**[COMPARISON OF AC AND DC POWERFLOW SIMULATIONS FOR TRANSMISSION
PLANNING IN THE WESTERN INTERCONNECTION]{.underline}**

**1. INTRODUCTION**

The SSG-WI is presently proceeding with detailed Western Interconnection
planning studies for 'economic' transmission expansion. The methodology
uses "production simulation programs" with transmission modeling and LMP
simulations to evaluate generation scenarios with and without the new
transmission line or reinforcement. The economic analysis will
essentially compare how existing generators, absent new generation
plant, would be economically dispatched differently for a system with or
without the new transmission line. Alternatively, overall economic
benefits will be computed for locating new generation with or without
the new transmission.

***[Impact of a New 500 kV Line in the Western
Interconnection]{.underline}***

Introducing a new transmission line, or reinforcement, impacts bus
voltages and line loadings in the system. The higher the line rating and
voltage of the line, the greater the impact, especially in a sparse
topology network as the Western Interconnection. Also, the higher the
loading on the lines, the greater are the system losses and voltage
differentials, and a different pattern of loop flows. A new 500 kV line
will clearly impact the Western Interconnection significantly. It is
thus required to ensure that "economic" transmission additions do not
also create or worsen a reliability problem in the system.

***[LMP Modeling in the Western Interconnection]{.underline}***

Locational Marginal Pricing (LMP) simulations integrate economic and
electrical powerflow analysis using optimal power flow (OPF) analysis or
Security Constrained Optimal Power Flow (SCOPF). This makes it possible
to minimize system operation costs and dispatch economically available
generators in the Western Interconnection system within generator MW
operation limits and simultaneously enforce transmission line and
control area thermal and area interface limits (a seams problem).

While none of the Western Interconnection control areas have LMP markets
presently as in the Eastern Interconnection, it is still advantageous to
use the method to assess congestion or restrictions in the transmission
system that prevent the least expensive supply of energy from generation
to load. It follows that it is useful to also study the impacts of new
transmission (or generation) in the system using SCOPF and LMPs which
give pricing signals[^1].

In SCOPF, to enable the system to be ready to take on the next N-1
outage in accordance with current NERC/WECC criteria, "expected" forced
outages are taken for a SCOPF generator dispatch. The extent of the
"expected" forced outages (including critical 500 kV outages) that will
be taken with the SCOPF model will thus have a critical bearing on the
SCOPF simulation results and LMPs. Running SCOPF solutions rather than
plain OPF will provide an operations type generation dispatch that will
lend value and credibility to the study.

***[Data for LMP Simulations]{.underline}***

The basic network data for LMP analysis are available in existing WECC
reliability programs modeling for electrical systems. These include
powerflow network bus and line topology, generator and load buses, line
and transformer thermal loadings and interchange area constraints data,
and a critical contingency list.

The minimum additional data required for economic dispatch, OPF, or
SCOPF generation scheduling to minimize the operation costs and dispatch
the available generators, are the following: generator heat rates or
input-output operating cost curves, fuel costs, and generator maximum
and minimum limits for DC simulations. For AC OPF or SCOPF simulations
the following are additionally required: voltage controls, voltage
operating limits and reactive power limits or MW-MVAR capability curves
for generators, capacitor controls, spinning, etc. Note that DC programs
do not have voltage and reactive power controls. To perform 8760 hour
simulations, hourly load shapes are required. Further modeling functions
include hydro and wind generation, outage scenarios, ramp rates,
reserves policy, etc.

It is important that the SSG-WI data base currently planned have data
that is available to all stakeholders who are desirous of performing LMP
studies in the Western Interconnection. Certain individual entities that
perform studies in public stakeholder forums currently withhold certain
economic analysis data stating that these are "confidential". This
practice should be discouraged. An example is "piece-wise" heat rate
curve data of critical units. Fig.1 below illustrates the difference
between "confidential piece-wise" heat rate curve and the "SSG-WI
average" heat rate curve. Critical "confidential" data of specific
generators which are different from the SSG-WI data base could result in
OPF results and generator dispatches substantially different between one
study and another.

