CONSERVATION IMPROVEMENT PROGRAM APPROVAL LETTERS

Transcription

1 APPENDIX E CONSERVATION IMPROVEMENT PROGRAM APPROVAL LETTERS INTEGRATED RESOURCE PLAN Submitted to the Minnesota Public Utilities Commission Docket No. ET2/RP April 28, 2017

2 April 7, 2015 Jeffrey Haase Energy Efficiency Coordinator Elm Creek Blvd. Maple Grove, MN RE: All-Requirements Members 2013 CIP Results and 2015 Plan Dear Mr. Haase: Thank you very much for s (GRE) efforts to report 2013 Conservation Improvement Program (CIP) results and a 2015 CIP plan in ReportingESP on behalf of GRE s all-requirements members. My staff has finished reviewing this information CIP RESULTS Each utility and association has an annual energy savings goal equal to 1.5 percent of gross annual retail sales. 1 Based on the information provided, GRE s all-requirements members saved a total of 99,134,162 total savings kwh at the generator in 2013, equivalent to 1.17 percent of average retail sales, excluding sales to any CIP-exempt customers. 2 We appreciate GRE s energy efficiency and conservation achievements in 2013 and those of its members. A summary of energy savings by member is as follows: Table 1: 2013 Energy Savings Results Member Organization Energy Savings (kwh) % of Retail Sales Arrowhead 359, % BENCO 5,855, % Brown 974, % Connexus 20,297, % Cooperative 332, % Dakota 26,430, % East Central 8,004, % Elk River 2,378, % Goodhue 929, % 1 See Minn. Stat. 216B.241 subd. 1c (b). 2 Minnesota Statutes 216B.241 subd. 1c(b) states that the energy savings goal is to be calculated based on the most recent three-year weather-normalized average. This review was based on retail sales as reported in ESP.

3 All-Requirements Coops Page 2 Itasca Mantrap 2,898, % Kandiyohi 1,599, % Lake Country 9,340, % Lake Region 4,474, % McLeod 1,233, % Mille Lacs 1,319, % Nobles 1,443, % North Itasca 1,310, % Runestone 1,638, % Stearns 5,967, % Steele Waseca 1,360, % Todd Wadena 988, % TOTAL 99,134, % Each cooperative electric association and municipality utility is required to invest a minimum of 1.5 percent of its Minnesota gross operating revenues (GOR), excluding revenue from any CIP-exempt customers, on CIP. 3 For 2013, 2011 revenues were the baseline for establishing these minimum spending requirements. Based on the information provided, Co-ops - Allrequirements s members invested a total of $15,575,524 in 2013, approximately 1.73 percent of 2011 Minnesota GOR, excluding revenue from any CIP-exempt customers. Additionally, Minnesota Statutes require each electric utility and natural gas municipal utility to invest a minimum of 0.2 percent of its residential Minnesota GOR on CIP programs that directly serve the needs of low-income persons, including renters. 4 For 2013, 2011 revenues were the baseline for establishing the low-income spending requirements. Each member utility is responsible for meeting the low-income spending requirement. While Department policy currently allows cooperatives and municipalities to count a portion of general residential spending as low-income, the Department strongly encourages all utilities to meet their low-income spending requirements through programs that directly serve the needs of low-income persons, including renters. Also, while utilities may claim energy savings that result from EUI projects on top of a minimum savings goal of one percent from conservation improvements, provided the EUI projects results in energy efficiencies greater than what would occur through normal maintenance activity, 5 Minnesota Statutes do not allow spending on EUI projects to count towards the CIP spending requirement. 6 Therefore, total 2013 CIP spending does not 3 See Minn. Stat. 216B.241 subd. 1b. 4 See Minn. Stat. 216B.241 subd. 7(a) and (c). 5 Minn. Stat. 216B.241 subd. 1c (d) allows a utility or associated to include in its energy conservation plan energy savings from electric utility infrastructure projects. 6 Minn. Stat. 216B.241 subd. 1b (b) requires each electric cooperative association and electric municipal utility to spend 1.5% of gross operating revenues annually on energy conservation improvements. Minn. Stat.

4 All-Requirements Coops Page 3 reflect any EUI spending. The Department is supportive of EUI projects that increase generation and distribution efficiencies and appreciates that utilities are reporting information about these investments through ReportingESP. A summary of CIP investments by member is as follows: Table 2: 2013 Actual Expenditures Member Total CIP Low-Income Organization Total CIP (% of GOR) Low-Income (% of Res GOR) Arrowhead $112, % $12, % BENCO $514, % $49, % Brown $124, % $9, % Connexus $2,476, % $371, % Cooperative $137, % $17, % Dakota $3,852, % $391, % East Central $1,652, % $90, % Elk River $417, % $28, % Goodhue $221, % $15, % Itasca Mantrap $449, % $22, % Kandiyohi $270, % $7, % Lake Country $1,322, % $148, % Lake Region $788, % $71, % McLeod $372, % $22, % Mille Lacs $379, % $40, % Nobles $134, % $18, % North Itasca $107, % $8, % Runestone $543, % $45, % Stearns $947, % $59, % Steele Waseca $358, % $13, % Todd Wadena $394, % $26, % TOTAL $15,575, % $1,471, % In addition to meeting the energy savings goal and the total and low-income spending requirements, Minnesota Statutes 216B.241 and 216B.2411 contain provisions that utilities must meet, including the following: Research and Development (R&D): Each utility and association may spend up to 10 percent of a utility s minimum spending requirement on R&D ( 216B.241, subd. 2(c)). 216B.241 subd. 1(e) specifically excludes electric utility infrastructure projects from the definition of energy conservation improvements.

5 All-Requirements Coops Page 4 Distributed and Renewable Generation (DRG): Each utility and association may spend up to 5 percent of a utility s minimum spending requirement on DRG ( 216B.2411, subd. 1). Utilities may not use green pricing programs to achieve CIP requirements. Green Building Standards: Each utility and association must offer one or more programs that support green building certification of commercial buildings and that support goals consistent with Sustainable Buildings 2030 (SB 2030) standards ( 216B.241, subd. 1f(c) and 216B.241, subd. 9(e)). We recommend that at a minimum, utilities offer subsidies for design assistance and/or certification expenses on a case by case basis within their commercial and industrial program(s). Load-Management Activities: Each utility and association may use load-management activities to achieve up to 50 percent of a utility s minimum spending requirement ( 216B.241, subd. 1b(e)). Electric Utility Infrastructure (EUI): As stated above, energy savings from EUI projects count towards CIP energy savings goals. However, according to the Minnesota Statutes, spending on EUI projects may not be counted towards CIP spending requirements. For 2013, GRE s all-requirements members: Collectively did not achieve the statutory energy savings goal of 1.5 percent of gross annual retail energy sales excluding sales to any CIP-exempt customers, equivalent to 127,479,516 kwh in Collectively met the statutory minimum spending requirement of 1.5 percent of gross operating revenue, excluding revenue from any CIP-exempt customers, equivalent to $13,525,223 in Collectively invested $0 on DRG. This amount complies with the statutory spending cap, equal to $676,261 in Collectively invested $11,321,734 on conservation programs, equivalent to percent of the total CIP minimum spending amount of $13,525,223. This amount complies with the minimum spending amount on conservation programs (programs designed to save energy rather than reduce peak demand and/or shift energy use to off-peak hours), 50 percent of a utility's total minimum spending amount. The following member organizations invested at least 0.2 percent of their Minnesota residential GOR on low-income customers through CIP: Arrowhead BENCO Connexus Cooperative Dakota

6 All-Requirements Coops Page 5 Elk River Lake Country Lake Region Mille Lacs Nobles Runestone Stearns Todd Wadena The following member organizations did not invest at least 0.2 percent of Minnesota residential GOR on low-income persons through CIP: Brown East Central Goodhue Itasca Mantrap Kandiyohi McLeod North Itasca Steele Waseca 2015 PLAN REVIEW For 2015, the savings goal and minimum spending requirements are calculated as follows: Savings Goal = 1.5 percent of annual average retail energy sales, excluding sales to any CIP-exempt customers Minimum Total Spending = 1.5 percent of 2013 GOR, excluding revenue from any CIP-exempt customers Minimum Low Income Spending = 0.2 percent of 2013 residential GOR Because GRE had not obtained internal approval of its 2015 budgets and goals by member by the September 5, 2014 deadline, GRE was granted approval to initially enter its 2015 plan at the aggregator-level, with the understanding that budgets and goals would be entered for each member following plan approval. GRE s total energy savings goal, budget, and low-income budget for its all-requirements members are indicated below. Table 3: Total Energy Savings Goal for All-Requirements Members Energy Savings (kwh) % of Retail Sales 131,070, %

7 All-Requirements Coops Page 6 Table 4: 2015 Total CIP and Low-Income Budget for All-Requirements Members Total CIP Portfolio Total CIP Portfolio (%) Low-Income Low-Income (%) $15,768, % $1,929, % The CIP plan for 2015 presented by Co-ops - All-requirements: Collectively meets the statutory energy savings goal of 1.5 percent of gross annual retail energy sales excluding sales to any CIP-exempt customers, equivalent to 130,711,596 kwh in Collectively meets the statutory minimum spending requirement of 1.5 percent of gross operating revenue, excluding revenue from any CIP-exempt customers, equivalent to $14,826,909 in (As discussed in the 2013 Results section, EUI expenditures do not count as CIP expenditures.) Collectively invests $0 on DRG. This amount complies with the statutory spending cap, equal to $741,345 in Collectively invests $11,254,981 on conservation programs, equivalent to percent of the total CIP minimum spending amount of $14,826,909. This amount complies with the minimum spending amount on conservation programs (programs designed to save energy rather than reduce peak demand and/or shift energy use to off-peak hours), 50 percent of a utility's total minimum spending amount. Collectively invests at least 0.2 percent of Minnesota residential GOR on low-income customers. FUTURE REPORTING Annual one-year plans and one-year status reports are due on June 1 of each year. The next scheduled report will be on June 1, 2015, when GRE will be required to submit expenditures and savings for 2014, budgets and goals for 2016, and updated program designs in ReportingESP for Program designs will persist from one year to the next so that it will not be necessary to reenter those programs that have not changed. The baseline periods for each program year are shown below in Table 5. Please note that there is a change to the low-income spending requirements beginning in Legislation passed in changed the calculation of the minimum low-income spending requirements to use a three-year average of residential GOR. Similar to how the 1.5 percent savings goal is calculated, low-income spending requirements will be calculated using average residential GOR over the most recent three-year period prior to the year in which the plan is filed. Therefore, for the 2016 plans filed in 2015, the low-income spending requirements for associations and municipalities will be calculated as 0.2 percent 7 Minn. Laws 2013 Ch. 132 Sec. 2

