA or legal agreement.

Nick: technical doable. Not a lot of energy lost but need contractual
and legal infrastructure in place. Not rational to spend a lot of money
to plan for occasional event when contractual mechanism will accomplish
objective. Spot prices low; wind not valuable anyway.

Bob Smith: Using some of the wind to regulate some of the other wind.

Nick: or let wind provide economic dispatch. (?)

### Wind Group Distribution

From Ontario study. Ontario did not evaluate balance of portfolio or
transmission. Did statistics to evaluate boundary conditions for them to
evaluate infrastructure.

10 zones, meso-scale data backed with high-resolution met tower data
from 38 sites. 30 GW system. 10 GW wind most extreme scenario.

What is expectation that this bubble will move in direction that is
problematic? Here, bubble may be PNM vs. Tri-State.

### Coincident Wind Analysis

Coincidence Factor between all zones is 0.3. If something screaming in
bubble 10, not happening in bubble 7.

### Wind MW by Zone in Scenarios

NY used to have 11 control areas; not have one.

### Zone E Load and Wind

Zone doesn't have enough native generation to work with lots of wind.
Works just fine with NY having one big control area. See application to
Western work.

Bob Smith: Have adequate transmission in that zone? Yes.

# Debbie Lew

Good to get a sense of what GE can do. Putting subcontract in place with
GE. On details, run more scenarios or less, lot of flexibility and why
we are asking for your input today. Focusing on economic dispatch and
not so much on bilateral contracts---is that workable?

For QSS analysis, huge amount of work and don't get that much new
knowledge; is it best to do a spreadsheet quasi-QSS analysis. Need
feedback.

For each scenario:

Transmission load flow

Run MAPS for

Rheinhold?: for PSLF, need base case before doing stress case. Base case
has to be agreed upon. Is there a point where there is agreement for
assumptions in base case before stress cases applied?

Lew: stakeholder meeting after preliminary analysis done and scenarios
developed. Time for input then. (Rheinhold agrees).

Lew: TRC, one person from each utility, UWIG, WestConnect, Rob K. on
transmission, Doug Larson. TRC meeting more frequently.

# Charlie Smith

Process at beginning. Transmission not picked for a while; contract not
begun yet.

Start with Question to Considers slide from Debbie.

Ron Lehr: eastern side of N.M. in SPP. Middle of WY is mystery land;
PaCIFICORP from West and TOT3 in Wyoming.

Charlie: Resolution balancing areas in study? Include these areas in
study? Figure out what are final boundary areas

Ron: Yes.

Debbie: Looking at WECC area of N.M.

Bob Smith: even if not WECC, look at wind and how tied into WECC. Assume
radial feeds into WECC.

Bob Anderson: Map kind of stylized and curious. Rectangle in part of
Montana---would eastern Montana be included? Is SE New Mexico excluded?

Charlie: Part of drawing map is to include areas not in current
meso-scale models. Try not to overlap with BPA model; idea is to have
meso-scale for all of WECC.

Larson: boundary of control areas of NM, AZ, NV. Is there value and
budget to expand analysis to include WestConnect's study on virtual
control consolidation?

Rheinhold: would pick up El Paso and southern New Mexico and Xcel and
Tri-State. IID in CA another exclusion. Reasons for exclusion from wind
study somewhat compelling because studies already been done and because
of budget limitations.

Larson: If they do AZ, CO, NM and NV, how will this study be used in
WestConnect consolidation study?

Charlie: project team should consider; would gain benefits of smoothing.
Will take it under advisement.

Jordan: will look at load and resources throughout WECC. Will look at
load and generation profiles, but the three-state area is focusing on
sub-hourly load impacts and minute-to-minute LF and regulation issues.
Will see some impact on WECC but won't dive down into short-term.

Charlie: could do three states to begin with but do sensitivity to
expand outside of 3 states.

Jordan: Gather data below hourly level in three states. Real fast stuff
done locally anyway. Will look at dynamic scheduling and control areas
more broadly. Can expand geographic scope.

Larson: would like to see NREL study plugged in and used in WestConnect
study.

Rheinhold: Timing doesn't work. WestConnect study will be done this
year. This study could help refine it.

Milligan: will have Xcel scenario built in in WECC scenario. What's
missing is sub-hourly impact.

Bob Smith: Will integration costs be for three-state area or for control
area? See integration costs for AZ, NM and NV be somewhat similar, but
Xcel may have different number.

