2022 PC7 Drought Study Report

PC7 Drought Case

(2022 PC7 WGA Drought StudySeptember 19, 2013)

Introduction

The purpose of the 2022 PC7 Western Governors Association Drought Study (WGA Drought study) is to examine the impacts of higher temperatures and changes to the timing and quantity of precipitation and runoff on electricity generation relative to the 2022 Common Case. This study was developed by the WGA, Sandia National Labs (Sandia), Argonne National Laboratory (ANL), and the National Renewable Energy Laboratory (NREL) in conjunction with TEPPC and is based upon work described in the report, Analysis of Drought Impacts on Electricity Production in the Western and Texas Interconnections of the United States: In Support of Interconnection-wide Transmission Planning.[footnoteRef:1] [1: Link to report: http://energy.sandia.gov/wp/wp-content/gallery/uploads/Drought-Analysis-Report-Final.pdf ]

Key Questions

Several potential pathways for climate impacts to electricity generation and transmission were of interest to the WGA as part of this study. The following list of key questions to be answered by the WGA Drought study were developed in cooperation with the WGA and are intended to provide insights into the impact of drought on generation and transmission in the Western Interconnection.

1. What impact does a prolonged drought have on the operation of thermoelectric generation?

2. What impact does a prolonged drought have on the operation of hydroelectric generation?

3. What impact does a prolonged drought, and the corresponding higher temperatures, have on energy demand?

4. What impact do the changes in thermal plant operation and hydro generation availability have on transmission utilization, production cost, and the ability of the Western Interconnection to continue serving its load obligation?

Questions 1-3 were addressed by Sandia, ANL and NREL in the development of study case input assumptions that fed into TEPPCs production cost model study. The findings of Sandia, ANL and NREL are described in greater detail in the Input Assumptions and Study Results sections.

Study Limitations

(Figure 1: WECC Watershed Basin)A number of study case limitations were identified by TEPPC and the study case requestors in the process of scoping the data needs for the 2022 WGA Drought study. To begin with, relative to the impact of drought on load and cooling water, the national labs collaborating with TEPPC on this study case originally identified two possible drought conditions to be considered: a 10th percentile drought year assumed in each individual watershed basin within WECC (see Figure 1), and a West-wide coincident drought using 1977 conditions for each basin. However, due to time limitations it was determined that only one drought condition could be studied by TEPPC, and so the West-wide drought using 1977 conditions was selected as the basis for the WGA Drought study inputs due to its severity and coincidence between multiple hydrological basins within the Western Interconnection.

Further, due to data and resource limitations it was determined that the 2001 hydro data being collected for TEPPCs 2022 PC1-2 Low Hydro Sensitivity (Low Hydro Sensitivity) would be used as a proxy for the hydro generation levels modeled in this drought study. Analysis from the national lab team showed that the loss of hydroelectric generation in 2001 was likely to be similar enough to the loss of hydroelectric generation for conditions identical to those experienced in 1977. Modeled estimates of the potential loss of hydroelectric generation for the hydrological conditions in the basins of interest for 2001 and 1977 are shown below in Figure 2and Figure 3.

Figure 2: Estimated loss of hydroelectric generation from an average year for 2001 flow conditions

Figure 3: Estimated loss of hydroelectric generation from an average year for 1977 flow conditions

It should also be noted that while specific thermoelectric plants were identified as having the potential to be impacted by the drought conditions considered in this study, the specific list of impacted generating units used for modeling purposes is not provided in this document to preserve the confidentiality of those facilities. The specific plants selected to be modeled as impacted by drought in this scenario were identified as a result of the flow conditions in the basin from which the plants cooling water is drawn for the selected drought year and would likely change under different drought conditions. Further, drought mitigation plans for the identified impacted plants were not collected and therefore broad conclusions should not be made about these specific facilities.

Input Assumptions

All 2022 study cases are constructed from the 2022 Common Case. As such, a number of the assumptions used to construct the 2022 Common Case are carried through to each subsequent study case. The following assumptions are those specific to this study case, and may be in addition to or an alternative of those assumptions used in the 2022 Common Case.

Loads Monthly peak demand and energy for all TEPPC load bubbles was increased in the month coincident with the hottest month for that area in 1977 (drought condition).