8 All-Requirements Coops Page 7 of average residential GOR. 8 ReportingESP will be updated to use the new lowincome formula beginning with 2016 program totals. Program Year Table 5: Baseline Periods for Cooperatives and Municipalities Savings Goal 1.5% of: Total Spending Rqmt 1.5% of: Low-Income Spending Rqmt 0.2% of: average sales 2013 GOR 2013 residential GOR average sales 2014 GOR average residential GOR average sales 2015 GOR average residential GOR average sales 2016 GOR average residential GOR DECISION With this letter, I accept GRE-All Requirements results for the 2013 program year and approve GRE-All Requirements CIP plan for Please note that approval for GRE s electric utility infrastructure projects is provisional pending the outcomes of the upcoming policy development process planned by the Department. Also, please complete entry of the 2015 plan at the member-program level by May 1, Thank you for your organization and members continued contributions to Minnesota s energy efficiency and conservation goals. Please contact Jessica Burdette at Jessica.Burdette@state.mn.us or or Laura Silver at laura.silver@state.mn.us or with any questions or concerns. Sincerely, WG/LNS WILLIAM GRANT Deputy Commissioner 8 Since associations and municipalities have already developed and filed 2014 and 2015 plans under the old lowincome formula, the Department will apply the new low-income formula beginning in 2016.

9 April 7, 2015 Jeffrey Haase Energy Efficiency Coordinator Elm Creek Blvd. Maple Grove, MN RE: Fixed Members 2013 CIP Results and 2015 Plan Dear Mr. Haase: Thank you very much for s (GRE) efforts to report 2013 Conservation Improvement Program (CIP) results and a 2015 CIP plan in ReportingESP on behalf of GRE s fixed members. My staff has finished reviewing this information CIP RESULTS Each utility and association has an annual energy savings goal equal to 1.5 percent of gross annual retail sales. 1 Based on the information provided, GRE s fixed members saved a total of 27,418,152 kwh at the generator in 2013, equivalent to 0.96 percent of average retail sales, excluding sales to any CIP-exempt customers. 2 We appreciate GRE s energy efficiency and conservation achievements in 2013 and those of its members. A summary of energy savings by member is as follows: Table 1: 2013 Energy Savings Results Member Organization Energy Savings (kwh) % of Retail Sales Agralite 1,054, % Crow Wing 2,578, % Federated 1,201, % Meeker 1,018, % Minnesota Valley 10,942, % Redwood 299, % South Central 1,396, % Wright-Hennepin 8,927, % TOTAL 27,418, % 1 See Minn. Stat. 216B.241 subd. 1c (b). 2 Minnesota Statutes 216B.241 subd. 1c(b) states that the energy savings goal is to be calculated based on the most recent three-year weather-normalized average. This review was based on retail sales as reported in ESP.

10 Fixed Coops Page 2 Each cooperative electric association and municipality utility is required to invest a minimum of 1.5 percent of its Minnesota gross operating revenues (GOR), excluding revenue from any CIP-exempt customers, on CIP. 3 For 2013, 2011 revenues were the baseline for establishing these minimum spending requirements. Based on the information provided, GRE s fixed members invested a total of $4,277,865 in 2013, approximately 1.56 percent of 2011 Minnesota GOR, excluding revenue from any CIP-exempt customers. Additionally, Minnesota Statutes require each electric utility and natural gas municipal utility to invest a minimum of 0.2 percent of its residential Minnesota GOR on CIP programs that directly serve the needs of low-income persons, including renters. 4 For 2013, 2011 revenues were the baseline for establishing the low-income spending requirements. Each member utility is responsible for meeting the low-income spending requirement. While Department policy currently allows cooperatives and municipalities to count a portion of general residential spending as low-income, the Department strongly encourages all utilities to meet their low-income spending requirements through programs that directly serve the needs of low-income persons, including renters. Also, while utilities may claim energy savings that result from EUI projects on top of a minimum savings goal of one percent from conservation improvements, provided the EUI projects results in energy efficiencies greater than what would occur through normal maintenance activity, 5 Minnesota Statutes do not allow spending on EUI projects to count towards the CIP spending requirement. 6 Therefore, total 2013 CIP spending does not reflect any EUI spending. The Department is supportive of EUI projects that increase generation and distribution efficiencies and appreciates that utilities are reporting information about these investments through ReportingESP. A summary of CIP investments by member is as follows: Table 2: 2013 Actual Expenditures Member Total CIP Low-Income Organization Total CIP (% of GOR) Low-Income (% of Res GOR) Agralite $539, % $18, % Crow Wing $474, % $29, % Federated $283, % $14, % 3 See Minn. Stat. 216B.241 subd. 1b. 4 See Minn. Stat. 216B.241 subd. 7(a) and (c). 5 Minn. Stat. 216B.241 subd. 1c (d) allows a utility or associated to include in its energy conservation plan energy savings from electric utility infrastructure projects. 6 Minn. Stat. 216B.241 subd. 1b (b) requires each electric cooperative association and electric municipal utility to spend 1.5% of gross operating revenues annually on energy conservation improvements. Minn. Stat. 216B.241 subd. 1(e) specifically excludes electric utility infrastructure projects from the definition of energy conservation improvements.

11 Fixed Coops Page 3 Meeker $312, % $13, % Minnesota Valley $1,232, % $63, % Redwood $245, % $9, % South Central $134, % $6, % Wright-Hennepin $1,054, % $126, % TOTAL $4,277, % $282, % In addition to meeting the energy savings goal and the total and low-income spending requirements, Minnesota Statutes 216B.241 and 216B.2411 contain provisions that utilities must meet, including the following: Research and Development (R&D): Each utility and association may spend up to 10 percent of a utility s minimum spending requirement on R&D ( 216B.241, subd. 2(c)). Distributed and Renewable Generation (DRG): Each utility and association may spend up to 5 percent of a utility s minimum spending requirement on DRG ( 216B.2411, subd. 1). Utilities may not use green pricing programs to achieve CIP requirements. Green Building Standards: Each utility and association must offer one or more programs that support green building certification of commercial buildings and that support goals consistent with Sustainable Buildings 2030 (SB 2030) standards ( 216B.241, subd. 1f(c) and 216B.241, subd. 9(e)). We recommend that at a minimum, utilities offer subsidies for design assistance and/or certification expenses on a case by case basis within their commercial and industrial program(s). Load-Management Activities: Each utility and association may use load-management activities to achieve up to 50 percent of a utility s minimum spending requirement ( 216B.241, subd. 1b(e)). Electric Utility Infrastructure (EUI): As stated above, energy savings from EUI projects count towards CIP energy savings goals. However, according to the Minnesota Statutes, spending on EUI projects may not be counted towards CIP spending requirements. For 2013, GRE s fixed members: Collectively did not achieve the statutory energy savings goal of 1.5 percent of gross annual retail energy sales excluding sales to any CIP-exempt customers, equivalent to 42,630,414 kwh in Collectively met the statutory minimum spending requirement of 1.5 percent of gross operating revenue, excluding revenue from any CIP-exempt customers, equivalent to $4,117,920 in 2013.

12 Fixed Coops Page 4 Collectively invested $0 on DRG. This amount complies with the statutory spending cap, equal to $205,896 in Collectively invested $2,698,900 on conservation programs, equivalent to percent of the total CIP minimum spending amount of $4,117,920. This amount complies with the minimum spending amount on conservation programs (programs designed to save energy rather than reduce peak demand and/or shift energy use to off-peak hours), 50 percent of a utility's total minimum spending amount. The following member organizations invested at least 0.2 percent of their Minnesota residential GOR on low-income customers through CIP: Agralite Federated Wright-Hennepin The following member organizations did not invest at least 0.2 percent of Minnesota residential GOR on low-income persons through CIP: Crow Wing Meeker Minnesota Valley Redwood South Central 2015 PLAN REVIEW For 2015, the savings goal and minimum spending requirements are calculated as follows: Savings Goal = 1.5 percent of annual average retail energy sales, excluding sales to any CIP-exempt customers Minimum Total Spending = 1.5 percent of 2013 GOR, excluding revenue from any CIP-exempt customers Minimum Low Income Spending = 0.2 percent of 2013 residential GOR Because GRE had not obtained internal approval of its 2015 budgets and goals by member by the September 5, 2014 deadline, GRE was granted approval to initially enter its 2015 plan at the aggregator-level, with the understanding that budgets and goals would be entered for each member following plan approval. GRE s total energy savings goal, budget, and low-income budget for its all-requirements members are indicated below. Table 3: Total Energy Savings Goal for Fixed Members Energy Savings (kwh) % of Retail Sales 47,624, %

13 Fixed Coops Page 5 Table 4: 2015 Budgets Total CIP Total CIP Low-Income Low-Income (%) Portfolio Portfolio (%) $4,769, % $544, % The fixed member CIP plan for 2015 presented by GRE: Collectively meets the statutory energy savings goal of 1.5 percent of gross annual retail energy sales excluding sales to any CIP-exempt customers, equivalent to 47,392,913 kwh in Collectively meets the statutory minimum spending requirement of 1.5 percent of gross operating revenue, excluding revenue from any CIP-exempt customers, equivalent to $4,753,929 in (As discussed in the 2013 Results section, EUI expenditures do not count as CIP expenditures.) Collectively invests $0 on DRG. This amount complies with the statutory spending cap, equal to $237,696 in Collectively invests $3,595,237 on conservation programs, equivalent to percent of the total CIP minimum spending amount of $4,753,929. This amount complies with the minimum spending amount on conservation programs (programs designed to save energy rather than reduce peak demand and/or shift energy use to off-peak hours), 50 percent of a utility's total minimum spending amount. Collectively invests at least 0.2 percent of Minnesota residential GOR on low-income customers. FUTURE REPORTING Annual one-year plans and one-year status reports are due on June 1 of each year. The next scheduled report will be on June 1, 2015, when Co-ops - Fixed will be required to submit expenditures and savings for 2014, budgets and goals for 2016, and updated program designs in ReportingESP for Program designs will persist from one year to the next so that it will not be necessary to reenter those programs that have not changed. The baseline periods for each program year are shown below in Table 5. Please note that there is a change to the low-income spending requirements beginning in Legislation passed in changed the calculation of the minimum low-income spending requirements to use a three-year average of residential GOR. Similar to how the 1.5 percent savings goal is calculated, low-income spending requirements will be calculated using average residential GOR over the most recent three-year period prior to the year in which the plan is filed. Therefore, for the 2016 plans filed in 2015, the low-income spending requirements for associations and municipalities will be calculated as 0.2 percent 7 Minn. Laws 2013 Ch. 132 Sec. 2