![](media/image1.jpeg){width="4.003472222222222in"
height="2.2916666666666665in"}

**Fig.1 Showing "confidential piece-wise" heat rate curve vs SSG-WI
"average" heat rate curve.**

***[Use of ABB Gridview for SSG-WI studies]{.underline}***

From the SSG-WI presentations, it is understood that the ABB program
Gridview will be used for 'economic' transmission simulations and that
it models the transmission system in detail. The program will use
generator and load buses from the GE PSLF and PTI/PSSE programs. Hourly
load curves can be stored and used in the production simulation. Random
forced outages for generators are taken in Monte Carlo simulations. Unit
commitment is by using SCOPF calculations. The program has thermal line
limits and can also use nomograms. Hourly prices, shadow prices and line
utilization can be displayed.

It was stated at the TSG meeting that the ABB Gridview program uses the
DC powerflow algorithm. If this statement is incorrect and the program,
or a newer version of it, uses an AC algorithm instead, the comments
herein of the potential incorrect solutions that may be expected from DC
powerflow programs will not apply to Gridview. However, these comments
will still apply to all other programs using DC algorithms, such as
Plexos which the CAISO uses for 'economic' transmission evaluation, or
any other DC production simulation programs that SSG-WI/WECC may plan to
use or purchase.

**2. INACCURACIES IN DC POWERFLOW AND OPF MODELING**

DC powerflow simulations have basic inherent inaccuracies arising from
the fact that reactive power and voltage control, vital characteristics
of the interconnected electric system, are not modeled. Hence DC OPF
modeling that does not include reactive power and voltage control
operating constraints in determining the optimum economic dispatch and
unit commitment of generators in the system would produce results
substantially different from AC OPF modeling. This is especially true
for sparse systems such as the WECC.

For DC Powerflows :

-   Voltages are made equal to 1.0 per unit value throughout the system.
    This results in an unnatural voltage profile in the system. It is
    well known that the Northwest has higher voltages of about 110%, and
    voltages go down to nearly 100% at critical buses in California as
    power flows from NW to south.

-   The line and transformer resistances are made equal to zero. Hence
    losses cannot be evaluated.

-   As a result, the DC powerflow solution will result in significant
    errors in line and transformer flows.

-   These errors increase as large generator and line contingencies are
    taken in the Western Interconnection.

If losses are lumped with loads, other issues arise; the implications of
this approach will be examined in greater detail in this paper.

***[Voltage Control and Reactive Power Issues in the WECC System are not
Insignificant]{.underline}***

WECC's vulnerability to voltage instability is tied directly to voltage
control and reactive power availability. The following are a few points
of interest:

-   The WECC-wide July 2^nd^ 1996 collapse was due to voltage collapse
    in the Northwest that cascaded into a system-wide blackout

-   A high percentage of the operating transfer capability (OTC) limits
    in the WECC are currently limited by voltage instability and MVAR
    requirements.

-   The attached file 'VOL2004Final' presents the WECC's 2004 annual
    voltage stability summary report on voltage stability concerns
    Western Interconnection --wide (See Ref.1).

-   The dispatch of certain generators for dynamic voltage support, in
    addition to its MW supply, can be therefore critical for system
    reliability. These generators would be dispatched in an AC OPF but
    not in dispatched in a DC OPF because the DC program does not
    recognize voltage control or reactive power.

-   Certain generators in AC OPFs are dispatched for both dynamic
    voltage support and spinning reserves

The NYISO uses an AC security constrained OPF (SCOPF) program for its
market simulation, the main reasons are the voltage and reactive power
constraints of the system which DC programs cannot deal with.

***[Losses in the WECC System are not Insignificant]{.underline}***

The total losses in the WECC system are of the order of over 5000 MW
during peak summer. These are clearly not insignificant and the
treatment of losses must be carefully evaluated.

It was stated that all transmission losses in powerflow solutions are
included with the load located at substations. There were other
statements that loads are obtained from the EMS system of control areas.
These result from real-time AC measurements and are therefore specific
to the loads downstream of the substation transformers. These loads
would therefore correctly include distribution system losses. But should
the loads also include transmission losses?

For a load forecaster to come up with accurate load allocations for
transmission losses, he would need to know the powerflows in the
transmission system for different hours of the day, and then allocate it
to the different load buses by some arbitrary formula; or use gross
percentage loss approximations. If there is a contingency in the system,
for either transmission or generation outages, flows will change in the
system and losses too as a result of redispatch. A large generation trip
in the Southwest could change the losses in the WECC by about 500 MW.