Jordan: From CEC study, had costs for California but operating impacts
throughout WECC. Same thing will be true here but putting wind in
different pieces to focus on different elements.

Bob Smith: Will costs for three-state region or separate costs for each
state?

Jordan: Can do for each state or by control area. If do from WECC basis,
can catch interchanges that are not captured in control area study.

Charlie: Is it three-state from one balancing area or multiple control
areas? Not sure if it is decided yet.

Nick: changes in costs are changes in variable costs of production, not
capital or carrying costs. If generators lose out, that is not a cost
but just market forces. Will report market effects but not consider it a
cost. If you have to do something economically sub-optimal because of
renewables variability, like buy more regulation, then that is a cost.
If have to commit sub-optimally, that is in the gray area. May be a
market impact because already commit sub-optimally. If have to procure
additional ancillary services, that is a cost. Will come out of
statistical work, not so much a MAPS work.

Abe Ellis: would like to see study done both ways. One of outcomes is
assessment of integration costs with and without doing something about
control areas. Will take some time to do something about control area,
so need to figure out benefits of consolidation and understand urgency
in moving in that direction.

Nick: we agreed to do that.

Abe Ellis: valuation of reliability impacts and CSP2. standards are in
flux, initiatives to change. Will there be sensitivities to account for
change in control area standard?

Nick: let me answer part of it. Have identified CSP2 to look at. Covered
some new ground in California via combination of time sequences and
mapping of statistical work. It's an analytical approximation, as CSP2
is highly non-linear. Don't want to do thousands of hours of 1-minute
simulations. Have to map between time series of simulations and
statistics to see expected proxy impact on CSP2 in California. Concluded
to see CSP2 being 2% worse. Not a high precision exercise. Expect to do
it here on existing control areas and integrated control area, but
recognize it's approximate. For other standards, not on our radar and
maybe it's open to discussion. Don't have a sense of how we do this work
so reluctant to say yes.

Charlie: Looking at other metrics besides CSP2 not in original SOW but
can and should be discussed. GE can't commit right now.

Abe Ellis: for transmission, assume unused transmission is available to
put wind on transmission? Lines have rights associated with them. Will
flexible firm be an assumption?

Gary: Yes, use available transmission.

Charlie: Assume full compliance with Order 890 on CF.

Richard, CO PUC; how to handle 5% solar, given data differences and
inputs. How will it be modeled? What different integration costs between
wind vs. solar?

Nick: First time we did solar in California. Still on learning curve.
Scenario with distribution of PV done by county and discrete CSP plants
(Stirling, parabolic trough). Hourly solar insolation data mapped to
production by zip code. Put PV in as load modifier. Time synchronized
with weather and with load. CSP insolation looks like wind profiles.
Sub-hourly; stitched 3-minute data and 1-minute data from another source
and did dance to come up with something defendable. But looks like what
we did for wind: time-synchronized production by site.

Gary: For CA, look at integration cost by intermittency. Lumped solar
and wind together. Maybe break those out in this study for wind alone
and solar alone. Don't worry about solar at 2 a.m.; high solar at low
load periods not an issue. Very different impact

Richard: See inverse correlation between wind and solar?

Gary: Yes, solar correlated well with load and the opposite for wind.

Richard: Well, with weather, you have wind and not solar.

Nick: Broad diurnal correlation

Bob Smith: Wind in different geographic locations

Mark Mehos: Can model CSP to include storage and can tailor dispatch
whether to maximize revenues or have dispatch late in evening. Nick:
Lots of storage. Meho: 3-4 hours of storage in southern California, in
northern California, 6 hours of storage.. Nick: Have to take that into
account. Did not do that in California.

Charlie: study years 2004-06? That data available? Heard from Doug and
Rob that WECC will have hourly data available. 2006 data available by
control area. WECC data by balancing area (Mark at Tri-State).
Approprtion data by control area (Charlie).

Jordan: data by control area what we need. Need hourly, will need
10-minute load data by control area. For 1-minute, need 1pminute load
data. Have to account for

Charlie: Will look at you for 10-minute load data.

Bob Smith: Want forecast? (Need hourly forecast). Will have to work with
control areas and figure out to get it from you.

Larson: Don't want to have two sets of data between this study and WECC
study.

Bob Smith: Need finer resolution for this study that WECC won't have.

Charlie: Is hourly data you have different than WECC hourly data?

Bob Smith: No (laughter).

Gary Jordan: Want hydro data as well. Want to see hourly operation of
hydro for three years.. Some will be flexible and to take account for .