Transmission System No change to 2022 Common Case transmission

Generation Changes to hydro and thermal generation were made as follows:

Median hydro data was replaced with low hydro data based on 2001 historical hydro conditions (same assumption as used in the Low Hydro Sensitivity study).

Increased forced outage rates were applied to thermal plants identified as having the potential to be impacted by drought conditions.

The drought related input assumptions are described in more detail in the following sections.

Increased Loads

NREL developed adjustments for each of the 39 individual TEPPC load bubbles that increased the WECC coincident peak native load by 2.3 percent and the annual energy load by 0.18 percent. The adjustments applied by TEPPC load bubble were based on the estimated change in peak demand for each of 17 transmission areas in the Western Systems Coordinating Council (the predecessor to WECC) for a high temperature scenario with a 1-in-40 year probability as developed by the California Energy Commission (CEC) for the study, High Temperatures & Electricity Demand: An Assessment of Supply Adequacy in California, Trends and Outlook.[footnoteRef:2] The CEC report was used to develop the load adjustments in response to drought conditions because upon a thorough review of the existing literature addressing the impact of high summer temperatures, which may be associated with drought, it was found that, while there is a strong relationship between temperatures and energy demand, there is no single rule of thumb that says for every 'x' degree above the average daily or monthly temperature, energy demand will increase by 'y' percent. Instead, it was clear that there exists a direct relationship between the number of cooling-degree-days in a given period (month or season) and the peak and total energy demand during that period. Further, it was found that the impacts to energy demand are highly regionalized, and can even vary significantly between neighboring states. As such, the CEC report provided the best information regarding estimating the impact of high temperatures on energy demand in the Western Interconnection. [2: The CEC report can be found here: http://www.energy.ca.gov/reports/1999-07-23_HEAT_RPT.PDF ]

The percent change values reported by the CEC in their 1-in-40 scenario were used to adjust the peak demand of all 39 TEPPC load bubbles, but for only a single month. In order to represent the general climate trends of 1977 (the drought year) the hottest month of 1977 for all states in the Western Interconnection was determined, and the percent change value was applied to the peak demand in that given month. Although the overall change in peak load was minor, there were several areas that had increases between 4 and 10 percent (see Figure 4).

Figure 4: Increase in Area Peak Demand

The resulting increases in peak demand by subregion are summarized in Figure 5.

Figure 5: Change in Peak Demand by Subregion

The CEC report used to estimate the change in demand under drought conditions provided percent change values for peak demand only, but after initial test runs of the WGA Drought study it was determined that both the peak and the energy values required adjustment. By increasing the peak demand and not the monthly energy, PROMOD was taking energy from the off-peak hours and adding it to the on-peak hours to achieve the peak demand increase and net-energy change of zero. To prevent this from happening it was ultimately decided that half of the peak demand increase should also be applied to an increase in energy because it resulted in a stretching of the demand shape rather than a shifting of the demand shape. It was recognized, however, that during extreme heat events the nighttime low temperatures do not cool-off as much as normal. This would be a justification for shifting the entire demand shape up by applying the same percent increase in peak demand to an increase in energy. However, since only one modeling approach could be selected for modifying the demand for all TEPPC load areas, including load areas in Arizona as well as places like Idaho and Wyoming where hot temperatures do not sustain through the nighttime hours, even during extreme heat events, it was decided to go forward with stretching the load shapes rather than shifting the shapes which limits the impact to the demand in the off-peak hours.

Because the peak demands and energy loads were only changed for a single month in each area, the total Interconnection-wide energy load was only increased by 1,828 GWh relative to the 2022 Common Case.

Reduced Hydro Generation

The primary drought impact considered in this study is with regard to the reduction in electricity generation at many of the Western Interconnection hydro projects. The hydro availability was derived from the historical hydro data for the 2001 water year, and resulted in an overall decrease in Interconnection-wide hydro generation of 34,088 GWh. Although hydro production in 2001 was greater in a few areas than the hydro production derived from the median hydro data used for the 2022 Common Case, in other areas, including California and Washington, substantial decreases in hydro production occurred in 2001 relative to median hydro conditions (see Figure 6). This inconsistency is the result of selecting a coincident year for the hydro data inputs but it also reflects the true geographic diversity of the Western Interconnection.