Clearly, lumping transmission losses with loads creates significant
inaccuracies that can be summarized as follows:

-   It is electrically incorrect to include losses with loads because
    loads do not create transmission losses

-   The losses are not insignificant. For peak loads, losses total over
    5000 MW in the WECC. In the Northwest and Southern California,
    transmission losses are about 1000 MW, and about 800 MW in
    N.California.

-   Power flows through lines will be incorrect in DC powerflow
    simulations correspondingly for normal flows, with even greater
    inaccuracies for generation and transmission contingencies

-   Intertie flows (seams) will be correspondingly incorrect between
    control areas in DC powerflow simulations

***[Losses In LMP Computation]{.underline}***

In an LMP solution, transmission losses would be included in the
marginal loss component of LMP (note: marginal loss being the derivative
is twice the value of power flow in per unit because losses are the
square of the current flow), and should therefore be subtracted from the
load to prevent double accounting of losses.

As stated earlier, the New York ISO (NYISO) uses AC OPF simulations in
their LMP market. In the figure shown below taken from the NYISO
real-time market on Jan.13, 2005, the loss component can be seen to be
significantly higher in the Long Island zone, which also has significant
congestion, than in other zones.

![](media/image2.jpeg){width="5.990972222222222in"
height="4.432638888888889in"}

**Fig. 2 Typical Real-time Jan.13, 2005 LMP Recording of the NYISO
Market**

In a current proposal for a HVDC submarine cable project between
Pittsburg substation and the San Fransisco Peninsula, the economic
justification of the project is being made on the basis of improvement
of LMP prices and the saving in transmission losses in the HVDC
alternative compared with power supplied by AC overhead transmission
into the peninsula. This project hence cannot be studied using DC
OPF/SCOPF methods. (See Ref. 2 and Attachment 1).

***[Losses in AC Powerflow Solutions]{.underline}***

Losses are part of the AC powerflow solution and the above inaccuracies
do not occur in an AC powerflow solution or in AC LMP simulations.

***It follows from the earlier discussion on DC powerflow simulations,
that in the preparation of the loads in the database for the WECC AC
power flow simulations, the load data so carefully prepared by the
control areas inclusive of transmission losses will have to be doctored
now in the reverse direction to remove the losses from the loads in the
WECC AC powerflow database! It is assumed that this is being done by
WECC staff or other work groups; but if this is not being done, WECC AC
Powerflow simulations will be correspondingly incorrect!***

**3. COMPARISON OF AC AND DC POWERFLOW SIMULATIONS USING THE 2003 HEAVY
SUMMER CASE**

Table 1 shows the results of simulations of a 2003 Heavy Summer peak
load base case used for OTC operating studies in 2003. The area results
for generation, load, and losses are summarized in this table. Losses in
the AC system are 5371 MW. The case has 144,762 MW of generation and
139,269 MW of load. The transmission losses in each control area are
also shown in the Table..

In the same table, the results showing simulations by a DC power flow
algorithm are included for comparison.

Both AC and DC simulations were performed with the Powerworld program.

Note that the scheduled and actual intertie flows between control areas
are maintained in both solutions and very closely match each other
through the interchange controls in the program.

**Table 1 Results of AC and DC simulations with 2003 Heavy Summer peak
load case**

  -------------- -------------- --------------- --------------- ------------- -------------- ----------- ------ -------------
  **[AC                                                                                                         
  Powerflow Area                                                                                                
  Records                                                                                                       
  --]{.mark}**                                                                                                  

  **Area Num**   **Area Name**  **Gen MW**      **Load MW**     **Tot Sched   **Int MW**     **ACE MW**         **Loss MW**
                                                                MW**                                            