Abe Ellis: Need data covered by NDA such as heat rates?

Gary Jordan: Ideally work with WECC database. Have done NDAs before. Not
sure about data with ramping. Unit minimums, maximums, etc. If that's
available in WECC database

Charlie: If we need NDAs, we'll enter into them.

Bob Smith: Will need NDAs to get forecast data.

Kevin: Ramping data.

Nick: California ISO did a lot of homework and GE did a lot of scrubbing
to make it not overly sensitive.

Vhadlseiv, Nevada Power: Need NDA.

Doug: WECC created general ramping data for vintages of machines.

Gary: If done from good data, may be good enough. In California, took
unit-specific and make it generic.

Hawkins: any data from GADS? From NERC?

Gary: Rolled together by size and type. Probably not enough
unit-specific info and no ramp data.

Abe Ellis: WECC database---refer to control operator simulation tool at
PNL?

Doug: Out of SSG-WI and put in ABB model.

Abe: PNL has model for all of WECC in 2002 or 2003.

Doug: Defer to WECC as much as possible to allow it be a standard for
regional transmission planning.

Bob Smith: WECC data has a lot of generic data in it to allow it to be
open and be more transparent. If we send confidential data, does that
devalue results of study?

Charlie: Look at WECC data and see if it's adequate. If not, then
explore other mechanisms.

Abe Ellis: Will you need interchange data?

Nick: Might like to look at it, but for most part, we'll schedule it.
Will try to drive study system as if done rationally.

Hawkins: Any chance of looking at changing interchange schedules on
hourly basis down to sub-hourly basis?

Gary Jordan: One thing that came out of California study is variations
in CSP2 falling on hour-to-hour change with interchange schedules
(self-inflicted wounds). If it would help to change more often, yes, but
will we push for it? No.

Charlie: Intra-hour variability accounted with resources within study
area. Can we expect to do 5-minute changes by control area operator by
2015 in WECC?

Abe Ellis: Consider dynamic scheduling. Export variability out of
control area. Can't take in 4,000 MW in N.M. anyway.

Charlie: Will be addressed in single balancing area case. Longer-term
question of faster balancing mechanisms than once an hour.

Nick: Don't see finer temporal analysis than 1 hour for all of WECC.
Intra-hour; all on table within study area (including resource areas).
Nothing sub-hourly outside of black line other than observations.

Abe: Look at 3000-4000 MW in N.M. with finer sub-hourly; manage
variability with dynamic scheduling. (?)

Vlad from NV Power: Wind data?

Charlie: Separate RFP from NREL.

Debbie: Want to work with folks on selection of sites. Put a separate
subcontract for 10-minute wind data and work with utilities, AWEA, wind
developers on wind sites and build up virtual wind farms. If anyone has
wind data, we need it to validate (Vlad has 1-kM data).

Michael: Keep raw 2-kM data in raw form and do lots of case studies.

Charlie: Need to mesh three areas: California, Northwest, and this study
area. Expect to have complete meso-scale data for all of WECC. Have
time-coincident load data and wind data.

Bob, WAPA: Minute-to-minute wind, load generation data at WAPA office.
Some drop-outs. For Colorado, not study area. Talk to WAPA operator out
of Phoenix.

Charlie: Some data within hour would be helpful.

Tom Carr: (to Milligan). If we build up good wind data for region, can
that be put back in TEPCC effort?

Milligan: Yes, that would be intent.

Jerry Smith: What are meso-scale needs for solar?

Debbie: Will pull off from other NREL solar database.

Corbus: Will get output from meso-scale model but if something

Mehos: Have high-resolution satellite data on hourly. Sub-hourly data
not available except from met stations or with statistical analysis.

Charlie: Solar data from a variety of sources, some from meso-scale,
some from satellites.

??: wind data from parks, military facilities.

Gary: Exclusion zones used for national parks, etc.

Rich: Models pick up everything and then get maps to exclude land use,
transmission, etc.

Charlie on Methodology

Will Quasi-QSS analysis suffice?

Gary: Use California work to benchmark and validate quasi-QSS analysis.
Then apply quasi-QSS work.

Nick: QSS analysis is very labor intensive. Wind, solar, load all at
one-minute intervals. Results could be figured out with
back-of-the-envelope. Can do more with spreadsheet work. Won't solve for
a load flow every minute, but will start with a solved load flow.