14 Fixed Coops Page 6 of average residential GOR. 8 ReportingESP will be updated to use the new lowincome formula beginning with 2016 program totals. Program Year Table 5: Baseline Periods for Cooperatives and Municipalities Savings Goal 1.5% of: Total Spending Rqmt 1.5% of: Low-Income Spending Rqmt 0.2% of: average sales 2013 GOR 2013 residential GOR average sales 2014 GOR average residential GOR average sales 2015 GOR average residential GOR average sales 2016 GOR average residential GOR DECISION With this letter, I accept GRE-Fixed s results for the 2013 CIP program year and approve GRE-Fixed s CIP plan for Please note that approval for GRE s electric utility infrastructure projects is provisional pending the outcomes of the upcoming policy development process planned by the Department. Also, please complete entry of the 2015 plan at the member-program level by May 1, Thank you for your organization and members continued contributions to Minnesota s energy efficiency and conservation goals. Please contact Jessica Burdette at Jessica.Burdette@state.mn.us or or Laura Silver at laura.silver@state.mn.us or with any questions or concerns. Sincerely, WG/LNS WILLIAM GRANT Deputy Commissioner 8 Since associations and municipalities have already developed and filed 2014 and 2015 plans under the old lowincome formula, the Department will apply the new low-income formula beginning in 2016.

15 APPENDIX F LADCO SCENARIO ANALYSIS INTEGRATED RESOURCE PLAN Submitted to the Minnesota Public Utilities Commission Docket No. ET2/RP April 28, 2017

16 Conservation Plan Scenario Analysis - Benefit/Cost Results and Rate Impact Prepared for Prepared by LADCO Services, LLC 7820 Galway Cove Eden Prairie, MN (952) March 24, 2017

17 Table of Contents Section 1 -Introduction 1 Section 2 - Method of Analysis 2 Section 3 - 's 2015 Conservation Plan 3 Section 4- Scenario Definition and Associated Input Parameters 4 Section 5 - Scenario Results 6 Appendix 1 - Program Incremental Costs and Incentives by Scenario Appendix 2 -Annual Plan Savings and Costs Appendix 3- Total Meter Savings by Program and Scenario Appendix 4 - Individual Program Costs by Scenario Appendix 5 - Benefit/Cost Results by Program LADCO Services, LLC March 24, 2017

18 Section 1 Introduction 's (GRE) conservation Improvement Plan (CIP) contains both conservation and load management projects. Over the past several years, conservation projects saved energy at a rate of approximately 1% of its annual sales. An additional 0.5% level of savings was realized through supply side efficiency projects. This level of achievement is challenging for rural electric cooperatives, owing to the greater proportion of residential customers, compared to that of investor owned utilities (IOU). Among utilities, the largest conservation savings are attributed to the commercial and industrial classes. Since GRE has a lower proportion of commercial and industrial customers than the IOUs, its savings percentage would be expected to be lower, given the same effort of implementation. While it would be possible to increase the magnitude of the conservation program, this increased size would be accompanied by increased costs. These costs could be in the form of greater incentives to customers and greater program administrative costs. The measures implemented in more aggressive plans could be the same measures currently implemented, other identified measures or future measures not currently identified. One measure of cost-effectiveness for more aggressive plans would be the standard DSM cost-effectiveness tests, i.e. Participant, Utility, Ratepayer Impact and Societal tests. Resource plans are generally evaluated using the Utility test, which is also known as the Revenue Requirements test. While aggressive conservation may lower revenue requirements and look attractive from that perspective, it does not address the rate impacts caused by the additional conservation. In theory, the Ratepayer Impact test does address the rate impact. Unfortunately it does so in a manner that is not intuitively obvious. A calculation of projected rate impact is required. This study addresses the cost-effectiveness of various levels of conservation both in terms the cost-effectiveness tests and projected rate impact. LADCO Services, LLC March 24, 2017

19 Section 2 Method of Analysis The conservation portion of GRE's projected 2017 CIP is used as the basis for this study. The conservation portion of the 2017 plan is 1.0% of weather normalized sales. This plan was constructed based on the average levels of achievements across distribution cooperatives for past years combined with known kwh reductions from those measures that are known to have increased baselines and reduced kwh savings. It does not include load management programs that also provide some kwh savings. Three additional plans are constructed by increasing participation. The three plans correspond to 1.25% of sales, 1.5% of sales and 2.0% of sales. Costs are escalated in a manner consistent with the Utility Net Benefit correction factors originally agreed to with the DER and other utilities in Docket No. E, G999/CI Since a 1. 0% of sales plan for GRE is consistent with a 1.5% of sales plan for the IOUs, the factors used to increase an IOU plan from 1.5% to 3% are the same factors used to escalate the GRE plan from approximately 1% to 2%. Although the existing measures are used in the analysis, they are proxies for whatever measures would be implemented to obtain the greater level of savings. Any new measures used to escalate a plan would be expected to require greater incentives than those currently offered, have lower unit savings or both. The focus of this study is the level of savings and costs and not the actual measures. Each plan is assumed to be implemented from 2018 through 2032, the end of the IRP study period. Since the IRP is filed in 2017, it is reasonable to assume that any scenario variations would not occur until To simplify the analysis, measures are examined at the program level. For example, Residential lighting encompasses all lighting components, such as LED, CFL and holiday lighting. The program loadshapes are proportioned by the projected 2018 components to obtain a reasonable loadshape. Program lives are determined in the same manner. Each plan is evaluated for cost-effectiveness over the period from 2018 through 2051 to include a complete lifecycle of the plan implemented in 2032, the last year of the IRP study period. Cost effectiveness results are computed for the Participant, Utility, Ratepayer Impact and Societal tests. Finally a calculation of relative rate impacts between plans is calculated for the year 2022, the last year of the IRP action plan. LADCO Services, LLC 2 March 24, 2017

20 Section 3 's 2017 Conservation Plan GRE's projected 2017 conservation plan is shown in Table 3.1 below. The participant incentives, administrative costs and savings at the meter were supplied by GRE. The savings at the generator are a result of the modeling that considers loadshapes and system losses. Costs and savings associated with GRE's load management programs are not included, as these are not expected to vary significantly over time. The savings at the generator of 122,228,338 kwh represent 1.0% of annual sales without opt-out customers. This plan is the basis for the scenario analysis. The report includes assumptions and results for the Commercial/Industrial/Agricultural, Residential and Income Eligible classes as well as for the total plan. Details for the individual programs are shown in the various appendices. These are noted in the upcoming sections. To simplify the analysis, the actual numbers of program participants are not used. Rather participant escalators are used for each scenario. The 2017 plan is assumed to have an escalator of 1.0. LADCO Services, LLC 3 March 24, 2017

21 Section 4 Scenario Definition and Associated Input Parameters Four scenarios are developed for this analysis. These scenarios are defined as: Base Case Scenario This scenario is identical to the 2017 conservation portion of the CIP. Costs are escalated by the Consumer Price Index (CPI) each year, beginning in The measures from the 2017 CIP are used as proxies for measures to be implemented in the future. While the actual measures may vary, the overall spending level and savings level are expected to be representative of the scenario. The Income Eligible programs are not varied by scenario, but are kept at the 2017 level, except for the annual inflation cost escalations, beginning in The Income Eligible Project is based on customer need and is not easily varied. Increases to the Program are not reasonable. This scenario is used as the basis for determining the other scenarios. 1.25% Scenario With the exception of the Income Eligible project, incentives are increased 50% from the Base scenario. Administrative costs increase 121%. Participation increases %. The Income Eligible project does not change from the Base Case. Savings represent 1.25% of sales. 1. 5% Scenario With the exception of the Income Eligible project, incentives increase 125%, administrative costs increase 180% and participation increases %. Again, all are with respect to the Base. The Income Eligible project does not change from the Base. Savings represent 1.50% of sales. 2. 0% Scenario With the exception of the Income Eligible project, incentives increase 234% to equal full incremental cost. Administrative costs increase 273% and participation increases %. The Income Eligible project does not change from the Base Case. Savings represent 2.0% of sales. All percentages are relative to the Base scenario. Table 4.1 below lists the per-measure incentives for each customer class, of each scenario. Individual measure incentives are shown in Appendix 1 along with the incremental costs GRE assumed. The incentives are set to 30% of assumed incremental cost for the Base Case. LADCO Services, LLC 4 March 24, 2017

22 Table 4.2 below lists the participant escalators assumed for each customer class of each scenario. The participation for all programs within a class is escalated using the class escalator. Table 4.3 below lists the annual administrative costs for each customer class, under each scenario. Administrative are not allocated to individual programs within a class. Each plan assumes implementation at a constant level through the year 2032 for all scenarios, including the Base. Plans projecting impacts this far out are suspect in terms of achievable impacts in the later years. Program costs are escalated at the CPI escalator for each year beginning in LADCO Services, LLC 5 March 24, 2017

23 Section 5 Scenario Results Each of the Plans is evaluated for cost-effectiveness over a period from 2018 through 2051, with implementation extending through It is necessary to consider program life past the year of implementation to balance the costs incurred in the first year with benefits in later years. Table 5.1 below lists the 2018 annual energy and peak savings, at the generator, for each project in each scenario. The year 2018 is the first year that the scenarios vary. The cumulative savings for each plan in 2022, the last year of the action plan, are also shown. The cumulative savings include impacts and also factor in losses due to end of measure life. Annual plan level savings and costs are shown in Appendix 2. Individual program savings at the meter are shown in Appendix 3. Total plan spending for each scenario in 2018 is shown in Table 5.2 below. Individual program costs are shown in Appendix 4. Benefit/cost results for each scenario are shown in Table 5.3 below. benefit/cost results are shown in Appendix 5. Program level LADCO Services, LLC 6 March 24, 2017