  **54**         **ALBERTA**    **7531.1**      **7680.3**      **-400.1**    **-400.14**    **-0.04**          **240.64**

  **52**         **AQUILA**     **707.01**      **738.47**      **-54**       **-54.02**     **-0.02**          **22.55**

  **14**         **ARIZONA**    **17437.78**    **14470.56**    **2558.4**    **2558.26**    **-0.14**          **395.47**

  **50**         **B.C.HYDR**   **9429.98**     **6212.63**     **2754.4**    **2753.61**    **-0.79**          **463.74**

  **60**         **IDAHO**      **3904.34**     **3157.2**      **506.1**     **506.48**     **0.38**           **240.65**

  **21**         **IMPERIAL**   **859.77**      **690**         **148.1**     **148.35**     **0.25**           **21.42**

  **26**         **LADWP**      **3728.04**     **5617.32**     **-2404.4**   **-2403.77**   **0.63**           **512.32**

  **20**         **MEXICO-C**   **2068.83**     **1860.7**      **177.4**     **177.49**     **0.09**           **30.63**

  **62**         **MONTANA**    **2935.01**     **1634.13**     **1199.4**    **1199.54**    **0.14**           **100.96**

  **18**         **NEVADA**     **4045.98**     **4952.61**     **-966.7**    **-966.64**    **0.06**           **60.01**

  **10**         **NEW MEXI**   **2677.55**     **3154.46**     **-625.4**    **-625.31**    **0.09**           **144.12**

  **40**         **NORTHWES**   **28925.91**    **22873.98**    **4972.6**    **4973.05**    **0.45**           **1031.41**

  **65**         **PACE**       **5787.1**      **5989.7**      **-440.9**    **-440.51**    **0.39**           **237.8**

  **30**         **PG AND E**   **22879.11**    **23885.64**    **-1856.4**   **-1859.16**   **-2.76**          **824.87**

  **70**         **PSCOLORA**   **5743.06**     **6675.07**     **-1110.6**   **-1110.57**   **0.03**           **171.29**

  **22**         **SANDIEGO**   **1684.64**     **4079.79**     **-2490.6**   **-2490.45**   **0.15**           **95.25**

  **64**         **SIERRA**     **1421.47**     **1663.76**     **-299.4**    **-299.09**    **0.31**           **53.89**

  **24**         **SOCALIF**    **13853.57**    **20069.25**    **-6650.3**   **-6650.45**   **-0.15**          **434.74**

  **19**         **WAPA L.C**   **3759.53**     **151.3**       **3482.2**    **3482.37**    **0.17**           **120.84**

  **73**         **WAPA R.M**   **5329.36**     **3743.16**     **1422.2**    **1422.49**    **0.29**           **163.55**

  **63**         **WAPA U.M**   **53.16**       **-31**         **78.1**      **78.43**      **0.33**           **5.73**

                                                                                                                

                                                                                                                

                 **Totals**     **144762.3**    **139269.03**   **0.1**       **-0.04**      **-0.14**          **5371.88**

                                                                                                                

                                                                                                                

  **DC                                                                                                          
  Powerflow**                                                                                                   

  **Area                                                                                                        
  Records**                                                                                                     

  **Area Num**   **Area Name**  **Gen MW**      **Load MW**     **Tot Sched   **Int MW**     **ACE MW**         **Loss MW**
                                                                MW**                                            

