Total Retail Electric Customers

Transcription

1 Model Inputs New Resource Cost and Production Characteristics Integration and Ancillary Services Costs Historical Weather and Retail Load Forecast Carbon Costs GenTrader PowerSimm Cost and Energy Contribution From Existing Resource Portfolio Implied Market Volatility for Electricity and Natural Gas DSM Program Costs and Associated Energy Savings Price Forecasts for Electricity and Fuel 1

2 NWE 2013 Resource Procurement Plan Model Input Overview Load Forecast 1. Residential & GS1 Secondary (small commercial) customer forecasts a. Montana state and county population forecasts (MT State Census & Economic Information Center (CEIC)) i. Econometric model developed by Regional Economic Models, Inc. (REMI) ii. Drives NWE service territory population forecast b. Historical customer counts ( ) c. Regression model to develop customer forecast 2. Total Degree Days (HDD + CDD) a. Historical total degree days ( ) b. Normal forecasted degree days equals historical average 3. Residential & GS1 Secondary load forecast a. Historical and forecasted customer counts b. Historical and forecasted total degree days c. Historical Residential and GS1 Secondary loads ( ) d. Regression model to develop load forecast 4. Customer forecast results reflect 1.3% growth in Residential, 1.6% growth in GS-1 Secondary, and 1.3% growth in Total customers, compared to 1.1% growth in both Montana and NWE service territory population. (20-year average annual growth rates) 5. Load forecast results reflect 1.2% growth in Energy Supply load for all rate classes excluding DSM and 0.8% growth including DSM. 2

3 , , , , , , ,000 Total Retail Electric Customers Actual Forecast Frcst 2009 Frcst 2010 Frcst 2011 Frcst 2012 Frcst 2013 Frcst Total Customers

4 ,000,000 7,500,000 7,000,000 6,500,000 6,000,000 5,500,000 5,000,000 4,500,000 4,000,000 Total Energy Supply Load At the meter before losses, forecast excludes DSM & USB Actuals Forecast Frcst 2008 Frcst 2009 Frcst 2010 Frcst 2011 Frcst 2012 Frcst 2013 Frcst MWh

5 ,200,000 3,000,000 2,800,000 2,600,000 2,400,000 2,200,000 2,000,000 Residential Load At the meter before losses, forecast excludes DSM & USB Actuals Forecast Frcst 2008 Frcst 2009 Frcst 2010 Frcst 2011 Frcst 2012 Frcst 2013 Frcst MWh

6 , , , , , , , , , ,000 Residential Customers Actuals Forecast Frcst 2008 Frcst 2009 Frcst 2010 Frcst 2011 Frcst 2012 Frcst 2013 Frcst

7 Residential Use per Customer Actuals Forecast Frcst 2008 Frcst 2009 Frcst 2010 Frcst 2011 Frcst 2012 Frcst 2013 Frcst MWh

8 ,900,000 3,700,000 3,500,000 3,300,000 3,100,000 2,900,000 2,700,000 2,500,000 GS1 Secondary Load At the meter before losses, forecast excludes DSM & USB Actuals Forecast Frcst 2008 Frcst 2009 Frcst 2010 Frcst 2011 Frcst 2012 Frcst 2013 Frcst MWh

9 ,000 85,000 80,000 75,000 70,000 65,000 60,000 55,000 50,000 GS1 Secondary Customers Actuals Forecast Frcst 2008 Frcst 2009 Frcst 2010 Frcst 2011 Frcst 2012 Frcst 2013 Frcst

10 GS1 Secondary Use per Customer Actuals Forecast Frcst 2008 Frcst 2009 Frcst 2010 Frcst 2011 Frcst 2012 Frcst 2013 Frcst MWh