Bob Smith: Make sure approximate limitations such as path rate limits
put in MAPS are correct, but make sure that something not happening
within hour that affects reliability (yes). Never worried about this
with SSG-WI and TEPPC.

Nick: value is show me. Worry about intra-hour variability because
syhstem is moving with intermittency. Time simulations illustrative and
helps to determine what system needs to have happen and when.

Bob Smith: Either have adequate maneuverability or import regulation
from other areas?

Nick: Six consolidated versus six balkanized.

Bob Smith: With six control areas, if at constraint, won't allow
regulation import?

Nick: Yes, but will recognize control areas on "blob basis".

Mark from Tri-State: Will quasi-QSS look at load level?

Nick: will look at interesting periods. Walk through it and make sure
system behaves as statistical work and coarser time period states.

Charlie on Flat Block Comparison?

Charlie on movement from cost-based comparison to benefits from adding
renewables to system. Somewhere on continuum between those two end
points.

Gary: Energy value varies by time of day. Comparisons with flat block
don't add much because don't capture energy value difference. Not an
integration cost, but market opportunity cost or value of energy
difference. Hydro worth a different amount if flat versus different
amounts of time of day. If you have to pay more for regulation, that is
a cost assignable to wind. If you have to move units around that cannot
make market sales, that is a market opportunity cost, not a wind
integration cost.

Charlie: See this with Avista and Idaho Power studies. Wind integration
cost took a hit because hydro held back that could have been sold.
Philosophical question. Unit commitment?

Gary: Unit Commitment falls into value of energy issue.

Tom Acker: Some discussion with IEA, and a recent result is take
holistic look at value of wind energy in system is right. In lieu of
that, studies that identify integration costs of wind but studies that
take holistic look better.

Charlie: International studies focus more on benefit of renewables and
less on cost impacts.

Brennan: Move hydro units around, affects efficiency and that is a real
cost.

Nick: If move hydro units around, that comes out in total production
costs. Philosophical question: introduce new resources, other generators
move around, production costs move around and heat rates affected, that
may not be a cost and may be more of a market impact.

Brennan: Differences are fuel limited with hydro.

Nick: Different flavor of opportunity cost.

Bob : People and legislators said you shall do renewables. Societal
cost.

Nick: Introduction of renewables to supply load lowers cost on
incremental basis. To call differences what is and what might be as
costs, we have a philosophical issue.

Milligan: For those that have to respond to PUCs, is an integration cost
worth chasing or something we put in the whole bucket?

Jerry Smith: Political question that needs attention. Question that
doesn't have an answer is how big is it and what's the value of it, and
is it significant enough to drive the political equation?

Ron Lehr: Society and voters have spoken. The question is how to do it
in a least cost way?

Bob: Don't see RPS standards going down; problems will become
challenging and opportunistic.

Charlie: Studies five years ago focused on costs and now moving towards
identified value. Keep moving along continuum. Can probably satisfy both
needs for two of three costs, and third has always been difficult.

Nick: Success in part depends on composition of generation portfolio,
i.e., cycling, ramping capability, turnback but are not valued by any
market signals. Need to factor these attributes in resource adequacy,
ensure they are appropriately valued. Load following---see more activity
in California but did not identify particular cost. If there is a load
following market, then could identify the market costs.

Bob: Plant managers identify costs in terms of increased wear and tear,
lost fuel, etc. but in market bids, that comes out in the wash.

Hawkins: RT price changes every ten minutes as units move up and down.
Will be economic impact.

Kirby: Don't see hourly market clear at different price.

Gary: New York study---a system operator said combined cycle units did
not want to move within the hour so weren't made to. GE asked what they
were paid to do load following---nothing. Why are you surprised?

Intra-Hour Varability by Load Area or Resource Area? (If wind farm in WY
and serve AZ?)---Charlie: depends on where you draw the circle. Is
dynamic scheduling the way to handle this? Bob Smith: if control areas
purchasing wind from other areas, will dynamically schedule.

Abe: Are we missing El Paso Electric? Have load and good wind.

Charlie: Will review that after the meeting. Some adjustments to
boundary need to be made.

???: El Paso part of WECC.

Bob: Will this study look at how hydro system is operated now and why,
and add to that?

Charlie: Not a wind/hydro integration study but will look into how hydro
will be operated.

