IEEE Power & Energy Magazine - November/December 2019 - 39

PG and E Area 2018 Peak Day Load Profile
25,000

Peak
Shift of 1 h

Load (MW)

20,000
15,000
10,000
5,000
-

8 10 12 14 16 18 20 22 24
Hour Ending
(a)

PG and E Area 2028 Peak Day Load Profile
25,000

Peak
Shift of 2 h

20,000
Load (MW)

issues are compounded by load modifiers, such as energy
efficiency, demand response, time-of-use rates, and electric
vehicle charging.
The uncertainty in net load forecasting, including D-PVs,
is a concern for BPS reliability studies. The CAISO coordinates its load forecasts with and relies upon long-term
forecasts produced by the California Energy Commission
(CEC). The CEC's energy-demand forecast includes an
hourly estimate of the consumption load and load modifiers
to develop the managed outlook by which the transmission
system is planned.
Since D-PVs is shifting net peak load periods, the selection
of critical study conditions needs to change. Planning standards
require an assessment of peak and off-peak conditions; however, with large numbers of DERs, critical system conditions
may not occur during either of those periods. This requires
even greater numbers of sensitivity studies of varying dispatch
and load scenarios, including peak gross load, peak net load (at
the transmission-distribution interface), and minimum net load
conditions (for example, a spring weekend during off-peak load
conditions). Tables 1 and 2 show how DERs were incorporated
into the CAISO study scenarios during the 2018-2019 transmission planning process. In addition to these sensitivities, consideration for BPS-connected generation dispatch and assumptions for neighboring planning areas are critical as they impact
local or wide-area reliability issues. This leads to the need for
wider coordination between planning administrators.
With the increasing penetration of DERs, CAISO has
explicitly incorporated the forecast resources in power flow

15,000
10,000
5,000
-

8 10 12 14 16 18 20 22 24
Hour Ending
(b)

Consumption Load

Managed Load

figure 4. The PG&E net load impacts from DERs.

table 1. The baseline scenarios and DER contributions.
Day/Time

BTM-PV

AAEE

Scenario

20:20

20:23

20:28

20:20

20:23

20:28

20:20

20:23

20:28

Driver

Summer
peak

10 Aug.
HE 18

14 Aug.
HE 19

18%

90%

81%

76%

Hour of maximum
managed load

Spring
off peak

5 Apr.
HE 12

6 Apr.
HE 13

16 Apr.
HE 13

79%

84%

85%

58%

56%

49%

Hour of minimum
managed load

28%

Hour of minimum
consumption

72%

Hour of maximum managed
load during winter

Winter
off peak
Winter
peak

13 Feb.
HE 4
15 Oct.
HE 19

3 Oct.
HE 18

3 Oct.
HE 19

0%
0%

77%

76%

AAEE: additional achievable energy efficiency; HE: hour ending.
table 2. The sensitivity scenarios and DER contributions.
BTM-PV

AAEE

Scenario

Starting Baseline
Case

Baseline

Sensitivity

Baseline

Sensitivity

Summer peak with high CEC forecasted load

20:23 summer peak

81%

Off peak with heavy renewable output and
minimum gas generation commitment

20:23 off peak

84%

99%

56%

Summer peak with heavy renewable output
and minimum gas generation commitment

20:20 summer peak

18%

99%

81%

november/december 2019

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IEEE Power & Energy Magazine - November/December 2019

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