24 TABLE 5.3: Benefit/Cost Results by Scenario The benefit/cost results indicate the following: The Societal, Utility, and Participant tests indicate that the overall program portfolio is cost effective for all scenarios. This suggests that the effects of varying budget, incentives, and participants do not cause a plan to become not cost-effective; For the Utility test, the program portfolio becomes less cost effective when going from the Base to the 2% scenario. This suggests diminishing returns when increasing the incentive and administrative cost levels. Participation rates do not increase in proportion to the funding and incentive levels; In the Societal test, there is also a decrease in the cost effectiveness as the amount of spending increases. This is caused by the increasing administrative costs; The Ratepayer Impact Measure test is not cost effective for any scenario. The present value of the revenue loss and program costs is greater than the present value of the energy and capacity savings; The larger incentives in the 1.25%, 1.6% and 2% scenarios increase the costeffectiveness of the Participant test; LADCO Services, LLC 7 March 24, 2017

25 Examining the results of the Ratepayer Impact Measure Test can provide additional insight. An approximation of relative rate impacts caused by each scenario can be calculated from the results of the cost-effectiveness evaluations. Figure 5.1 below illustrates the impact on average system rate in the year 2022, relative to the Base Scenario ~ 3:;0.6.!II: :!DA t) as0.2 c. Base 0.00 /kwh 1.25% 0.23 /kwh 2.0% 1.01 /kwh ~ ~----~ ~ ~ ~ $17,020 $32,691 $49,707 $84,770.! ~ Annual DSM Spending ($1,000) The rate impacts assume program costs are expensed in the year incurred and also account for energy and capacity savings realized. They represent the change in rates in the year 2022, in 2022 dollars, due to the various scenarios. The rate of the 2% Scenario is 1.01 /kwh greater than the Base Case rate in This is in addition to the 0.49 /kwh increase associated with the Base plan, as opposed to no additional conservation after Of the 1.01 /kwh differential rate impact due to the additional conservation of the 2% scenario, compared to the Base scenario, 0.62 /kwh is due to the program incentives and administrative costs in The remaining 0.39 /kwh is due to the lower sales caused by the increased conservation. While the rate impact caused by the increased program spending remains relatively flat over time, the rate impact due to the lower sales associated with the 2% scenario continues to increase each additional year the scenario is implemented. Figure 5.2 below shows historical sales, sale under the Base scenario and sales under the 2% scenario, beginning in LADCO Services, LLC 8 March 24, 2017

26 , f!g~r~-~-~~:._.. ;!f~.~t~f~~~-~~-~~~~~-..:y~~!~~~-~--~~~-~!! , ::::: ;1==~===~==5=~=== :-===:::::~=: GWh I~'~'~'"' r1 ~ ~ ~ ~'''"' r ~ ~'''~'''"' ''''~'~''''' ~ m ~ m ~ ~ m ~ m ~ ~ m ~ 0 0 ~ ~ ~ ~ ~ N N N N N M N N N N N N N N N N N N N Year =-History -Base -2% Scenario Existing conservation efforts, combined with naturally occurring conservation caused by more strict equipment efficiency standards and personal choice, along with other factors, resulted in relatively flat sales growth over the past several years. Increasing conservation efforts above the current level may likely result in negative load growth and higher rates for customers. LADCO Services, LLC 9 March 24, 2017

27 Appendix 1 Program Incremental Costs and Incentives by Scenario LADCO Services, LLC March 24, 2017

28 Appendix 1: Program Unit Incremental Costs and Incentives by Scenario -- - Unit Incremental Costs ($) Unit Incentives ($) 2,017 2, Plan All scenar1os All Scenarios Base - 1.0% 1.25% 1.50% 2.00% Residential Residential Appliances $1,266, $1,298, $380, $389, $584, $876, $1,298, Hot Water Savings $44, $45, $13, $13, $20, $30, $45, Air Source Heat Pump $1,550, $1,588, $465, $476, $714, $1,072, $1,588, Residential Cooling $2,666, $2,733, $800, $820, $1,230, $1,845, $2,733, GSHP - Residential (Ton) $2,833, $2,904, $850, $871, $1,306, $1,960, $2,904, Res Home Energy Savings $523, $536, $157, $160, $241, $362, $536, AC Tune-u!) - Residential $150, $153, $45, $46, $69, $103, $153, Residential Lighting $1,233, $1,264, $370, $379, $568, $853, $1,264, Electrically Com mutated Motor (ECM) $823, $843, $247, $253, $379, $569, $843, Residential Measure Behavior Modification $66, $68, $20, $20, $30, $46, $68, Water Heat $1 '133, $1 '161, $340, $348, $522, $784, $1,161, CI&A Commercial Agricultural $150,863 $154,635 45, , , , , Commercial Custom $3,133,333 $3,211, , , ,445, ,167, ,211, Commercial Building Engineering & Design Assistance $470,000 $481, , , , , , Commercial GSHP $800,000 $820, , , , , , Commercial HVAC $1,210,000 $1,240, , , , , ,240, Commercial Motors and Drives $1,260,000 $1,291, , , ' , ,291, Commercial New Construction Lighting $1,766,667 $1,810, , , , ,222, ,810, Commercial Retrofit Lighting $4,250,000 $4,356,250 1,275, ,306, ,960, ,940, ,356, Income Eligible $1,400, $1,435, $1,400, $1,435, $1,435, $1,435, $1,435,000.00

29 Appendix 2 Annual Plan Savings and Costs. LADCO Services, LLC March 24, 2017

30 Appendix 2: Annual Plan Savings and Costs Page 1 of4 Base Scenario - Plan Impacts and Costs r~~i~;:;l~ 1,: 0\~~~l ;iii; ;~. ; tf '" ir:~:,\puio\e:i Q~tsz:....::;.: c.;;;;: lsi!~,,;,,,. ~~ :~i.~arnia:j '"0~~r".. ;;~:.~,rt:~ :sa~~~.... ; '? [Tf($)'.'1~?. ~; ,999,459 6,043,846 15,043,305 9,224,445 6,194,942 15,419,388 9,455,057 6,349,816 15,804,872 9,691,433 6,508,561 16,199,994 9,933,719 6,671,275 16,604,994 10,182,062 6,838,057 17,020,119 10,436,613 7,009,008 17,445,622 10,697,529 7,184,234 17,881,762 10,964,967 7,363,839 18,328,806 11,239,091 7,547,935 18,787,027 11,520,068 7,736,634 19,256,702 11,808,070 7,930,050 19,738,120 12,103,272 8,128,301 20,231,573 12,405,854 8,331,508 20,737,362 12,716,000 8,539,796 21,255,796 13,033,900 8,753,291 21,787,191 13,359,747 8,972,123 22,331,871 13,693,741 9,196,426 22,890,168 14,036,085 9,426,337 23,462,422 Savings are at the generator Peak on July weekday

31 Appendix 2: Annual Plan Savings and Costs Page 2 of4 1.25% Scenario - Plan Impacts and Costs Savings are at the generator Peak on July weekday

32 Appendix 2: Annual Plan Savings and Costs Page 3 of4 1.5% Scenario - Plan Impacts and Costs Savings are at the generator Peak at 1600 hrs on July weekday

33 Appendix 2: Annual Plan Savings and Costs Page4 of4 2.0% Scenario - Plan Impacts and Costs Savings are at the generator Peak at on July weekday

34 Appendix 3 Total Meter Savings by Program and Scenario LADCO Services, LLC March 24, 2017

35 Appendix 3: Total Meter Savings by Program and Scenario Annual KWh Savings (KWh} Plan Base -1.0% 1.25% 1.50% 2.00% I Total Residential 41,034,000 41,034,000 51,575,980 62,144,293 83,280,919 Residential Appliances 4,290,000 4,290,000 5,392,137 6,497,027 8,706,808 Hot Water Savings 1,400,000 1,400,000 1,759,672 2,120,242 2,841,382 Air Source Heat Pump 2,500,000 2,500,000 3,142,271 3,786,146 5,073,897 Residential Cooling 1,622,000 1,622,000 2,038,705 2,456,452 3,291,944 GSHP- Residential (Ton) 10,700,000 10,700,000 13,448,920 16,204,707 21,716,280 Res Home Energy Savings 750, , ,681 1,135,844 1,522,169 AC Tune-up - Residential 150, , , , ,434 Residential Lighting 7,500,000 7,500,000 9,426,813 11,358,439 15,221,692 Electrically Commutated Motor (ECM) 2,122,000 2,122,000 2,667,160 3,213,681 4,306,724 Residential Measure Behavior Modification 9,000,000 9,000,000 11,312,176 13,630,127 18,266,030 Water Heat 1,000,000 1,000,000 1,256,908 1,514,459 2,029,559 Total CI&A 66,675,000 66,675,000 83,804, ,976, ,320,838 Commercial Agricultural 1,500,000 1,500,000 1,885,363 2,271,688 3,044,338 Commercial Custom 14,500,000 14,500,000 18,225,172 21,959,649 29,428,604 Commercial Building Engineering & Design Assistance 1,825,000 1,825,000 2,293,858 2,763,887 3,703,945 Commercial GSHP 5,000,000 5,000,000 6,284,542 7,572,293 10,147,794 Commercial HVAC 2,750,000 2,750,000 3,456,498 4,164,761 5,581,287 Commercial Motors and Drives 11,000,000 11,000,000 13,825,993 16,659,044 22,325,148 Commercial New Construction Lighting 15,000,000 15,000,000 18,853,626 22,716,878 30,443,383 Commercial Retrofit Lighting 15,100,000 15,100,000 18,979,317 22,868,324 30,646,339 Total Income Eligible 3,322,000 3,322,000 3,322,000 3,322,000 3,322,000 Total Conservation Plan 111,031, ,031, ,702, ,442, ,923,757 Total Plan at Generator 122,228, ,228, ,690, ,228, ,304,491