Gary: Use hydro as peak shaver. Didn't see hydro moving more than 1500
MW from schedule. Variability less than from adding in wind. Looked at
impact on Pacific NW, but impact was minimal. Would want to look at
historical operation of hydro, how much variability is there. Looked at
limiting variability of hydro in California, but trade-off: if can get
variability out of conventional hydro and will do that; otherwise, take
30% efficiency loss on pumped storage.

Tom Acker on Hoover discussion: Looking at study with Arizona Power
Authority. Have certain energy and capacity to use within month, but
have a lot of flexibility. Can use within boundaries of this study.

Charlie: Some attention to how hydro variability modleed needs to be
paid, but not a detailed study of hydro variability.

Acker: May be some value after this study to extract information on
hydro units move and then ask hydro operators to see if their operations
will be affected.

Charlie on Day-Ahead, Real-Time Markets

Charlie: Intra-hour within study area, hour with WECC seems like a good
balance. Not sure how about where day-ahead discussion goes in West.

Bob Smith: Seems like load transmission up to limit, only question is
what do in hour. (yes).

Mark on Tri-State: How to account for day-ahead and three-day-ahead
scheduling, and WAPA hydro we have that is scheduled day-ahead? Can go
down a little but not up on prescheduling. Can you work it in?

Gary: with hydro scheduling, schedule hydro to load. Schedule hydro to
what is expected to be doing, or schedule hydro to actual wind and
actual load?

Ron: File comments on WestConnect RFI; reserve sharing in-hour would be
more valuable to wind. Flag that as consideration for scoping timing.

Tom Carr: At Portland meetings, was there difference between areas with
intra-hour markets functioned more easily? (Charlie: International,
yes). Intra-hour seems to make it easier.

Charlie on Answering the Right Questions?

Jerry: What transmission modeling needs? Do you need prior work from
Frontier, CDEAC, Trans-West Express? Build through national parks, etc.?

Charlie: TEPCC efforts being factored into study. Statistical and
preliminary analysis being done. Stakeholders meeting at that time.
Broad transmission assumptions will be available for that time.

Jerry: Take costs out of that study?

Gary: Take costs out. Looking at operational costs. Wind not being added
because it's the lowest cost but because of a decision to add 20%
renewables. Study looking at feasibility, not whether it's optimal
economics.

Charlie: Not a transmission study.

Jerry: Transmission lines not focused on renewables; this is a
renewables study. Will have to plan for new studies if transmission
needed not identified.

Gary: Lot of activity already; not sure if anything missed.

Jerry: Lines not planned to carry more renewables.

Charlie: New generation needed by 2015; capacity added to base case for
reliability purposes.

Gary: Yes. Like to build off studies being done. Like to build off
transmission expansion plans from WECC but not do our own. Realize wind
and solar primarily energy, not capacity. If generation planned, leave
those in and add in renewables and see change. Will also have emission
impact information.

Charlie on voltage stability

Charlie: Detailed questions on transmission system design and stability
not part of this study; primarily focused on operations.

Ron: See this study turning towards the benefits side; urge focus on
least-cost ways of integrating renewables. What do we need to do across
West? In a carbon-constrained world, see energy as a more valuable
commodity.

Larson: In agreement on six-control-area versus three-state control
area? (yes)

Acker: Modeling costs of transmission additions as best you can.

Gary: Yes. If need to go to best wind resources, and that requires an
additional 500 kV line, that incremental cost will be estimated. But
focus more on operational costs. We're doing crayon-level transmission
planning.

Jerry: What extent is study a displacement study, or a different mix of
resource additions focused on renewables and to how existing system can
handle renewables?

Gary: Yes to both. From California, if add lots of renewables, need
flexibility to balance of system and consider that with resource
additions.

Jerry: If move towards a displacement study, start at existing RPS
levels and move up. If 35%, optics difficult. Don't start off with
something that will rile up folks.

Nick: concerned with incumbent generators?

Jerry: Yes.

Gary: Someone's ox will be gored---a reality from putting in that much
wind. Same with 30% nuclear. Bring in something new, will displace the
old.

U.K. person: if encourage load growth, not displacement.

Gary: Not 30% load growth.

Gary Trent: How to handle must run?

Gary: Yes. All transmission constraints.

TEPCO: If new transmission added, that will be factored?

Gary: Yes.

Nick: If add new line, changes stability impact on interface and RMR
requirements, we're not doing full-blown stability analysis. Not doing
nomagram development.

Ron Lehr: saving \$200 million/year with CO RPS since 2004, as compared
to claims that costs \$3 billion. Be bold and take on even larger goals.

