20210325Avista to Staff 70 Attachment B Workshop 3 Presentation.pdf

Power Supply Modeling Workshop 3
December 13, 2018
Staff_PR_070 Attachment B Page 1 of 31
Agenda
o Introductions 10:00 –10:15
o Review of Last Meeting/Questions 10:15 –10:45
o Results of Modeled Power Cases 10:45 –12:00
o Lunch 12:00 –1:30
o Results of Modeled Power Cases, Cont.1:30 –2:30
o Other Analyses 2:30 –3:15
o Schedule Next Steps/Meeting 3:15 –3:30
o Wrap-Up/Adjourn 3:30 –3:45
1
Staff_PR_070 Attachment B Page 2 of 31
Basic Assumptions Across Modeling
o From 2016 Case Unless Stated Otherwise…
o All costs presented are system total (ID/WA)
o 2017 calendar year
o 80-year hydro record, sourced from BPA
o Fuel prices
o Forced outage and maintenance schedule
o Power and gas transactions
o EPIS Aurora v12.0.1090 and North-American_DB_2015-
02.xdb (version available Aug-2015 at time of filing)
2
Staff_PR_070 Attachment B Page 3 of 31
Evaluated Modeling Cases
Descriptions of Each In Following Slides
o Actuals
o Filed Case
o Median Water
o Out-of-the-Box
o Closed System
o Median water
o 80-Year water
o Backcast
3
Staff_PR_070 Attachment B Page 4 of 31
Modeling Case Definitions
o Actuals (not a modeling case, per se, but a reference)
o Experienced utility operations, including fuel, generation,
purchases and sales, outages, hydro conditions, etc.
o Filed Case
o Median Water
o Run only median hydro of 80-year hydro record
o Out-of-the-Box
o Modify our resources and contracts
o Update with BPA 80-year regional hydro conditions
o Adjust natural gas prices for WECC and Colstrip 3/4 fuel
4
Staff_PR_070 Attachment B Page 5 of 31
Modeling Case Definitions, Cont.
o Closed System
o Input hourly electricity prices and run Avista-only portfolio
o Uses latest version of Aurora
o Two hydro modeled variations
o median water (average of 80-year hourly prices)
o 80-Year BPA water and hourly prices
o Backcast
o Actual 2017 hydro, fuel and power prices, forced outage and
maintenance schedules AND power and gas term transactions
5
Staff_PR_070 Attachment B Page 6 of 31
Analyses Performed
o Proforma Power Supply Costs
o Generation Levels
o Market Purchases and Sales
o Mark-To-Market of Portfolio Assets
o Contract Costs
o 80 Water Year Input Prices and Single Median Water
Year Run
6
Staff_PR_070 Attachment B Page 7 of 31
Power Supply Costs (Exh. WGJ-2)
7
Staff_PR_070 Attachment B Page 8 of 31
Power Supply Costs (Exh. WGJ-2)
8
$000s $000s $000s $000s $000s $000s $000s
555 PURCHASED POWER 130,675 109,783 105,158 105,974 105,370 106,726 100,241
447 SALES FOR RESALE -88,779 -57,504 -65,134 -60,896 -67,086 -65,078 -58,162
557 OTHER EXPENSES 61,870 407 407 407 407 407 407
456 OTHER ELECTRIC REVENUE -67,200 0 0 0 0 0 0
501 THERMAL FUEL EXPENSE 26,289 29,225 29,791 29,444 29,376 28,532 26,199
547 OTHER FUEL EXPENSE 69,528 76,583 86,152 81,247 89,161 86,052 65,017
565 TRANSMISSION OF ELECTRICITY BY OTHERS 17,569 17,766 17,766 17,766 17,766 17,766 17,766
536 WATER FOR POWER 997 1,029 1,029 1,029 1,029 1,029 1,029
453 SALES OF WATER AND WATER POWER -418 -466 -466 -466 -466 -466 -466
WNP-3 CONTRACT MID-POINT VS. ACTUAL 1,820 N/A N/A N/A N/A N/A N/A
74 TOTAL NET EXPENSE 152,351 176,824 174,703 174,504 175,556 174,968 152,032
Delta From Filed Case -13.8% 0.0% -1.2% -1.3% -0.7% -1.0% -14.0%
Line
No.BackcastItemActual
Original
Filed
Median
Water
Out-of-
Box
Closed System
Median
Water
80-Year
Water
Staff_PR_070 Attachment B Page 9 of 31
Market Prices Summary –Malin Gas
9
Staff_PR_070 Attachment B Page 10 of 31
Market Prices Summary –Mid-C Power
10
Staff_PR_070 Attachment B Page 11 of 31