36 Appendix 4 Program Costs by Scenario LADCO Services, LLC March 24, 2017

37 Appendix 4: Total Costs by Scenario and Program Total Costs ($) Plan Base -1.0% 1.25% 1.50% 2.00% I Total Residential $7,637,038 $7,827,964 $16,072,872 $24,214,392 $40,669,466 Incentives $3,687,200 $3,779,380 $7,125,502 $12,878,357 $25,568,247 Residential Appliances $380,000 $389,500 $734,349 $1,327,234 $2,635,044 Hot Water Savings $13,200 $13,530 $25,509 $46,104 $91,533 Air Source Heat Pump $465,000 $476,625 $898,611 $1,624,115 $3,224,462 1 Residential CoolinQ $800,000 $820,000 $1,545,997 $2,794,176 $5,547,461 I GSHP- Residential (Ton) $850,000 $871,250 $1,642,622 $2,968,812 $5,894,177 Res Home EnerQv SavinQs $157,000 $160,925 $303,402 $548,357 $1,088,689 AC Tune-up - Residential $45,000 $46,125 $86,962 $157,172 $312,045 Residential Lighting $370,000 $379,250 $715,024 $1,292,306 $2,565,701 Electrically Commutated Motor (ECM) $247,000 $253,175 $477,327 $862,702 $1,712,779 Residential Measure Behavior Modification $20,000 $20,500 $38,650 $69,854 $138,687 Water Heat $340,000 $348,500 $657,049 $1,187,525 $2,357,671 Administrative $3,949,838 $4,048,584 $8,947,371 $11,336,035 $15,101,218 Total CI&A $5,848,467 $5,994,679 $11,946,423 $19,221,342 $34,531,487 Incentives $3,912,259 $4,010,065 $7,560,428 $13,664,425 $27,128,880 Commercial Agricultural $45,259 $46,390 $87,463 $158,077 $313,841 Commercial Custom $940,000 $963,500 $1,816,547 $3,283,157 $6,518,267 Commercial Building Engineering & Design Assistance $141,000 $144,525 $272,482 $492,474 $977,740 Commercial GSHP $240,000 $246,000 $463,799 $838,253 $1,664,238 Commercial HVAC $363,000 $372,075 $701,496 $1,267,857 $2,517,160 Commercial Motors and Drives $378,000 $387,450 $730,484 $1,320,248 $2,621,175 Commercial New Construction LiQhtinQ $530,000 $543,250 $1,024,223 $1,851,142 $3,675,193 Commercial Retrofit LiQhtinQ $1,275,000 $1,306,875 $2,463,933 $4,453,218 $8,841,266 Administrative $1,936,208 $1,984,613 $4,385,995 $5,556,917 $7,402,607 Total Income Eligible $1,557,800 $1,596,745 $1,596,745 $1,596,745 $1,596,745 Incentives $1,400,000 $1,435,000 $1,435,000 $1,435,000 $1,435,000 Administrative $157,800 $161,745 $161,745 $161,745 $161,745 I Total Conservation Plan $15,043,305 $15,419,388 $29,616,040 $45,032,480 $76,797,698 Incentives $8,999,459 $9,224,445 $16,120,929 $27,977,783 $54,132,127 Administrative 6,043,846 6,194,942 13,495,111 17,054,697 22,665,570

38 Appendix 5 Benefit Cost Results by Program LADCO Services, LLC March 24, 2017

39 Appendix 5: Benefit/Cost Results by Program Page 1 of4 BenelltiCost Results - Base Scenario Benefit/Cost Results - Base Scenario Benefit/Cost Results - Base Scenario H:'i[~;~~~ct\ve >;~ ;~~ ~~~~,!~~~~?~~~~,:.~~::;:i:;i ~~~~~~ Commercial Aaricultural Societal $19,926 $2,267 $17, Utility Cost $8,323 $573 $7, Rat~r Impact Measure $21,448 $31,155 $9,707) Participant $18,030 $1,910 $16, Commercial Custom Societal $245,585 $47,076 $198, UIII~Cost L $107,407 $11,9021 $95, o2 Rateoaver lmoact Measure $ $351,984 $91,366)1_ 0.74 Participant $198,773 $39,672 $ Commercial Eng[neertng & Design Assistance Societal $44,539 $7,061 $37, UtilitY Cost $ $1,785 $17, Ratepayer Impact Measure $44,143 $ $10,859) Participant $ $5,951 $24, Commercial Ground Source Heat Pump Societal $140,912 $12,019 $128, Utility Cost $ $3,039 $62, Rat~QIII'Eir Impact Measure $141,855 $157,302 $15, Participant $80,939 $10,129 $70, Commercial HVAC Societal $ $18,179 $77, Utilnv cost $47,784 $4,596 $43, Ratepayer Impact Measure $93,425 $93,082 $ Participant $47,441 $15,320 $32, Commercial Motors & Drives Societal $176,397 $18,931 $157, Utility Cost $74,456 $4 786 $69, Ratepayer lmpacl Measure $184,717 $256,811 $72, Parti~nt $146,550 $15,953 $130, Commercial Lighting -New Construction Societal $ $26,543 $243, Ulility Cost $122,803 $6,711 $116, Rateoaver lmoact Measure $293,141 $370,363 $77,222\ Participant $200,026 $22,369 $ Commercial Lighting -Retrofit Societal $272,745 $63,853 $208, Ulllitv Cost $123,934 $16,143 $107, Ratepayer Impact Measure $294,597 $381,411 $86,814) I 0.77 Particlpanl $210,747 $53,811 $156, Commercial Administrative Costs Societal $0 $29,090 $29,090) Utii~Cost $0 $24,515 $24,515) Rat-Impjlct Measure $0 $24,515 $24,515) Participant $0 $0 $0 #DIV/01 Total Commerclai!Industrtai!Agrtcultural Societal $1,265,932 $225,019 $1, Utilitv Cost $569,558 $74,050 $495, Ratepayer Impact Measure $1,333,944 $1,721,625 $387,681) Participant $932,725 $165,115 $767, Discounted to 2018 BenelltiCost Results - Base Scenario ' Societal $59,054 $ $35, Utility_ Cost $ $19,724 $6, Ratepayer Impact Measure $64,970 $115,754 $50,784' 0.56 Participant $100,879 ~$21,034 $79, Discounted to 2018.,,:;,';. iitfr;0\t?jlii;;i6~ ~~=~,~~~=~"'\:i~.~~~d~t~ ~~lt~~~~ ~~::~~r~~fili~. Residential Aoollances Total Plan Societal $54,026 $19,031 $44, Societal $1,982,976 $492,427 $1.490,549 I 4.03 Utility Cost $28,904 $4,811 $24, Utility Cost $897,347 $190,470 $706,877 I 4.71 Ratepayer Impact Measure $71515 $114,642 $43, 127) I o.62 Rat_~payer lm~ct Measure $2,120,732 $2,944,383.$ Parttctoant $96,815 $19,031 $ Parti<;~p_ant $1, $370,809 $1, I 5.17 Residential AIC & ASHP Tune-up Societal $700 $2,254 1$1,554) Utility Cost $481 $570 ($89) Ratepay~r Impact Measure $1,023 $1,569 $546) Participant $1,221 $2,254 $1,033) Residential Air Source Heat Pump Societal $46,859 $23,288 $23, Utilitv Cost $18,903 $5,888 $13, Ratepayer Impact Measure $50,206 $86,242 $36,036) Partie! ant $77,123 $23,288 $53, Residential Behavortal Societal $7,771 $1,002 $6, Utility Cost $3,741 $253 $3, Ratepayer Impact Measure $11,580 $ $10, Participant $16,795 $1002 $15, Residential Cooling Societal $74,806 $40,065 $34, Utility Cost $42,464 $10,129 $32, Rateoaver lmoact Measure $79,905 $79,395 $ Participant $57,524 $40,065 $17, Residential ECM Motors Societal $36,920 $12,370 $24, Utllnvcost $ $3,127 $13, Ratepayer Impact Measure $40,181 $63,715 $23,534) Participant $54,713 $12,370 $42, Residential Ground Source Heat Pumo Societal $261,578 $42,569 $219, UlilnyCost $113,858 $10,762 $103, Rate~mr Impact Measure $270,093 $391,442 $121, Participant $340,343 $42,569 $297, Residential Home Energy Savings Societal $15,946 $7,863 $8, UlilitvCost $7,837 $1,988 $5, Ratepayer lmoact Measure $17,465 $24,629 $ Participant $20,385 $7,863 $12, Residential Hot Water Savin s Societal $16,185 $661 $15, Utility Cost $7,606 $167 $7, Ratepayer Impact Measure $20,679 $31,238 $10, Partie! ant $23,784 $661 $23, Residential Lighting Societal $ $18,530 $91, UtilityGost $49,103 $4,685 $44, Ratepayer Impact Measure $128,255 $201,354 $73, Partici ant $164,835 $18,530 $146, Residential Water Heaters Societal $23,266 $17,027 $6, UtilitvCost $11,897 $4,305 $7, Ratepayer Impact Measure $30,916 $40,675 $9, Partici ant $29,143 $17,027 $12, Residential Administrative Costs Societal $0 $59,343 $59, Utii~Cost $0 $50,011 $50, Ratepayer lmoact Measure $0 $50,011 $50,011l I o.oo Partlci ant $0 $0 $0 #DIV/01 Total Residential Societal $657,990 $244,003 $413, UtllnyCost $301,208 $96,696 $204, Ratepay.l'r Impact Measure $721,818 $1,107,004 $385, 186) Partici ant $882,681 $184,660 $698, Discounted to 2018