Mansueti: Study funded by taxpayers. Be careful on how to craft the
executive summary.

Nick: Get thick skins from doing studies. Incumbent generators with
history a little gun-shy about these studies. With California, can be
done but not without planning and with correct rules and so forth.

Paul ?:

Hawkins: dynamic stability on light load with high wind and nukes on.
What's dynamic response? Working on it this summer with GE.

Abe Ellis: Like to offer data for 2004 from our integration study for
validation. Full set of schedules, load and wind data.

Harvey, AZ Power Authority: When will you talk to us?

Acker: Down next week.

Harvey: Concerned with across-the-board characterization of CO River
basin. Distinct. 7 states with strong feelings about water.

Doug Larson: 30% of three-state study area?

Debbie: In those six control areas.

Doug: And renewables in rest of WECC?

Debbie: With current levels of renewables in WECC and high levels from
CA and NW studies. Say 20% in WECC.

Abe Ellis: Time frame of 30%?

Charlie: 2015.

Mark from Tri-State: going beyond 2015. Can this study be used for
expansion study with new balance of generation and renewables for 2020?

Nick: It would be input but not exhaustive. Will quantify requirements
and set of resources to add. Don't want to move the horizon too far out
because one can assume everything to get the answer you want.

Charlie: IRP plans would see useful input for what kind of resources
would be useful to add.

Mark: Projections on changes in integration requirements over long term?
How do integration costs or benefits vary or trend over long term?

Nick: see some improvement through some contracts, so forth, rolling
off.

Gary: With 30% renewables and carbon tax, may see increase in
retirements. Won't look at retirements but needs to be considered. May
see load growth, planned retirements and accelerated retirements.

Jerry Smith: Best value out of study is defining operating constraints
and limitations from implementing large amounts of renewables.
Information not available when regulatory demands made, but information
can be used for future resource and transmission planning.

Brennan: Hydro constraints from Hoover will be important information and
how they interact with water constraints.

Nick: With light load situations, CA ISO understands peak load
situations.

Hawkins: Peak load not a problem; all wind that shows up is welcome. At
light load, get generation at time that is not needed. Like idea of
spilling resources or wind. Wind not being there for peak load not a big
reliability modeling.

Doug Larson: Model Hoover or Glen Canyon based on historic dispatch?

Gary: Monthly energy, minimum and maximum operating points. Then see
model predictability of hydro variability and how it changes with wind.
With historical operation of hydro, use that as a validation of the
simulation.

Doug: Would it tell you the value of changing hydro dispatch?

Gary: Possibly.

Hawkins: Could be complex for hydro what to do, as hydro optimized with
thermal resources; wind another variable. None of modeling perfect on
what that future scenario looks like. Other recreational constraints
(rafting, fishing).

Tom Carr: With low period, maybe scenario is innovations on how to
handle it like plug-in hybrids at night.

Bob: DOE and EPRI doing work on plug-in hybrid.

Charlie: Price-responsive load and demand response. Not in this study,
but next round of studies.

Jerry: Not all wind peaks during night. Wyoming wind peaks during peak
hour.

Ron: 15% Xcel study; biggest source of variability was Arc furnace in
Pueblo. Cheaper to call the Pueblo folks. Think of those anomalies.

Nick: Yes. Want to frame questions as to uncertainty of load versus
uncertainty of wind. In California, pump loads a big kick.

Harvey: For Colorado river, high flow versus low flow?

Gary: Will look at three years of history and data on variability of
hydro. In CA, conflict with high wind, low load and lots of hydro. Have
so much free energy don't know what to do with it. Spill the wind. Value
of wind in dry hydro year more because of need for energy. Will need to
consider sensitivity with low hydro.

Charlie: Could be a sensitivity case.

Data Needs

See Debbie or Michael's notes.

Next Steps

TRC meeting to be held soon to work on statement of work.

Meso-scale subcontract. Out by end of year, public data.

Kevin to work on data collection.

WestConnect to make web site for study with presentations and scope of
work once nailed down.

Linda: What's comparison of meso-scale techniques?

Debbie: Interested in doing that comparison and may do as a research
project. Will redo California to include 2005 and 2006.

Gary: Not just wind production but also day-ahead wind forecast.

Debbie: Next stakeholder meeting will be probably a year from now, say
April 2008. Will provide updates through regional planning groups,
WestConnect.

## Take-Aways

Expand study region to include WestConnect

Consider doing a 20% scenario

Do three-state control versus six-utility control area