  **54**         **ALBERTA**    **7290.02**     **7680.3**      **-400.1**    **-400.1**     **0**              **0**

  **52**         **AQUILA**     **684.47**      **738.47**      **-54**       **-54**        **0**              **0**

  **14**         **ARIZONA**    **17042.57**    **14470.56**    **2558.4**    **2558.39**    **-0.01**          **0.01**

  **50**         **B.C.HYDR**   **8967.03**     **6212.63**     **2754.4**    **2754.41**    **0.01**           **-0.01**

  **60**         **IDAHO**      **3663.3**      **3157.2**      **506.1**     **506.1**      **0**              **0**

  **21**         **IMPERIAL**   **838.1**       **690**         **148.1**     **148.1**      **0**              **0**

  **26**         **LADWP**      **3214.92**     **5617.32**     **-2404.4**   **-2404.4**    **0**              **0**

  **20**         **MEXICO-C**   **2038.1**      **1860.7**      **177.4**     **177.4**      **0**              **0**

  **62**         **MONTANA**    **2834.38**     **1634.13**     **1199.4**    **1199.4**     **0**              **0**

  **18**         **NEVADA**     **3985.91**     **4952.61**     **-966.7**    **-966.7**     **0**              **0**

  **10**         **NEW MEXI**   **2533.25**     **3154.46**     **-625.4**    **-625.4**     **0**              **0**

  **40**         **NORTHWES**   **27890.41**    **22873.98**    **4972.6**    **4972.6**     **0**              **-0.01**

  **65**         **PACE**       **5548.9**      **5989.7**      **-440.9**    **-440.9**     **0**              **0**

  **30**         **PG AND E**   **22055.29**    **23885.64**    **-1856.4**   **-1856.5**    **-0.1**           **0**

  **70**         **PSCOLORA**   **5571.5**      **6675.07**     **-1110.6**   **-1110.6**    **0**              **0**

  **22**         **SANDIEGO**   **1589.23**     **4079.79**     **-2490.6**   **-2490.6**    **0**              **0**

  **64**         **SIERRA**     **1367.18**     **1663.76**     **-299.4**    **-299.4**     **0**              **0**

  **24**         **SOCALIF**    **13418.97**    **20069.25**    **-6650.3**   **-6650.29**   **0.01**           **-0.01**

  **19**         **WAPA L.C**   **3635.04**     **151.3**       **3482.2**    **3482.2**     **0**              **0**

  **73**         **WAPA R.M**   **5165.51**     **3743.16**     **1422.2**    **1422.2**     **0**              **0**

  **63**         **WAPA U.M**   **47.1**        **-31**         **78.1**      **78.1**       **0**              **0**

                                                                                                                

                                                                                                                

                 **Totals**     **139381.18**   **139269.03**   **0.1**       **0.01**       **-0.09**          
  -------------- -------------- --------------- --------------- ------------- -------------- ----------- ------ -------------

***[COI Flows in AC and DC simulations]{.underline}***

COI flows are shown on Figs. 3 and 4 for AC and DC simulations. The
lines shown are Malin to Round Mountain \# 1 and 2, and Captain Jack to
Olinda. The differences between AC and DC are about 262 MW between the
two solutions.

Such differences, to varying degrees, between AC and DC solutions exist
for line flows throughout the system arising from losses and voltage
profile differences between the two simulations. It is expected that
similar differences would result in a one year run which essentially
will result in similar errors 8760 times.

![](media/image3.jpeg){width="5.991666666666666in"
height="2.984027777777778in"}

**[Fig. 3 COI -- AC solution: COI Path Flows are the sum of 1514, 1495
and 1639 MW over the 3 Lines]{.underline}**

![](media/image4.jpeg){width="5.998611111111111in"
height="3.4659722222222222in"}

**[Fig. 4 COI -- DC solution: COI Path Flows are the sum of 1429,1403
and 1554 MW over the 3 Lines. Note Reactive Power in MVAR is zero, also
voltages are 1.0 pu]{.underline}**

***[Voltage and Angle Profiles of the WECC for AC and DC
simulations]{.underline}***

Voltage profiles are shown in Figs. 5 and 6. In the AC system,
significant voltage differentials exist between the sending end
(Northwest) and the receiving end (California) and vary from about 110%
to 95% as in the real system. In the DC power flow, voltages equal 100%
for all buses throughout the system, an unrealistic simulation of the
real system.

![](media/image5.jpeg){width="5.999305555555556in" height="6.7875in"}

**[Fig. 5 AC Voltage Contour of WECC showing voltages varying from about
110% to 95% as in the real system]{.underline}**

***[Voltage and Angle Profiles of the WECC for AC and DC
simulations]{.underline}***

Voltage profiles are shown in Figs. 4 and 5. In the AC system,
significant voltage differentials exist between the sending end
(Northwest) and the receiving end (California) and vary from about 110%
to 95% as in the real system. In the DC power flow, voltages equal 100%
for all buses throughout the system, unlike the real system.

![](media/image6.jpeg){width="5.992361111111111in"
height="6.392361111111111in"}

**[Fig.6 DC Voltage Contour- voltages at all buses are 1.0 pu or 100%,
an unrealistic simulation]{.underline}**

***[Losses Comparison -- AC and DC]{.underline}***

The losses in each control area in the Western Interconnection are given
in Table 1. Generation is correspondingly higher in the AC solution. In
the DC powerflow, losses are zero.

***[LMP Powerflow Calculations]{.underline}***

LMP simulations are expected to show similar differences between AC and
DC programs as demonstrated above because of the differences in
generator dispatch to meet system voltage constraints and reactive power
limits of generators that have to be met in the real world of the
electrical system.