Market Prices Summary –Mid-C Power
11
Staff_PR_070 Attachment B Page 12 of 31
Market Prices Summary
12
Average Delta Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17
Malin Gas Price ($/dth)
Actual 2.736 3.294 2.649 2.590 2.790 2.842 2.630 2.662 2.681 2.680 2.610 2.748 2.640
Original Filed 2.799 2.3%2.937 2.939 2.885 2.599 2.592 2.636 2.725 2.755 2.761 2.769 2.914 3.083
Mid-C Electricity 7x24 Prices ($/MWh)
Actual 20.95 -14.3%29.60 18.72 12.65 10.04 11.63 8.66 25.48 34.93 25.78 23.93 23.10 26.07
Original Filed 24.44 0.0%26.96 24.84 23.54 19.53 17.14 16.48 25.13 29.22 27.44 25.03 27.09 30.74
Median Water 24.54 0.4%26.36 24.68 24.66 20.47 18.85 18.89 24.56 27.78 26.90 24.47 26.44 30.28
Out-of-the-Box 24.51 0.3%27.82 26.75 24.96 20.96 15.52 15.84 25.36 28.69 27.84 26.98 27.66 25.75
Closed System - Median Water 24.54 0.4%26.36 24.69 24.66 20.47 18.85 18.89 24.57 27.77 26.89 24.47 26.44 30.28
Closed System - 80-Yr. Water 24.45 0.0%26.96 24.84 23.54 19.53 17.13 16.48 25.13 29.22 27.45 25.04 27.09 30.74
Closed System - Backcast 20.94 -14.3%29.60 18.72 12.65 10.04 11.63 8.66 25.48 34.93 25.78 23.93 23.10 26.07
Staff_PR_070 Attachment B Page 13 of 31
Generation Levels (GWh)
13
Staff_PR_070 Attachment B Page 14 of 31
Generation Levels (GWh)
Generation (GWh)
Company Hydro 3,978 3,877 3,808 3,877 3,808 3,877 3,978
Mid C Hydro 952 940 935 940 935 962 949
Total Hydro 4,930 4,817 4,743 4,817 4,743 4,839 4,926
Delta From Filed Case 2.4%-1.5% 0.0% -1.5% 0.5% 2.3%
Colstrip 1,423 1,582 1,634 1,567 1,614 1,553 1,439
Kettle Falls 290 291 299 313 276 258 268
Coyote Springs 2 1,659 1,798 2,141 2,012 2,148 1,943 1,592
Lancaster 1,327 1,606 1,909 1,811 1,984 1,757 1,375
Boulder Park 27 31 22 14 16 25 25
Rathdrum 72 59 10 8 40 155 146
Kettle Falls CT 5 10 4 3 14 23 19
Northeast 0 4 - 0 0 25 26
Total Thermal 4,803 5,380 6,018 5,728 6,093 5,738 4,890
Delta From Filed Case -10.7%11.9% 6.5% 13.2% 6.7% -9.1%
Total Generation 9,734 10,197 10,761 10,545 10,835 10,577 9,817
Delta From Filed Case -4.5%5.5% 3.4% 6.3% 3.7% -3.7%
Backcast
Closed System
Out-of-
Box
Median
Water
80-Year
WaterActual
Original
Filed
Median
Water
14
Staff_PR_070 Attachment B Page 15 of 31
Marginal Fuel Costs ($millions)
15
Staff_PR_070 Attachment B Page 16 of 31
Fuel Costs ($millions)
16
Fuel Costs ($millions)
Company Hydro - - - - - - -
Mid C Hydro - - - - - - -
Colstrip 20.2 23.5 23.9 23.4 24.0 23.4 20.9
Kettle Falls 5.9 5.5 5.6 5.8 5.2 4.8 5.1
Coyote Springs 2 30.5 35.1 41.3 38.7 41.6 37.7 30.2
Lancaster 25.1 32.4 38.0 35.9 39.6 35.1 26.8
Boulder Park 0.7 0.8 0.6 0.4 0.4 0.7 0.6
Rathdrum 2.3 2.0 0.3 0.3 1.3 5.2 4.7
Kettle Falls CT 0.2 0.2 0.1 0.1 0.4 0.6 0.5
Northeast 0.0 0.1 - 0.0 0.0 0.9 0.9
Total Thermal 84.8 99.7 109.8 104.6 112.4 108.5 89.6
Delta From Filed Case -14.9%10.2% 4.9% 12.8% 8.8% -10.1%
Actual
Original
Filed
Median
Water
Closed System
Backcast
Out-of-
Box
Median
Water
80-Year
Water
Staff_PR_070 Attachment B Page 17 of 31
Fuel Costs ($/MWh)
17
Staff_PR_070 Attachment B Page 18 of 31
Fuel Costs ($/MWh)
18
Fuel Cost ($/MWh)
Company Hydro - - - - - - -
Mid C Hydro - - - - - - -
Colstrip 14.21 14.86 14.65 14.91 14.85 15.10 14.51
Kettle Falls 20.22 18.80 18.76 18.65 18.75 18.76 18.97
Coyote Springs 2 18.39 19.53 19.29 19.25 19.38 19.41 18.96
Lancaster 18.89 20.18 19.90 19.85 19.94 19.99 19.48
Boulder Park 26.28 26.18 26.24 25.93 26.23 26.19 25.33
Rathdrum 31.64 34.20 33.62 33.74 32.86 33.57 31.91
Kettle Falls CT 33.02 25.29 25.41 24.61 25.49 25.37 24.74
Northeast 30.67 37.09 #DIV/0! 36.25 36.55 37.03 34.88