Figure 6: Hydro Impact by TEPPC Area

Loss of Cooling Water Supply

Another drought related impact considered in the WGA Drought study is the potential loss of the cooling water supply for thermoelectric generators that would subsequently result in the loss of thermal generation.

The total loss of thermoelectric generation estimated for the WGA Drought study was developed by ANL and Sandia and was determined independently on an annual basis for each hydrological unit code (HUC)-2 hydrological basin based upon the flow conditions for the year 1977. To accomplish this, a master list of generating units considered at risk was first developed based upon each units dependence upon fresh, surface water for cooling. Figure 7 provides a breakdown of the fraction of thermoelectric generation determined to be at risk in each basin.

Figure 7: At Risk Generation by Watershed Basin

The specific units assumed to be impacted in the drought scenario were then determined by looking at the deviation in flow under the drought conditions in the local HUC-8 sub-basin where the generator is located. All at risk generators in sub-basins where the flow under drought conditions was less than 50 percent of the normal flow were assumed to be impacted. The only two basins within WECC that were determined to be likely to lose thermoelectric generation capacity under the chosen drought conditions were the California and lower Colorado basins.

United States Energy Information Administration (EIA) data was used to develop the initial list of impacted generating units and to estimate total annual generation lost from these impacted units under the drought condition. The total amount of lost generation for the year was then allocated by month based upon the deviation from normal flow in that month relative to other months. The estimated amount of generation lost by basin and by month is illustrated in Figure 8.

Figure 8: Estimate of Lost Thermal Gen by Basin

The amount of lost generation was converted into an average number of down days for each impacted plant by month in a given basin. Finally, the monthly down days were used to modify the unplanned (forced) outage rate for each impacted plant. The impacted units included a combination of biomass, cogeneration, combined cycle, combustion turbine, coal, geothermal and gas-fired steam boiler generation.

Study Results

The following study results are organized according to the Key Questions associated with this case. Additional results of interest are also outlined.

Impact of Drought on Thermal and Hydro Generation

The results reflect both a direct impact on the thermal generation from reducing the availability of certain units via increased forced outage rates, and an indirect impact on the thermal generation as a result of the reduction in the hydro generation. Figure 9 shows the thermal response to the lost hydro energy, and the reduced thermal generation in Arizona and California as a result of the modeled increased forced outage rates simulating the unavailability of plants due to cooling water restrictions. Some of the reductions due to the increased forced outage rates are netted against increases from other units of the same type to replace energy lost from the hydro generation.

Figure 9: Change in Energy by State/Province

Figure 10 compares the monthly energy output for the impacted generators in the California and lower Colorado basins illustrating the reduced generation output as a result of the applied increases in forced-outage rates.

(Figure 10: Comparison of Drought Impacted Thermal Generation)

Impact of Drought on Meeting Load Requirements

Decreasing the availability of both the thermal- and hydro-generation, while increasing peak demand, increases the risk that the system may not be able to meet its load obligation. In PROMOD, periods of unserved load are indicated by the dispatch of emergency generation, and Figure 11 shows that there was a slight increase in emergency generation in the Alberta Electric System Operator (AESO), Comision Federal de Electricidad (CFE), and Public Service Company of New Mexico (PNM) areas. Both AESO and CFE were resource limited in the 2022 Common Case, and since these areas are radial to the Western Interconnection, further decreasing the availability of the local thermal and hydro generation put an even greater strain on the remaining resources in these areas. The small amount of emergency generation observed in PNM is insignificant to the overall study results.

Figure 11: Emergency Generation (Unserved Load)

Impact of Drought on Transmission Utilization

The changes in generation dispatch as a result of the drought assumptions also affected the utilization of the transmission system. This is evident in the changes observed in the regional transfer of energy shown in Figure 12, which compares the transfers in the 2022 Common Case, Low Hydro Sensitivity study and WGA Drought study.

Figure 12: Regional Transfers

The region to region transfers did not change significantly from the Low Hydro Sensitivity study to the WGA Drought study which suggests that the WGA Drought study results are dominated by the changes made to the hydro assumptions and not the changes made to the peak demand or availability of the thermal generation.

The change in utilization of the most heavily utilized paths in the WGA Drought study is illustrated in Figure 13. The Northern-Southern California path (Path 26) was the most impacted due to the hydro reductions in northern California and the Northwest. The other changes in utilization suggest that a portion of the hydro reductions in the Northwest were replaced by additional generation dispatched in Alberta, British Columbia and Montana.