***[Unique Differences between Western and Eastern
Interconnections]{.underline}***

In the ongoing discussion of DC vs AC LMP market systems currently
operating in the Eastern Interconnection, DC SCOPF are used in PJM,
NE-ISO and MISO. AC SCOPF is used in NYISO. CAISO is currently planning
for an AC OPF. The DC vs AC discussion is well documented in an article
in the IEEE Power & Energy Magazine issue of July/August 2004 (Ref.3).
In this article the NYISO has given the reasons why they felt that it is
advantageous to go to an AC SCOPF program for their system simulations
where losses and congestion play critical roles. This issue is discussed
in some detail later. NYISO uses AC methods for both their market
simulator as well as their network auctions for transmission congestion
contracts or financial transmission rights recognizing that even though
longer computation time is involved, the results are more valid for
their system.

There are unique differences between the Western Interconnection and
other market systems in the Eastern Interconnection. The Western
Interconnection is sparser, with long EHV lines connecting remote
generation to load centers, and large frequency-responsive hydro
generation located primarily in the Northwest. Spinning reserves are not
uniformly distributed. There is a significant loop flow problem. The
Western Interconnection is subject to power and voltage swings for even
moderately high generation trips affecting the California system. A
market system exists in CAISO that comprises over 33% of the entire WECC
load with high imports over 500 kV interties, so that its impact to WECC
is significant[^2]. The 1996 system collapses in the Western
Interconnection indicated its vulnerability to both undamped
oscillations and voltage collapse. Current operating transfer
capabilities (OTCs) of key interties are limited by both phenomena;
however voltage collapse limitations dominate OTC limits.

**4. VALIDATION OF DC POWERFLOW AND OPF SIMULATIONS IS REQUIRED**

***[Validate the DC Powerflow Simulation Comparing with the AC Powerflow
for a Single Run]{.underline}***

Validating simulation programs against real-time system performance is a
goal in the electrical industry in general and we have been particularly
successful in WECC in this respect. Given the inaccuracies demonstrated,
there is no reason why a DC Power Flow program solving a real network
for voltage and powerflow distribution should not be validated against
real system AC recordings. Such a validation will go a long way to
assure the credibility of the economic transmission evaluation process
based on the LMP studies that SSG-WI has embarked upon.

Before going into an 8760 simulation with a DC program, it is
recommended that SSG-WI should "validate" the DC model proposed to be
used *for a single run* and estimate the extent of error in the
simulations and evaluate the potential error impact on economic
evaluation[^3]. The errors noted from a single run will likely result in
similar errors 8760 times (of varying magnitude) in a one year run. The
'validation' check with real-time operational flows and voltages will
determine the extent of variance and error for a variety of operational
scenarios and contingencies.

The validation could be performed using AC validation basecases already
available with WECC for real system disturbances. These cases have been
checked against monitored recordings of bus voltages and flows before
and after the event. Quantities to be compared between the AC and DC
programs will include generator MW dispatch for each generator, bus
voltages, angles, intertie exchanges, major line and transformer flows
and control area losses.

***[Compare DC OPF Powerflow and AC Simulations with a Single
Run]{.underline}***

After the validation of the 'plain vanilla' power flow is done as
described above, the DC OPF program results can be compared to an AC OPF
program for a single run. The errors noted from a single run will likely
result in similar errors 8760 times (of varying magnitude) in a one year
run.

***[Available AC Programs with OPF or SCOPF Features]{.underline}***

It is understood that robust AC OPF Programs which can perform 365 day
simulations that have special solution techniques for dealing with
convergence are available from vendors such as Nexant. These programs
have been used with large systems in the Eastern Interconnection. Other
vendors with AC OPF or SCOPF programs include Powerworld, PTI, LCG etc.
A copy of Nexant's SCOPE program is attached for information. PTI-PSSE
's url is <http://www.pti-us.com/PTI/software/psse/opf.cfm> .

**5. CONCLUSIONS AND RECOMMENDATIONS**

1.  DC powerflow, OPF and SCOPF programs ignore the very significant
    constraints imposed by AC voltage control and reactive power
    production in dispatching generators.

2.  If these are ignored in a sparse system such as the WECC, we could
    end up having non-optimal dispatch of generators in the real system.
    The results of 'economic' transmission planning which computes
    overall benefit from a simulated 'optimum' generation dispatch could
    very well be open to question by ignoring voltage and reactive power
    system constraints.