Total Thermal 17.66 18.53 18.25 18.26 18.45 18.90 18.33
Delta From Filed Case -4.7%-1.5% -1.5% -0.4% 2.0% -1.1%
Actual
Original
Filed
Closed System
Backcast
Median
Water
Out-of-
Box
Median
Water
80-Year
Water
Staff_PR_070 Attachment B Page 19 of 31
Mark-To-Market (Operating Margin)
19
Staff_PR_070 Attachment B Page 20 of 31
Median
Water % Total
80-Year
Water % Total
Back-
cast % Total
Clark Fork River 57.8 50.8%64.6 48.3%65.4 48.3%64.3 46.6%65.5 48.6%64.6 47.6%55.2 48.3%
Spokane River 20.3 17.8%25.2 18.8%26.3 19.4%25.5 18.5%26.2 19.5%25.2 18.5%20.3 17.8%
Mid-Columbia (3.4) -3.0%(1.2) -0.9%(0.6) -0.4%(1.0) -0.7%(0.6) -0.4%(0.7) -0.5%(4.2) -3.7%
Coyote Springs 2 13.3 11.7%13.9 10.4%14.1 10.4%15.9 11.5%13.9 10.3%15.2 11.2%13.1 11.5%
Lancaster 10.3 9.1%10.8 8.1%10.9 8.0%13.0 9.4%10.8 8.0%12.0 8.8%10.2 8.9%
Colstrip 14.2 12.5%17.1 12.8%16.8 12.4%17.5 12.7%16.5 12.3%16.8 12.4%15.9 14.0%
BP, Rath, NE 1.3 1.2%0.8 0.6%0.3 0.2%0.2 0.2%0.2 0.2%0.3 0.2%1.7 1.5%
Kettle Falls (CT/GS) (0.0) 0.0%2.5 1.9%2.3 1.7%2.6 1.9%2.1 1.6%2.4 1.7%2.0 1.7%
Total 113.7 133.7 135.4 138.1 134.7 135.7 114.2
Delta from Filed Case -14.9%0.0%1.3%3.3%0.8%1.6%-14.6%
Closed System
Resource Actual % Total
Original
Filed % Total
Median
Water % Total
Out-of-
Box % Total
Mark-To-Market (Operating Margin, $mil)
20
Staff_PR_070 Attachment B Page 21 of 31
80-Year Averaging For Input Prices
Period On-Peak?1929 1930 1931 1932 …2008 Average
On-Peak Average 21.63 20.63 22.63 33.94 …43.25 28.41 this value compared to forward on-peak price
Off-Peak Average 14.25 13.25 15.25 22.88 …28.50 18.83 this value compared to forward off-peak price
1 0 10 9 11 16.5 …20 13.3
2 0 11 10 12 18 …22 14.6
3 0 12 11 13 19.5 …24 15.9
4 0 13 12 14 21 …26 17.2
5 0 14 13 15 22.5 …28 18.5
6 0 15 14 16 24 …30 19.8
7 1 16 15 17 25.5 …32 21.1
8 1 17 16 18 27 …34 22.4
9 1 18 17 19 28.5 …36 23.7
10 1 19 18 20 30 …38 25
11 1 20 19 21 31.5 …40 26.3
12 1 21 20 22 33 …42 27.6
13 1 22 21 23 34.5 …44 28.9
14 1 23 22 24 36 …46 30.2
15 1 24 23 25 37.5 …48 31.5
16 1 25 24 26 39 …50 32.8
17 1 26 25 27 40.5 …52 34.1
18 1 25 24 26 39 …50 32.8
19 1 24 23 25 37.5 …48 31.5
20 1 23 22 24 36 …46 30.2
21 1 22 21 23 34.5 …44 28.9
22 1 21 20 22 33 …42 27.6
23 0 20 19 21 31.5 …40 26.3
24 0 19 18 20 30 …38 25
AURORA ESTIMATED PRICES
EXAMPLE AVERAGING CALCULATION
This spreadsheet illustrates how Avista ensures that it's 80-year run for ratemaking ties up to the forward electricity prices. First the concept is to
match the forward markets as closely as we can. By this we mean match the 24 periods of the 12-month proforma (12 months, on-peak, and off-
peak price in each month). To do this comparision we take the 80-year average of all hourly prices for each period of forward curve (e.g., January
on-peak prices) and compare it to that forward curve value. So for January you have 80 years of prices to average into the two periods. To the
extent that prices in a run differ significantly from the forwards, we make adjustments to input variables to move prices towardforwards. A simple
example is below showing the math if a month was comprised of only one day and I didn't show all modeled years. The actual math from the 2016
filing is provided in the three orange-colored sheets. The on-and off-peak pricing values used in the comparsion are graphed, but also highlighted
for reference. In actual case filings we have the AURORA software do the averageing and report out monthly on-and off-peak prices for each water
year. We then average these values up to arrive at the 80-year average. This means in our filed cases that we provide a spreadsheet like this one,