40 Appendix 5: Benefit/Cost Results by Program Page 2 of4 Benefit/Cost Results -1.25% Scenario Benefit/Cost Results -1.25% Scenario Benefit/Cost Results -1.25% Scenario!11,'~lfti~~~:t :; :~,:~.:::.~~ 18 ~=~ ~~~::~::~: ~\~1~ Commercial Aaricultural Societal $25,045 $2,849 $22, UtilityGost $10,462 $1,080 $9, Rateoaver lmoact Measure $ $39,518 $12 561ll 0.68 Participant $23,022 $2,401 $20, Commercial Custom Societal $308,678 $59170 $249, Utility Cost $135,001 $22,439 $112, Rateoaver lmoact Measure $327,572 $449,891 $122,319) Participant $ $49,865 $207, Commercial Enalneerlna & Destan Assistance Societal $55,902 $8,876 $47, Utility Cost $24,280 $3,366 $20, Ratepayer Impact Measure $55,387 $70,211 $14,824) Particijlant $39,104 $7,480 $31, Commercial Ground Source Heat Pump Societal $ $15,107 $162, Utility Cost $82,317 $5,729 $76, Rateoaver lmoact Measure $178,298 $199,623 $21, Participant $103,642 $12,731 $90, commercial HVAC Societal $119,809 $22,850 $96, Utilitv Cost $60,060 $8,665 $51, Ratepayer Impact Measure $117,426 $119,884 $2, Participant $62,518 $19,256 $43, Commercial Motors & Drives Societal $221,625 $23,794 $197, Utility Cost $93,515 $9,023 $84, Ratepayer Impact Measure $232,043 $325,736 $93,693) Participant $187,208 $20,052 $167, commercial Lighting - New Construction Societal $339,625 $ $306, Utility_ Cost $154,084 $12,652 $141, Ratepayer Impact Measure $367,910 $469,457 $101, Participant $255,631 $28,115 $227, Commercial Llg~tlllg - Retrofit Societal $342,077 $ $261, Utility Cost $155,247 $30436 $124, Ratepayer Impact Measure $369,307 $489,095 $119,788) Particijlant $275,035 $67,636 $207, Commercial Administrative Costs societal $0 $64,289 $64,289) Litility_Cost $0 $54179 $54, 179)1_ 0.00 Rateoaver lmoact Measure $0 $54,179 $54, 179) Participant $0 $0 $0 #DIV/01 Total CommercJalllndustrlalljlgrtculturaJ Societal $1,589,874 $310,554 $1, Utility Cost $714,966 $147,570 $567, Ratepayer Impact Measure $1,674,900 $2,217,594 $542,6941 I o. 76 Part!Q!~t l_$1,203,47~~0~ $995,943_L MO Discounted to 2018 Benefit/Cost Results -1.25% Scenario I '::c'!(t~st PiiiSP<>C!J'~ - : >J :;>~:-!!' :;,:, ~Of8 :fuii!iilani:f,i>o!!jii':.. :: :,:;j: :. ::' :-,:... 1:; ;p:i C:: >, C" ::.:: : ;EJZJ. eenliii\j5lllff'-(;l(st&'' :: ::['Net Bii'rii!fltli:::OIBIC Ratio Income Eligible Societal $59,054 $23,405 $35,649 I 2.52 Uti!!!Y_Cost $26,581 $19,724 $6,857 I 1.35 Ratepayer Impact Measure $64,970 $115,754 '$50,784) Particip_ant $100,879 $ $79,845 I 4.80 Discounted to 2018.fiffl!;:-~::i01!$>Yf,. :, ;:;p::':-: l''ii.~~18:$~=~d~ii=i:~;'~ ~~:~j~ ~i;.:::r:r~ ':~f;;~~1=~en'!;;;~:,;;_r~~~~ Residential Aoollances Total Plan Societal $80,469 $23,920 $56, Societal $2,475,325 $697,207 $1,778,118 I 3.55 Utility Cost $36,324 $9,071 $27, Utility-Cost $1,119,705 $365,834 $753,871 I 3.06 Ratepayer lmoact Measure $ $147,113 $57 23Jill 0.61 Ratepayer Impact Measure $2,646,297 $3,801,353 $1,155, Participant $125,275 $23,920 $101, Participant $2, $460,669 $1,987,955 I 5.32 Residential A/C & ASHP Tune-up Societal $879 $2 833 $1, UtilitY Cost _L $605 $1,0741 ($469)] 0.56 Ratepayer Impact Measure $1286 $2,330 $1, Participant $1,960 $2,833 $ Residential Air Source Heat Pump Societal $58,892 $29,270 $ Utility Cost $23,756 $11,100 $12, Ratepayer Impact Measure $63,084 $112,081 $48, ParticiPant $101,327 $29,270 $72, Residential Behavortal Societal $9,767 $1259 $8, Utility Cost $4,702 $477 $4, Ratepayer ImPact Measure $14,555 $ $13, Participant $21,299 $1259 $20, Residential Cooling Societal $93,867 $50,358 $43, UtilltvCost $53,262 $19,097 $34, Ratepayer Impact Measure $100,234 $106,070 $5, Participant $79,856 $50,358 $29, Residential ECM Motors Societal $46,405 $15,548 $30, UtilitY Cost $20,630 $5,896 $14, Ratepayer Impact Measure $50,504 $82,049 $31, Partlcioant $71,102 $15,548 $55, Residential Ground Source Heat Pump Societal $328,320 $53,505 $274, Utility Cost $142,802 $ $122, Rateoaver lmoact Measure $338,894 $498,489 $159, Participant $435,806 $53,505 $382, Residential Home Energy Savl~gs Societal $20,D43 $9,883 $10, Utility Cost $9,851 $3,748 $6, Ratepayer Impact Measure $21,952 $32,205 $10,253) Partlcjjl;lnt $27,105 $9,883 $17, Residential Hot Water Savings Societal $20,343 $831 $19, Utility Cost $9,560 $315 $9, Rateoaver lmoact Measure $25,991 $39,368 ($13,37DJ 0.66 Participant $30,019 $831 $29, Residential Lighting Societal $138,169 $23,290 $114, UtilitvCost $61,713 $8,832 $52, Ratepayer Impact Measure $161,193 $256,021 $94,828) Partic_lmlnt $ $23,290 $187, Residential Water Heaters Societal $29,243 $21,402 $7, Utility Cost $14,953 $8,116 $6, Ratel'l'Y!lr Impact Measure $38,857 $53,830 $14,973) Participant $39,841 $21,402 $18, Residential Administrative Costs Societal $0 $131,149 $131, Utllitv Cost $0 $110,523 $110 52:!) Ratepayer Impact Measure $0 $110,523 $110, Participant $0 $0 $0 #D\V/0\ Total Residential Societal $826,397 $363,248 $ Uti!!!Y_Cost $378,158 $198,540 $ Rateoaver lmoact Measure $906,427 $1,468,005 $561, Participant $1,144,266 $232,099 $912, Discounted to 2018

41 Appendix 5: Benefit/Cost Results by Program Page 3 of4 Benefit/Cost Results -1.5% Scenario Benefit/Cost Results -1.5% Scenario Benefit/Cost Results - 1.5% Scenario I~~~~~~~~;~ ~~f1!t :~;::~~ 1 ~:r::::t-~~~~~f:~a:~; MJitt~ icommerclal Agricultural ISacletal 1 $3o,trrl j3,433l $26, ~-~~ U.OI 9.81 LSacietal I $371,9291 $71,2951 $300, Jtil~yCast I $162,6631 $40,5561 $122, ~atepayer Impact Measure I $394,694 I $555,595 I ($160,901)1 0?artlcipant 1 _ $323,!i6_11 ~ $263, ~ :::ommerclal Enalneertna & Destan Assistance lacletal I $67,277 I $10,694 Jtility Cast I $29,202 I $6,083 latepayei.iiiipact_~asure_l $66,640 l $86,5~ >artlcipant I $49,145 I $9.012 ~ommerclal Ground Source Heat Pump lacietal I $213,4Q Jtil~vcast L_ $99,184!Ratepayer Impact Measure I $214,8<!Participant 1 $128,331 tthvac Lsacietal IUtilitv Cast I Ratepayer Impact Measure IPartlciJl.llll! I commercial Motors & Driv!Societal Utii~Cast :t Measure Participant Commercial Lighting- N.. $ $72,36> $141.48> $80,548-: 1266,91 12, , ,005 Societal =r J408,419 Utility Cast I $185,092 I Ratepayer Impact Measure I $442,268!Participant I_ $31M~ l Commercial Lighting - Retrofit :ietal I $411,038 ltv Cast I $186,: tepayer Impact M_llasure j_ $443,491l' >artlclpant I $349,728 :ommerclal Administrative Cosl )ocietal _10 Jtllitv Cast jq I Ratepayer Impact Measure $0 $0 _$_18,203 $10,355 $243,979 $15,340 $ $15,661 $149,669 _12;!,202 $28,669 $16,309 $397,837 $24,161 _140,198 $ $572,810 _133,876_ $96,703 $55,009 _j 06,95~_ $ _j81,452 $ $ $0 $56,583 I 6.29 $23, ao ($19,943)1 $40,133 I 5.45 $195,202 1 tt.72 $88,829~ ($29,147) $112,991 I 8.37 $tt6,a $56,706 I 4.62 ($8,182) $57,346] M7- $238,248 I 9.31 $206,844 I 9.56 $368,221 I!Q.16 $162,226 1 a.o9 ($130,542)1 o: $2Bt,I ~ $314,335 I 4.25 $131,261 I c$tsm59ll on $268,233 I :-<ii!m52ll-o.oo C$6B.642l 1 o.oo C$68,642> I 0.1 $0 I #DIV/01 [Societal $1,91! $ I $1.535,342 I 5.06!Utilitv Cost $851 $237,434 I $622,537 I 3.62 I RatePayer Impact Measure $2,0H $2,730,338 1 ($715,0t8JI o.74 jparticlpan $1,501 $25o.o6t 1 $1,256, o:r Discounted to 2018,~,::~g.;~-i/:~;f'~h~ Societal $2.~~7.686 $847,401 $2,120,285 I 3.50 Utility-Cast $1,341,775 $556,270 $785,505 I 2.41 Ra~r Impact Measure $3,171,596 $4,674,356 '$1,502,760) I 0.68 Participant $3,048,882 $550,751 $2,498,131 I 5.54 Benefit/Cost Results - 1.5% Scenario I':;:: -tfliri'peii!p!ii;i!ve c: :.:I '': '\':'.>- 2018'ti\ciwiaiid'DOU$rs''\H<;;'.> h<.z:: ;:!': :; Societal $59,054 $23,405 $35, Utjlity_Cost $26,581 $19,724 $6, Ratepayer Impact Measure $64,970 $ '$50, Participant $100,879 $21,034 $79, Discounted to 2018 Discounted to 2018