Figure 13: Change in Path Utilization

The effect of the drought assumptions on a few of the individual transmission paths is provided in the plots below. The increased flow on the Northwest-British Columbia path (Path 3), seen in Figure 14, reinforces the belief that a part of the hydro reduction in the Northwest was replaced by generation from British Columbia.

Figure 14: Duration Plot for Path 3

The slight flow reduction on West of Colorado River (Path 46) seen in Figure 15 may be related to the increased dispatch of combined cycle generation in California to make up for the reduction in the states hydro generation. The minimum runtime and other operating constraints defined for the combined cycle units could reduce imports for some hours.

Figure 15: Duration Plot for Path 46

The utilization of the paths connecting the northwest to California decreased in the WGA Drought study, likely due to the reduced hydro energy in the Northwest. The combined reduction in utilization of both the California-Oregon Intertie (COI Path 65) and the Pacific DC Intertie (PDCI Path 66) is illustrated in Figure 16.

Figure 16: Duration Plot for Path 65 + Path 66

The reduction in utilization of Path 26 is due to the decrease in hydro energy in California where most of the states hydro projects are located in the North. The reduction in hydro in the northwest may also have had an impact on the utilization of Path 26 since a reduction in hydro means less energy is available for export from the Northwest.

Figure 17: Duration Plot for Path 26

Other Observations

The results of the WGA Drought study were dominated by the changes made to the hydro generation assumptions, which were the same as those used to construct the 2022 Low Hydro Sensitivity study. Since the majority of the hydro generation is modeled as a must-take resource, fluctuations in the hydro availability have a direct impact on the thermal dispatch. On an average hourly megawatt basis, the amount of hydro generation available to the system was reduced by 3,890 aMW in the WGA Drought study.

The planning margins built into the TEPPC studies ensure that the amount of generation plus imports in each subregion will exceed the load. This makes it unlikely that the loss of a few thermal plants due to cooling water restrictions would create significant unserved load. No significant increases in unserved load were observed as a result of increasing peak demand and decreasing both the hydro and thermal generation to simulate drought-like conditions. Figure 11 illustrates that there was already some unserved load in the 2022 Common Case and the minor increases in unserved energy in the WGA Drought study were confined to the same areas as in the 2022 Common Case.

Study Summary

The key impacts of increased demand and decreased thermal and hydro generation reflecting a potential drought condition are listed in Table 1. The production cost and CO2 emissions increased as thermal generation was needed to replace the lost hydro generation. Although noteworthy, the unserved load in the WGA Drought study occurred in radial areas of the Western Interconnection where the dispatch of emergency generation by PROMOD is a sufficient response to the resource shortages.

Table 1: Key Drought Impacts

Result Element

2022 Common Case

WGA Drought Study

Change

Variance

Conventional Hydro (GWh)

246,879

214,236

(32,643)

-13.2%

Total Var. Prod. Cost (M$)

14,851

16,262

1,411

9.5%

CO2 Emissions (MMetricTons)

359

373

14

3.9%

Unserved Load (MWh)

2,676

3,063

386

14.4%

As with the generation results, the changes in transmission utilization observed in the WGA Drought study are consistent with the results observed in the Low Hydro Sensitivity study. Specifically, the largest decreases in hydro generation relative to the 2022 Common Case occurred in California and Washington which reduced the availability of surplus low-cost generation in the Northwest thereby reducing imports from the Northwest into California and increasing the need for additional resources to be transported from the Southwest into southern California.

Worst Case Loss of Hydro Generation 2001

HydroMissouriTX GulfRio GrandeUpper COLower COGreat BasinPacific NWCalifornia0001.8755411836260726E-301.7824427128953123E-20.220475359182869044.8237520419170773E-2ThermoMissouriTX GulfRio GrandeUpper COLower COGreat BasinPacific NWCalifornia00000000

Fraction of total generation lost (MWh basis)

Worst Case Loss of Hydro Generation 1977

HydroMissouriTX GulfRio GrandeUpper COLower COGreat BasinPacific NWCalifornia1.3848682467282845E-202.7935667380487656E-22.0173888169225549E-31.214024371027107E-22.5828020202042969E-20.197361007023543377.4447571875898483E-2