but instead of averaging up from hourly data we average up the monthly data. But for illustration purposes this spreadsheet also ("see AURORA 80-
Year Hourly Output") contains the averaging methodology starting from hourly AURORA output prices. The final tab is the Aurora vendor's own
backcast of 2017 adjusting the market after the fact to account for actual fuel prices, loads, outages, etc.
21
Staff_PR_070 Attachment B Page 22 of 31
Gas Transportation Geography/Rights
22
Stanfield
Kingsgate
Malin
AECO
Staff_PR_070 Attachment B Page 23 of 31
Gas Transport Optimization
o Avista has firm contract rights for its gas plants
o 60,590 dth/day for $12.9 million
o 26,388 dth/day AECO to Malin
o 34,204 dth/day AECO to Stanfield
o Post-filing GTN rate case lowered cost to $11 million
o Proformed Case (~$9 million system)
o Executed and open volume positions
o Open positions valued at forward spreads between
AECO and Malin
o Very volatile year to year, so modeled 5-year average of
spreads, adjusted higher in the case because 5-year average
was below forward price delta23
Staff_PR_070 Attachment B Page 24 of 31
PSE Has Less Volatile Resources
Substantially Less Hydro/More Coal
24
(PSE 2.5x Coal)
(Avista 1.5x Hydro)
PSE
wholesale
net power
revenues
(FERC
555/447)
varied from
mean by
almost 50%
more than
Avista from
2003-2017
Staff_PR_070 Attachment B Page 25 of 31
Power Supply Costs (Exh. WGJ-2)
25
Staff_PR_070 Attachment B Page 26 of 31
Summary and Conclusions
o Various methods arrive at similar power cost estimates
o Some methods are easier to run/audit than others
o PSE (out-of-the-box Aurora) and PacifiCorp (input prices) are
much simpler to implement/audit than the Avista method but
arrive at similar results
o At least we can simplify the process
o Near-perfect backcast possible with existing model
o Do we have agreement here, or are more analyses needed?
o Analyses illustrate prices and hydro drive variation
o But, we can’t predict prices/hydro….so what next?
26
Staff_PR_070 Attachment B Page 27 of 31
o Closed system, modified (PAC method)
o Use Aurora model
o Full hydro record (80 years available now, 90 soon)
o Input electricity and natural gas prices shaped to forwards
o Proforma costs equal the average of the individual hydro years
o No dispatch margin for thermal plants
o Model all power contract costs and energy inside Aurora
o Mark-to-Market gas positions against forward prices
o Gas purchased for power plants
o All remaining gas transportation open positions
Avista Recommendation
27
Staff_PR_070 Attachment B Page 28 of 31
Recommendation, Cont.
o Continue using 5-year historical averages for long-term
contracts, hydro shaping, forced outages, maintenance
o except Colstrip where we continue to use average of two
maintenance cycles (currently two 3-year cycles)
o Prior to rates going into effect, should we rerun Aurora?
o latest forward prices for electricity and natural gas
o known contract changes (power and fuel)
o latest pricing information should lessen proforma-to-actuals delta
28
Staff_PR_070 Attachment B Page 29 of 31
Benefits of Recommendation
o Much simpler to understand
o less need to audit non-Avista data
o Much easier to operate
o Runs fast
o Recognizes impact of hydro variability
o Recognizes impact of oversupply
o Aurora values Avista power contracts
o Updates would allow recent information in rate setting
o should reduce delta between proforma and actuals
29
Staff_PR_070 Attachment B Page 30 of 31
Thank You.
Staff_PR_070 Attachment B Page 31 of 31