3.  Losses of over 5000 MW in the WECC with its long transmission lines
    and remote load areas are significant and can only be modeled
    correctly using an AC powerflow program. These losses generally
    increase during contingencies.

4.  Before the Western Interconnection goes very much further in
    deciding the type of programs to be purchased by WECC for
    transmission 'economic' analysis, it is recommended that a
    validation of the DC powerflow and DC OPF/SCOPF programs should be
    made versus the AC programs. This validation can be done easily for
    a single run. The errors noted from a single run will likely result
    in similar errors 8760 times (of varying magnitude) in a one year
    run.

5.  The oft repeated reasons of non-convergence of AC OPF programs
    should be carefully evaluated in the light of NYISO's insistence in
    using AC programs for their LMP real-time market recognizing its
    very clear advantages in simulating their system where voltage
    issues, constraints and high losses are a dominating feature of the
    NYISO system. Fig.2 of this paper highlights realtime LMP issues in
    NYISO. Improved AC SCOPF programs are available that offer new
    techniques to deal with convergence problems.

Les Pereira P.E.

January 31^st^ 2005

**[References]{.underline}**

1.  'VOL2004Final' - WECC's 2004 Annual Voltage Stability Summary
    Report.

2.  Comments on the Evaluation of the Bay Area HVDC Project, Les
    Pereira, NCPA, Nov.15,2005, sent to CAISO. See Attachment 1.

3.  "The Rights to Fight Price Volatility - Financial Transmission
    Rights Are an ImportantTool in Hedging Against Congestion Cost
    Volatility and Promoting Liquidity in Energy Markets" - by O. Alsaç,
    J.M. Bright, S. Brignone, M. Prais, C. Silva, B. Stott, and N.
    Vempati with contributions from the New York and Midwest ISOs,
    published in the IEEE Power & Energy July/August 2004 Vol2, No.4.

**[Attachment 1]{.underline}**

**[Comments on the Evaluation of the Bay Area HVDC
Project]{.underline}**

The supply of electrical power to the San Fransisco peninsula,
surrounded on three sides by water, is a challenge that is compounded by
the planned retirement of key generating units located at the northern
extremity of the peninsula. Currently, this is through AC transmission
from the south side only through essentially radial feeds from the
Greater Bay Area. This radial system configuration has therefore all the
attendant problems that need mitigation during contingencies, including
overloading of lines, voltage support with supply of reactive power, and
voltage stability[^4]. As the Potrero units retire, "dynamic" voltage
support will increasingly fall on the SVC (Static Var Compensator) to be
installed at Potrero. Also four CCSF combustion turbine peaking units
planned at the same location will provide voltage support provided they
are dispatched and thus operating at the time of the contingency. PG&E,
through a series of upgrade projects, is currently planning to provide
the necessary support of the growing San Fransisco peninsula load, and
also the Greater Bay Area load. However, further reinforcement is needed
for the area.

The HVDC submarine cable project provides power directly to the loads in
the northern extremity of the San Fransisco peninsula from generators
located in the Pittsburg and Contra Costa region, thereby bypassing the
AC transmission feeds from the south side of the peninsula. This
dramatically reduces the losses in the transmission system (about 36 MW
at peaks) and improves generally the voltage and angle profiles of the
electrical system in the San Fransisco peninsula and Greater Bay Area
regions.

Using the LMP (Locational Marginal Price) method of analysis, the
project proponents have attempted to show that the benefits from the
improvement of voltages, flows and losses in the transmission system,
and power from more economic Bay Area generators, will substantially
offset the higher costs of HVDC submarine transmission.

The quality and experience of the internationally known HVDC equipment
and submarine cable manufacturers would appear to be well established.
Therefore, the questions on the project evaluation are focused on
whether the LMP transmission "benefits" and loss reductions have been
properly calculated, and whether the LMP modeling, data accuracy and
methodology adopted are appropriate and correct. Recognizing that this
is a fairly new approach to project evaluation in the industry, and
because there has been considerable debate on the specific methodology
to be adopted, it is appropriate to go into some depth into the
comparison of methodologies and simulation models.