42 Appendix 5: Benefit/Cost Results by Program Page4of4 Benefit/Cost Results - 2.0% Scenario Benefit/Cost Results - 2.0% Scenario Benefit/Cost Results - 2.0'/o Scenario -~.-e;;~~~~~~ ~::,~.~~:~:;:~~=f; ~&,.,f! ~ocietal $40,440 $4,600 Jtility Cost _jt6,892 $~77 IRatep~l~t Measure $43,525 $65,940 I Participant $39,30 $3,81 Custom [So~lOial_- L _ $498~ $95,5~ IUtllityCost _ I $217,9871 $80,518 1 I Ratepayer Impact Measure I $528,9< $770,729 I Participant I $459,78 $80,518 l~merclai_e;nglneerimt~ Deslan Assl.nee!Societal I $89,98 Utility Cost Rate a er Jm act Measure Partici ant 1,785 Commercial Ground Source Hea un Societal 85,' ;Utility Cost 32.' ~e~ l~ct Measure 287, larticipant 78,1 mmerclal HVAC ~ietal!1_93, 182 lity Cost $96,796 IRateoaver Impact Measure $189,314!Participant $118, Motors & Driv!Societal $357,479 Utility Cost $150!Ratepayer Impact Measure ~74,1~ ~~~~I_ 320,09i Llahtlna - Ne \Societal 545,30 Utility Cost 24M~ /Ratepayer Impact Measure &589,981 I Participant &437,74; Ljghtlllll- R~ofll_ $14,332 $12,078 $119,860 ~078 $24,394 $20,558 $333,545 $20,558. $36,896 $31,094 $210,568 $31,094 $38,421 $32,378 $5~515_ $32,378 $53,870 $45,3~ $ $45,398 l c>cietal I $548,282 I $129,593 $247,817 $590,883 $847,2oo $504,173 $109,213 1cietal I $0 I $108,506 ility Cost _j!til_- _i!~f4~ IBat~~r ~ct Measure I $0 I $91,442 I Participant I $0 I $0 Total lsoclet<ll_!utility Cost I Ratepayer Impact Measure I Participant Discounted to ,558,84 $506,155!.148,6: $ ,693,50 $3,763,922 $335,1_1±_ Benefit/Cost Results - 2.0% Scenario $35,840 I 8.79!13,015T: 4.3B: {$22,415) $35,430 I M02,885 1~2~ $ I 2.11 ($241,796) $379,266 I 5. $75,651 I 6.28 $26,938 I 3.23 ($30,769)\ 0.74 $57, $261,348 $112,1!li M6 ($45,905) QJl $158, 8.69!156,286_ ~M_ $65,702 ~ ($21,254) J.90 $86, $319,058 I 9.30 $118,343 I 4.66 <!_169,TI_ijl 69 $287, $ I _j:!01,240_j.~ ($191,104) $392,344 I 9.64 $418,689 I 4.23 $138,604 2.: $256,355 o: $394, ($108,506)1 0.1 _i$91,442)1_jl.l ($91,442l 1 o.1 $0 I #DIV/01 $2,052,689 _J;.Q _ $722, ($1,070,4' o:!1,792,484 M.. ij<te$i!'eifbiic!ivo Vt!LS - i?;7"2o:1~jtiowiarid'jxillin'll : >::o::;:;:nj :;;;2 :.;, i\\.1: _.;.- - _-,:~y,c~~it!niifbilneiltii7bicriitlo Income Eligible Societal $59,054 $23,405 $35,649 I 2.52 Util~yCost $26,581 $ $6,857 I 1.35 Rat~er Impact Measure $64,970 $115,754 $50,7~ 0.56 Participant $100,879 $21,034 $79,845 I 4.80 Discounted to 2018 [~,; ;~~~l?i~ji'it;t, \ 1 ~,:~~:: 18 ~::~~~~~~::::-:t'l# ;~~~,:,:&.::ZQ~!~=d~l~~~1~'~'~ Residential APPliances Societal $129,918 $38,624 $91, $3,950,075 $1,125,684 $2,824,391 I 3.51 Utility Cost $58,640 $ $26, $1,784,300 $948,656 $835;644 I 1.88 Ratep!l}'l!r lm@ct Measure $145,100 $ $110,33IDI 0.57 $4,219,037 $6,430,340 '$2,211,303) Participant $223,528 $38,624 $ $4, $730,922 $3,551,352 I 5.86 Residential AJC & ASHP Tune-up Societal $1,420 $4,574 $3,154)\ 0.31 Utility Cost $977 I $3,855 ~2.878) 1 o.25 Rateoaver lmoact Measure $2,077 $5,882 $3,805) Participant $5 680 $4,574 $1, Residential Air Source Heat Pump Societal $95,070 $47,263 $47, Utilitv Cost $38,343 $39,831 $1.488) Ratepayer Impact Measure $101,765 $202,805 $ ) Particlp~nt $189,610 $ $142, Residential Behavorial Societal $15,771 $2,033 $13, Utility Cost $7,592 $1 713 $5, Ratepjly_er lm_11llct Measure $23,502 $46,036 $22, Participant $35,509 $2,033 $ Residential Cooling Societal $151,159 $81,313 $69, UtilityCost $85,712 $68,526 $ Rateoaver lmoact Measure $161,306 $ $47, Participant $173,668 $ $92, Residential ECM Motors Societal $74,929 $25,106 $49, UtilltvCost $33,310 $21,157 $12, Ratepayer Impact Measure $81,546 $144,121 $62,575)\ 0.57 Partic]2ant $128,618 $25,106 $103, Residential Ground Source Heat Pump Societal $528,404 $86,396 $442, Utility Cost $229,410 $72,809 $156, Rateoaver lmoact Measure $544,894 $843,817 ~ Partici ant $751,224 $86,396 $664, Residential Home Energy savings Societal $32,364 $15,958 $ Utilitv Cost $15,906 $13,448 $2, Ratepayer Impact Measure $ $59,399 $23, Partie! ant $52,543 $15,958 $ Residential Hot Water Savin s Societal $32,848 $1,342 $31, Utility Cost $ $1,131 $ Rat~er IIJlllact Measure $41,966 $64,189 $22, Partici ant $49,211 $1,342 $47, Residential Lighting Societal $223,086 $ $ UtilitY Cost $99,634 $31,693 $67, Rateoaver tmoact Measure $260,244 $430,811 $170,567) Partlci ant $360,867 $37,607 $323, Residential Water Heaters Societal $47,208 $34,558 $12, Utility Cost $24,136 $29,123 $4,987) Ratepayer Impact Measure $62,716 $102,919 $40, ParticiPant $83,339 $ $48, I Residential Administrative Costs Societal $0 $221,350 $221,350) util~ycost $0 $186,540 $186,540)\ 0.00 Ratepayer Impact Measure $0 $186,540 $186, Particloant $0 $0 $0 #DIV/01 Total Residential Societal $1,332,177 $596,124 $736, utility Cost $609,097 $502,376 $106, Rati!Jl!ly~r I1J1Pact Measure $1,460,562 $2,550,664 $1,090,102)\ 0.57 Partlcioant $2,053,797 $374,774 $1,679, Discounted to 2018

43 APPENDIX G GRID MODERNIZATION CATALOG INTEGRATED RESOURCE PLAN Submitted to the Minnesota Public Utilities Commission Docket No. ET2/RP April 28, 2017

44 S H A P I N G O U R F U T U R E

45 Shaping our future The future grid initiative and its members are excited about the opportunities that lie ahead for the cooperative members of tomorrow. No one could be fully prepared for the speed of change we are experiencing in our industry, but with thoughtful planning, an innovative workforce and strong relationships among us, we are shaping our future in a way that only cooperatives can. Future grid initiative In 2014, a -member group called the Future Grid Committee was formed to facilitate collaboration among us and develop a common vision of the future. Through our future grid initiative, we are planning, evaluating new technologies, learning from industry peers and leading conversations with other innovators to ensure the best future for our members, our employees and the industry. The future grid initiative complements grid modernization efforts underway at other electric utilities and in states around the country, including in Minnesota. Each process is unique, but the common thread is a commitment to assess all that is in play in today s energy environment and rethink what always has been in terms of how the grid operates, what customers want from their electric utilities, what role regulators should play in grid planning and how electric utilities operate their businesses. Distributed energy resources and the transition from a centralized electric system to one that is far more integrated are central in these discussions. The first phase The first phase of the future grid initiative focused on two primary objectives: 1) developing a shared vision of the future among and its members, and 2) moving toward shared technology platforms. Steps Great River Energy and its members took in the first phase: Facilitated a future grid strategy session for Great River Energy s board of directors and member managers Distributed energy resources and the transition from a centralized electric system to one that is far more integrated are central to discussions about the evolving electric utility industry. Graphic courtesy of EPRI. Powering what s possible

46 PHASE I Learn and assess Develop a shared vision Move toward sharing technology platforms Member forums PUC grid modernization process FUTURE GRID INITIATIVE PHASE II Continue technology implementation Maximize value Provide member forums Leverage R&D relationships Visited leading utilities around the country who are further down the path of implementing advanced grid technologies Participated in the Minnesota Public Utilities Commission s grid modernization process, establishing a leadership position Progressed toward sharing technology platforms such as demand response management systems (DRMS), telecommunications, meter data management systems (MDMS) and advanced metering infrastructure (AMI) Hosted multiple -member forums to facilitate learning and collaboration The next phase Activities in the second phase of the future grid initiative will include: Maximizing the value of the advanced grid technologies being implemented Providing forums that make it easy for Great River Energy and its members to collaborate Leveraging research & development relationships, such as with the Electric Power Research Institute Continuing to monitor industry trends Pillars of technology and its members are well into updating critical systems and implementing advanced grid technologies. Over the last several years, we have made significant progress toward updating and implementing these key technology pillars : AMI: s members continue down the path toward installing advanced metering infrastructure (AMI). AMI is an integrated system of meters, communication networks and data management systems that enables two-way communication between utilities and customers. By the end of 2017, approximately 30 percent of the meters on Great River Energy s members systems are expected to have advanced functionality. DRMS: is deploying a demand response management system because its one-way load management system is reaching end of life. The new system will allow s members to adopt many new demand response technologies while still providing the simplicity of operating a single system. The DRMS brings enhanced analytics to demand response, creating an opportunity to secure and increase the programs value via the wholesale power market.