11 NWE 2013 Resource Procurement Plan Model Input Overview Peak Demand Forecast 1. Energy Supply is using a new method for developing the peak demand forecast based on a percentage, or ratio, of the Balancing Authority Area (BAA) forecast. 2. Pros of this method include the NWE Transmission group uses linear regression with weather/temperature, loads, and population as the driving variables (so it is not a derivative of Energy Supply s load forecast); 1 in 2 (50% probability of being exceeded) and 1 in 10 (10% probability of being exceeded) forecasts are developed; and the ratio of Energy Supply peak demand to BAA peak demand has been reasonably consistent over the past ten years with winter peak averaging 68.3% with a 1.8% standard deviation and summer peak averaging 66.1% with a 2.3% standard deviation. 3. Cons of this method include the forecast could be skewed by large industrial load swings that are not relevant to Energy Supply. Energy Supply will have to monitor the BAA load forecast to make certain there are no such swings, which is the case in the most recent BAA load forecast. 11

12 Actual (not weather normalized) NorthWestern Energy 2013 Peak Forecast Including DSM Forecast (weather normalized) 1 in 10 Winter Peak 1 in 2 Winter Peak 2011 RPP 12 Peak MW

13 NWE Energy Supply Historical and Forecast Peaks 1 in 2 Peak Forecast - Including DSM 2013 RPP Energy Supply Peak Forecast Year Winter Summer CAGR 0.92% 0.80% Actual Forecast 13

14 NWE 2013 Resource Procurement Plan Model Input Overview Demand Side Management (DSM) Forecast 1. Future DSM acquisition is considered a load-serving resource rather than a direct reduction on the load forecast. Prior year DSM acquisition is built into the load forecast as a result of being embedded in the actual historical load that drives the forecast. 2. The 2013 RPP DSM acquisition forecast is based on the 2009 DSM study and acquisition plan that produced a 15-year goal of 84 amw (91 amw including losses) in accumulated DSM energy savings by The planned DSM contribution to serving peak load, including losses, is an accumulated 130 MW of winter peak savings and 125 MW of summer peak savings by

15 Year DSM Plan Annual Cumulative Achievable Residential - Residential - Non- Year Year non-cfl CFL Residential Total

16 NWE 2013 Resource Procurement Plan Model Input Overview Existing Resources Assumptions 1. Existing resources include all owned, leased, and physical contracted energy supply resources that are at least 3 years in duration. 2. QF Tier II contracts will expire at various times throughout the planning horizon and are assumed to renew under QF1 tariffs. 3. Judith Gap and any QF1 contracts that expire are assumed to renew under estimated prevailing avoided cost rates. 16

17 NorthWestern Energy Existing Energy Supply Resources (as of June 26, 2013) Resource Nameplate 1 Capacity (MW) Summer Peaking Capacity (MW) Winter Peaking Capacity (MW) Annual Energy (amw) Load Following Up (MW) Load Following Down (MW) Spinning Reserves (MW) Non- Spinning Reserves (MW) Expiration Date Colstrip Unit n/a Basin Creek /1/2026 Spion Kop n/a QF Tier II Various QF-1 Tariff Various Gordon Butte /21/2036 Musselshell /24/2036 Musselshell Two /24/2036 Two Dot /31/2037 Fairfield Wind /31/2037 Turnbull /31/1932 DSM ( Total) 3 & 4 n/a n/a DGGS (Energy Supply) n/a Judith Gap /31/2026 Tiber /1/2024 PPL 7 YR (HL) /30/2014 PPL 7 YR (LL) /30/2014 PPL 09 RFP (HL) /30/2017 Citgroup 08 RFP /30/2020 Morgan S 09 RFP (HL) /30/2017 TransAlta 10 RFP (HL) /30/2017 Powerex (LL) /31/2014 Credit Suisse /30/2015 TOTAL: 1, n/a 1. Nameplate capacity reflects NWE share only 4. Estimated on non-coincident peak basis 2. Under QF contract but not yet under construction 5. QF-1 excludes wind contracts after Pre-existing DSM embedded in load forcast / values include losses 17

18 NWE 2013 Resource Procurement Plan Model Input Overview Proposed New Resources to Assess 1. The number of proposed new resources that will be modeled in the 2013 RPP is trimmed down considerably from previous plans due to a focus on resources that are commercially viable and realistically plausible. Alternative resources that are excluded from modeling will still receive consideration in the body of the plan. 2. The group of resources that will be assessed via portfolio modeling include: various combined cycle and simple cycle techonologies, combined heat & power, solar pv, and wind. 3. Not including the total universe of generating resources in the modeling effort is consistent with practices exhibited by other utilities in the development of their IRPs, including Puget Sound Energy. 18