Fraction of total generation lost (MWh basis)

Generation Breakdown by Basin (MWh basis)

At Risk ThermoMissouriTX GulfRio GrandeUpper COLower COGreat BasinPacific NWCalifornia0.699886013426192940.733482024668790643.3208661534504948E-20.932626359866400080.140377393659044560.431290777965333880.174554444827714769.8408843851984548E-2HydroMissouriTX GulfRio GrandeUpper COLower COGreat BasinPacific NWCalifornia7.2671805680472656E-22.4415563810835351E-35.5191484431941738E-25.3649933528248928E-23.2389607739963799E-26.5150021008417811E-20.682540149293690450.11834671156989182Low RiskMissouriTX GulfRio GrandeUpper COLower COGreat BasinPacific NWCalifornia0.227442180893336290.264076418950126460.911599854033554811.3723706605350943E-20.827232998600991530.503559201026247180.142905405878595490.78324444457812503

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0.0%2.0%4.0%6.0%8.0%10.0%12.0%FAR EASTGCPDPACWSRPNEVPBPATIDCTPWRAPSMAGIC VLYPACE_IDSDGEPGNWACMSCLWALCCHPDAVACFEDOPDIIDLDWPPG&E BAYPSCSCETEPWAUWBCTCEPEPACE_UTPG&E VLYPSETREAS VLYAESONWMTPACE_WYPNMSMUDSPP

Change in Peak Demand -PC1 vs. PC7

010,00020,00030,00040,00050,00060,00070,00080,000

Hydro Comparison by Area

PC1 MedPC7 Low/Drought

GWh

0200400600800100012001400JANFEBMARAPRMAYJUNJULAUGSEPOCTNOVDEC

PC7 Drought -Lost Thermal Generation (GWh)

Lower ColoradoCalifornia

-20,000-15,000-10,000-5,00005,00010,00015,00020,000

GWh

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC7 WGA Drought

Hydro+PSSteam - BoilerCombined CycleCombustion TurbineCogenerationRenewableOther

0100200300400500600700800123456789101112

California Basin Thermal by Month

PC1 CaliforniaPC7 California

GWh

0100200300400500600700800900123456789101112

Lower Colorado Thermal by Month

PC1 Lower ColoradoPC7 Lower Colorado

GWh

02004006008001,0001,2001,4001,6001,800AESOCFEPNMMWh

Comparison of Emergency Energy by Area

PC1PC7

(1000)(500)050010001500200025003000AZNMNV

To Ca_S

Basin To

AZNMNV

Basin To

Ca_N

Basin To

Ca_S

Ca_N To

Ca_S

Canada To

NWUS

NWUS To

Basin

NWUS To

Ca_N

NWUS To

Ca_S

RMPA To

AZNMNV

RMPA To

Basin

Average Megawatts

Transfers between Sub -Regions (aMW)

PC1 CCPC1-2 LHPC7 Drought

-30%-25%-20%-15%-10%-5%0%5%10%15%P45 SDG&E-CFEP08 Montana to NorthwestP03 Northwest-British ColumbiaInterstate WA-BC WestP29 Intermountain-Gonder 230 kVP47 Southern New Mexico (NM1)P26 Northern-Southern CaliforniaP22 Southwest of Four CornersP01 Alberta-British ColumbiaP60 Inyo-Control 115 kV TieInterstate WA-BC EastP66 COIP11 West of CrossoverP79 TOT 2B2P27 Intermountain Power Project DC Line

Change in Utilization -PC1 to PC7

U75U90U99

-4000-3000-2000-100001000200030004000

Megawatts

P03 Northwest-British Columbia Path Duration Plots

20082010PC1_CCPC7_Drought

S->N

-15000-10000-5000050001000015000

Megawatts

P46 West of Colorado River (WOR) Path Duration Plots

20082010PC1_CCPC7_Drought

E->W

-8000-6000-4000-20000200040006000800010000

Megawatts

Interstate COI plus PDCI Path Duration Plots

20082010PC1_CCPC7_Drought

N->S

-4000-3000-2000-1000010002000300040005000

Megawatts

P26 Northern-Southern California Path Duration Plots

2010PC1_CCPC7_Drought

N->S