The project proponents appear to have limited the load serving
capability analysis to San Fransisco and the peninsula north of San
Mateo and have not included the Greater Bay Area (see answers by B&B to
questions) stating that the study focus was the San Fransisco peninsula.
The Optimal Power Flow (OPF) program simulations are stated to minimize
the Greater Bay Area cost function. This approach has given rise to
several comments from stakeholders regarding (a) the 'correctness' or
adequacy of simulations, (b) the impact on other areas of the system who
may be 'disadvantaged', and (c) LMP benefits and losses that may be
incorrect if the area of study is expanded to the Greater Bay Area and
beyond.

It is believed that all these questions could be addressed by performing
simulations of the entire CAISO controlled area using an AC Security
Constrained Optimal Power Flow (SCOPF) program, including key
contingencies that would affect the area including outage of the HVDC
line itself as well as other critical contingencies in the Pittsburgh
area etc. This would also be the simulation closest to CAISO's future
proposed operational LMP simulations. The data for the CAISO generation
could be obtained from CAISO who has performed LMP type studies for the
STEP and other projects.

The Security Constrained Optimal Power Flow (SCOPF) considers not only
normal operating limits, but additionally optimally dispatches
generation economically to also mitigate violations that would occur
during contingencies. The list of contingencies to be run for the HVDC
project would include an outage of the HVDC line itself as well as other
critical contingencies, including for instance, N-1 for lines in the
Pittsburgh area which is the source of generation to the HVDC project.
The SCOPF "looks ahead" and dispatches generators optimally so that the
total operating cost is minimized, and at the same time assures that no
security limit will be violated for any of the selected contingencies if
they do occur.

The project proponents have analyzed the annual transmission benefits
(for the first year) by dividing the year into three discrete periods of
peak (15%), intermediate (65%), and off-peak (20%). Since the LMP
simulations have not been performed on an 8760 hour basis, it would
appear that the economics for transmission benefits would likely be
overstated. The accuracy could be improved with a greater sampling of
peaks, intermediate and off-peak levels.

The CAISO's TEAM (Transmission Economic Assessment Methodology) uses an
8760 hour simulation, evaluating total consumer and producer net
benefits, developed with a DC OPF program with essentially generation
planning algorithms. It was completed under deadlines imposed by the ALJ
for the Path 26 Upgrade Project. The method analyzes Path 26 which is a
path between two zones (utilities)[^5]. The TEAM method uses a DC
program that has two disadvantages: (a) *DC-OPF cannot enforce voltage
and reactive power limits and (b) the DC-OPF cannot calculate losses.*
Both the above features are required for a proper evaluation of the HVDC
project. The DC OPF program will basically provide inaccurate results as
far as the HVDC project is concerned which is located in a critical
"load pocket", and for which voltage constraints are critical, as well
as the proper evaluation of losses, both of which are not simulated in
the DC OPF. Using the DC OPF program by the TEAM method will most likely
be prejudicial to the HVDC project.

To provide a fair comparison of the AC alternative to the DC project, a
similar LMP type analysis should also be performed for the AC
alternative.

Comments sent to CAISO by

Les Pereira P.E.

NCPA

Nov.15, 2004

[^1]: These remarks on the advantages of theoretical Western
    Interconnection-wide LMP studies with SCOPF programs and not a
    commentary of the current CAISO efforts in LMP market modeling under
    MD02 using "isolated" system models of CAISO which have substantial
    seams and loop flow LMP and CRR modeling issues still to be
    resolved.

[^2]: In comparison, NYISO, PJM, and NE-ISO comprise about 5% to 8% of
    the Eastern Interconnection.

[^3]: This validation approach was suggested to the CAISO when they were
    attempting to set up their economic transmission planning process
    for the first time for Path 26 studies. On account of tight ALJ
    deadlines, CAISO justified the use a DC program by Plexos to avoid
    the complexity of AC OPF programs citing long simulation times,
    convergence issues etc. They have since continued to use Plexos in
    subsequent project evaluations without validating results of their
    DC program vs real system conditions.

[^4]: It may be argued that a parallel configuration would be Cleveland,
    Ohio, which is located on the Lake Erie shoreline with restricted
    transmission access. Cleveland found itself in an unenviable
    position on August 14^th^ 2003 when a nearby large generating plant
    tripped out and lines supplying Cleveland started tripping out
    thereafter starting off the Eastern blackout.

[^5]: CAISO correctly stated in the Introduction to the TEAM report for
    Path 26 : "We do not consider this report to be the final end-all
    treatise with respect to economic evaluation of transmission
    upgrades."