19 NorthWestern Energy 2013 Energy Supply and Procurement Plan - Resource Options Leading Edge Technologies In 2011 Preferred Portfolios Baseload Combined Cycle Yes Yes Combined Cycle w/ CCS Yes Gas Combined Heat & Power Yes Supercritical Coal Yes IGCC no CCS Yes IGCC with CCS Yes Intermediate/Peaking Aeroderivative Gas Turbine Yes Yes Frame Gas Turbine Yes Reciprocating Engine Yes Renewable & Other Distributed Generation (Rooftop Solar) Waste Water Treatment Biomass Wood products Solar PV Yes Yes Geothermal Landfill Gas Yes Small Hydro Yes Wind Yes Yes Storage Devices Battery Storage Pump Storage Yes Proposed for Inclusion in 2013 Portfolios 19

20 NWE 2013 Resource Procurement Plan Model Input Overview Natural Gas Price Forecast 1. The natural gas price forecast is based on AECO forward market curve as of June 7, An escalation rate of 2.07% based on the 20-year average Implicit Price Deflator (measure of average annual growth in GDP) was used to escalate prices beyond the forward curve. 3. Transportation charges of $0.17 (AECO to MT) and $ (delivery within MT) are added to the AECO forward market curve to create the delivered cost of fuel. 20

21 $ Resource Procurement Plan Natural Gas Price Forecast Comparisons (all forecasts include transportation costs through MT) $10.00 $8.00 $/MWh $6.00 $4.00 $ RPP Base Case : Levelized $ RPP Base Case : Levelized $4.96 $ EIA AEO : Levelized $ EIA Escalated Base Case : Levelized $

22 NWE 2013 Resource Procurement Plan Model Input Overview Electric Price Forecast 1. The electric price forecast is based on the Mid-C forward market curve as of June 7, The electric price forecast cases include the EIA carbon penalty cases in 2021 as they would apply to the marginal unit (assumed to be a natural gas-fired resource). 3. An escalation rate of 2.07% based on the 20-year average Implicit Price Deflator (measure of average annual growth in GDP) was used to escalate prices beyond the forward curve. 22

23 $ Resource Procurement Plan Electricity Price Forecast Cases ATC On-System Power $90.00 EIA GHG15 beginning Base Case $80.00 $70.00 EIA GHG25 beginning 2021 $/MWh $60.00 $50.00 $ RPP Base Case Electric Forecast - Carbon 2015 EIA GHG10 beginning 2021 No Carbon Case $30.00 $20.00 $10.00 $ No Carbon Case (frwd curve thru 2017 only) 23

24 NWE 2013 Resource Procurement Plan Model Input Overview Carbon Penalty Forecast 1. The carbon penalty forecast was adopted from the Energy Information Administration s (EIA) 2013 Annual Energy Outlook (AEO). 2. EIA developed three carbon, or green house gas (GHG), cases in addition to its No GHG Concern case which was simply a no carbon penalty case: a. GHG10 case carbon penalty beginning in 2014 at $10/metric ton and escalating at 5% b. GHG15 case carbon penalty beginning in 2014 at $15/metric ton and escalating at 5% c. GHG25 case carbon penalty beginning in 2014 at $25/metric ton and escalating at 5% 3. NWE intends to use these cases as well as any others that will help capture a variety of carbon futures and provide insight into how resources and portfolios will perform under the uncertain future of carbon legislation. 24

25 $ $90.00 $80.00 $70.00 $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 EIA 2013 Annual Energy Outlook (AEO) Carbon Cases 5% escalation on each case 25 EIA GHG25 EIA GHG15 EIA GHG10 No GHG Concern $/metric ton

26 NWE 2013 Resource Procurement Plan Model Input Overview Renewable Energy Credits (REC) Forecast 1. The Renewable Energy Credit (REC) forecast is based on broker quotes for RECs on July 24, 2013, provided by Karbone, Inc., a global firm focused on renewable energy and environmental markets operating from offices in New York, London and Istanbul. 2. The quotes cover three years, , and average $1.07 with the high occurring in 2015 at $ For the period , REC values increase by $0.25, which is the increase from 2014 to 2015 in the broker quotes. The 20-year levelized value of RECs is $ The 2011 RPP reflected a 20-year levelized REC value of $11.36 based on short-term broker quotes ($7.50) and actual long-term contract deals for RECs ($15.00) executed in the state of Washington. 26

27 Karbone Broker Quotes-Based Method 2013 RPP REC Forecast highlighted = average bid/ask broker quotes increased by $0.25 annually (same as 2014 to 2015 increase) REC Annual Forecast Growth 2013 $ $ % 2015 $ % 2016 $ % 2017 $ % 2018 $ % 2019 $ % 2020 $ % 2021 $ % 2022 $ % 2023 $ % 2024 $ % 2025 $ % 2026 $ % 2027 $ % 2028 $ % 2029 $ % 2030 $ % 2031 $ % 2032 $ % 2033 $ % 20-Yr Lev $

28 NWE 2013 Resource Procurement Plan Model Input Overview Wind Integration & Ancillary Services Costs 1. Wind integration costs are based on the wind integration tariff finalized in the 2011 RPP Avoided Cost docket, updated with the electricity and natural gas price forecasts developed with June 7, 2013 forward curve information. 2. The resulting integration adders applied to wind projects are as follows: a. Zone 1, < 25 miles from Judith Gap: $7.12/MWh b. Zone 2, miles from Judith Gap: $2.62/MWh c. Zone 3, > 60 miles from Judith Gap: $0.96/MWh 3. Purchasing operating reserves is necessary for each generating resource, with thermal resources requiring 7% reserves, and wind and hydro resources requiring 5% reserves. 4. Based on the current operating reserve contract that NWE has with a third party, the operating reserve costs applied to each resource is as follows: a. Thermal resources: $0.77/MWh b. Wind & Hydro resources: $0.55/MWh 28

29 Cost of Regulation and WI-1 Tariff Rates, 25-Year Levelized Rate for New Wind (Revised) (Updated with June 7, 2013 Electric and Natural Gas Price Forecasts) 105 MW Regulation for Load and Wind 60 MW Regulation for Load Change for 45 MW Additional Regulation as per PSC-002(a) with 25-yr levelized prices as per UMX-013(a) with 25-yr levelized prices Fuel Expenses Units Price Total Units Ave. Price Total Total Natural Gas Fuel Costs (Dekatherms) /1 3,296,876 $6.45 $ 21,271,236 2,675,524 $6.45 $ 17,262,313 $ 4,008,923 Diesel Fuel Costs (Gallons) /2 1,293,569 $3.79 $ 4,902,628 1,049,774 $3.79 $ 3,978,643 $ 923,984 Compressor Electricity Bill /3 $ 559,177 $ 559,177 $ - Total Fuel Expense $ 26,733,040 $ 21,800,133 $ 4,932,907 Revenue Credits Per NWE Default Supply Total Per NWE Default Supply Total Total Mid-C Forward Market Price ($/MWh) /4 $34.90 $ $ $ $ $ Discount to Mid-C ($/MWh) ($7.00) ($7.00) ($7.00) ($7.00) ($7.00) ($7.00) Project Energy (amw) Hours/Year 8,760 8,760 8,760 8,760 8,760 8,760 Total Revenue Credits $ 6,599,891 $ 1,711,083 $ 8,310,974 $ 4,399,927 $ 1,711,083 $ 6,111,010 $ 2,199,964 Cost of Regulation $ 18,422,066 $ 15,689,123 $ 2,732,943 Cost of Regulation for New Wind DGGS Annual Net Variable Cost $ 2,732,943 Regulation Required (MW) 45 Unit Cost ($/kw-month) $ 5.06 WI-1 Tariff Rates DGGS Regulation as % of Nameplate Capacity Rate ($/kw-month of Namplate Capacity) Rate for 37% c.f. wind project ($/kwh) Total annual cost for 10 MW project at 37% c.f. $ $ $ Zone % $ 1.92 $ ,782 Zone % $ 0.71 $ ,025 Zone 3 5.1% $ 0.26 $ ,973 29