47 Telecommunications: The fiber backhaul network, 700 MHz wireless broadband and trunked mobile radio (TMR) systems are the three critical components of s telecommunications system. Employees completed an upgrade of the critical TMR radio system from analog to digital technology in early Fifteen members use the system. Employees also worked to update the fiber backhaul and 700 MHz wireless broadband systems which are used by 13 and 23 of s members, respectively. MDMS: implemented a new MDMS system in November of In August of 2016, we began to see savings as a result of more accurate data reported to MISO. Members continue to adopt MDMS systems. Fifteen members have or are installing MDMS systems. Thirteen of those are using the same vendor as (NISC). Getting value from new technologies Now that and its members are working more closely together to share technology platforms, the potential value of the technologies is growing exponentially. A significant focus will be on getting the most value out of the technologies. A few examples: Currently 15 of s members use our two-way radio system (TMR) to communicate between system operators and field staff. At a small cost, other members could use it as well, rather than managing their own systems. A common radio system enables greater field coordination and mutual assistance, as well. now has data analytics resources available to help members who have AMI and MDMS get the most from the data their systems are collecting. For example, worked with Minnesota Valley Electric Cooperative and LREC on a study related to its cycled air conditioning program. The study revealed an opportunity for members to target their marketing efforts more effectively. SHARED TECHNOLOGY PLATFORMS MEMBER COOPERATIVES YUKON + LG 1 ACLARA 1 YUKON, ACLARA & OATI 28 N/A 5 N/A 25 GRE S YUKON 23 GRE S 700 MHZ 11 N/A 1 MOTOROLA TRBO 900MHZ 13 N/A 15 MOTOROLA 13 NISC 2 SENSUS LOGIC 15 N/A 13 GRE 4 N/A 1 EATON COOPER RF 1 LANDIS & GYR PLX 1 LANDIS & GYR TURTLE 1/2 1 LANDIS & GYR TURTLE 2 6 ACLARA 2 ELSTER 4 LANDIS & GYR GRIDSTREAM RF 3 TANTALUS 4 5 SENSUS 0 LOAD MANAGEMENT SYSTEM (LMS) DEMAND RESPONSE MANAGEMENT SYSTEM (DRMS) WIRELESS BROADBAND SCADA NETWORK TRUNKED MOBILE RADIO (TMR) METER DATA MANAGEMENT SYSTEM (MDMS) FIBER BACKHAUL ADVANCED METER INFRASTRUCTURE (AMI) and its members have made significant progress in installing and implementing advanced grid technologies. For example, 15 members are either using or installing meter data management systems, which collect meter data and help co-ops be able to use the data to improve their operations.

48 plans to separate a major combined operating system, the energy management system (EMS) and the distribution management system (DMS). All of s members use the DMS on some level. Separating the systems may open up a growing number of opportunities for new distribution automation capabilities in the future. Making it easy to collaborate facilitates collaboration with and among its members through information-sharing teams, member workshops and other forums. Some groups include: Member Services and Marketing Team, Advertising and Communications Team (ACT), Member Engineering Group (MEG), Cooperative Automation & Technology Group (CATG), Energy Management System Users Group and a Geographic Information Systems Group. As a result of the future grid initiative, new teams for data analytics, meter data management and AMI users also have been formed. Future Grid Committee members Member systems/mrea Greg Miller (co-chair), Dakota Electric Association Syd Briggs, Steele-Waseca Cooperative Electric Ryan Hentges, Minnesota Valley Electric Cooperative Jim Horan, Minnesota Rural Electric Association Greg Ridderbusch, Connexus Energy Steve Shurts, East Central Energy Tim Sullivan, Wright-Hennepin Cooperative Electric Association Tim Thompson, Lake Region Electric Cooperative Adam Tromblay, Nobles Cooperative Electric Steve Wattnem, Cooperative Light & Power Association Will Kaul (co-chair), vice president and chief transmission officer Krista Benjamin, transmission strategic project specialist Jon Brekke, vice president and chief market officer Gary Connett, director, member services and marketing Mark Fagan, vice president and chief business development officer Tessa Haagenson, principal planning analyst Jim Jones, vice president and chief information officer Therese LaCanne, manager, corporate communications Laureen Ross McCalib, director, resource planning Louy Theeuwen, director, executive services Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

49 KEY TECHNOLOGIES

50 Future grid technologies Technological advances are a key driver in the evolution of the electric utility industry. and its member cooperatives are laying the technological groundwork that will enable cooperatives to offer members more options allowing them to further customize their service. describes the technology roadmap below as the five pillars. Telecommunications infrastructure s telecommunications system includes three critical components: the fiber backhaul system, the 700 MHz wireless broadband (SCADA) network and the trunked mobile radio system. In partnership with member cooperatives, plans to build a foundation for smarter energy and deliver solutions and services. Advanced metering infrastructure (AMI) Modern meters fulfill an integral role in providing data to members and cooperatives. AMI automates metering functions using communication networks and eliminates the need for field collection and on-demand polling of meters to verify an outage or restoration. Data collected through AMI can be used to identify customer consumption patterns and identify maintenance needs. Meter data management system (MDMS) An MDMS can help monitor line losses, transformer losses and power theft, and help accurately bill accounts with intermittent generation, such as solar. Demand response management system (DRMS) A modern DRMS will allow and its member cooperatives to better adapt to changes in technology, consumer expectations and market forces. A DRMS is the analytics engine for demand response. It will help cooperatives better understand the impact of demand response, control electric loads at a more granular level and interconnect with other load control technologies. Energy management system (EMS) and distribution management system (DMS) An EMS is a system of computer-aided tools to monitor, control and optimize the performance of the generation and/or transmission system. A DMS is a collection of applications designed to operate the distribution network efficiently and reliably. and its member cooperatives use both systems to collect data and remotely operate the transmission and distribution systems. Powering what s possible

51 Advanced metering infrastructure (AMI) Measurements Historically, electric meters primary function was to measure power consumed over time. With advances in metering, many other measurements are now available. Collecting additional units of measure (UOM) from smart meters enables business improvements and new opportunities. Some units of measure to consider beyond energy are: Current used to analyze losses, etc. Voltage used to analyze losses, outages and health of electric grid, etc. Events used to determine when electrical or physical meters issues occur. Overview Cooperatives have long depended on meters to monitor the electric system and measure the electricity being consumed at homes and businesses. Technological advancements in metering now allow the devices to do more than just measure energy, fulfilling an integral role in providing data to members and cooperatives. Most digital meters contain chips that enable them to send kilowatt-hour (kwh) use readings and other data to electric cooperatives what s called automated meter reading, or AMR. Some units go a step further and can send and receive signals from a co-op, opening up a world of possibilities. This allows co-ops to install AMI, or advanced meter infrastructure systems. AMI is an integrated system of meters, communication networks and data management systems that enables twoway communication between utilities and customers. AMI is a foundational technology for the future grid enhancements planned by and its member cooperatives. Frequency of data capture Today s meters are capable of capturing data at intervals not available in the past. Hourly meter readings provide a 60-minute view of consumption measures (e.g., energy) and hourly snapshots of instantaneous measures (e.g., voltage). About 8,800 measurements are collected for a single meter in a year. Fifteen-minute readings provide four times more granularity than hourly meter readings, which is useful in understanding changes in consumption and demand response. Nearly 35,000 measurements are collected for a single meter in a year. Benefits of AMI The primary function of AMI is to automate metering functions using communication networks. AMI also eliminates the need for field collection and on-demand polling of meters to verify an outage or restoration. Data collected through AMI can identify customer consumption patterns, identify maintenance needs, drive demand response strategies and much more. Powering what s possible

52 The two-way nature of AMI systems also makes them a platform for executing demand response. This enables the electric utility to deploy demand response with an incremental investment (load control devices) versus having to install a separate communications network and load control devices. To participate in s demand response programs, AMI systems should have the capability to control loads across the AMI system s communication network by Jan. 1, Other AMI use cases Better educating members about energy use Providing more information for customer service representatives Identifying and tracking losses Monitoring and improving distribution line voltages Improving load forecasting accuracy Enabling rate and billing plan options Improving outage identification and response Contact information John Aiton, leader, energy data and metering infrastructure jaiton@grenergy.com A field guide to meters Electromechanical meter Invented in 1888, this meter tracks electricity use with spinning dials. It can only be used to measure kwh consumed. Solid-state electronic meter An LED screen displays electricity use on this digital meter, which is accurate and inexpensive, but lacks advanced features. AMR smart meter This meter sends information to a centralized database, and can record and analyze electricity use. AMI meter This meter allows for two-way communication with the cooperative and offers enhanced options, such as time-of-use rates Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

53 Demand response management system Overview Utilities have long understood that they can use the electric system efficiently and economically by reducing demand at certain times. and its member cooperatives are leaders in this discipline, known as demand response. By controlling electric loads, can reduce the amount of electricity it must purchase during periods of high energy prices, which saves everyone money. This is particularly valuable for cooperatives, which provide electricity at cost. New system, new possibilities has established its demand response practice using a system that sends one-way signals to cycle certain devices off and on. As the technology nears the end of its useful life, has installed a modern demand response management system. The new system will help better adapt to changes in technology, consumer expectations and market forces. It will allow more precise control and allow for interconnection with growing load control technologies, such as smart thermostats and Wi-Fi-enabled devices. With two-way communication, will be able to accurately monitor the effectiveness of its demand response and analyze data to continually improve its programs. 2,700 2,500 2,300 Summer MW 2,100 1,900 1,700 Winter 1,500 1, Hour Demand response allows to avoid purchasing electricity when heightened demand drives up market prices, such as summer evenings. Powering what s possible

54 Project road map In 2017, will begin transitioning existing demand response programs to the new system. The system will then be made available to s member cooperatives, which can benefit from the system s additional capabilities Base System implementation Communication Execution Communication Planning and Execution Integration with MDMS; Members in GRE Node Yukon Integration MDMS Integration Initial Member AMI & Load Control Integration with GRE Load Management Web Services Other GRE System Integrations GIS Systems Integration EMS SCADA Integration Tesla Integration Integration with DSMR MDMS phase 2; load events delivered to MDMS Additional Member Integrations; MDMS and Load Control Additional Co-op Integrations; MDMS and Load Control Contact information John Reinhart, demand response and technologies lead jreinhart@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

55 Meter data management system The decision to deploy advanced metering infrastructure brings about an increase in data coming into electric cooperatives. 30,000 Just how steep is the rise? Take, for instance, a cooperative with 10,000 members. With monthly meter readings, it would collect 10,000 meter readings per month. Meter data accumulates quickly when that cooperative begins collecting meter data hourly (7.3 million per month) or every 15 minutes (29 million per month). Establishing processes and systems early ensures cooperatives can keep up with growing data demands. The system designed to handle this avalanche of data is known as a meter data management system (MDMS). Meter reading per year per member 20,000 10,000 Every 15 minutes 35,040/year Meter reading interval An MDMS collects meter data and subjects it to a continuous set of parameters to ensure the data is complete and accurate. With an abundance of clean data, cooperatives can do many things. and two member cooperatives conducted an MDMS demonstration project that uncovered a wide variety of business applications to both Great River Energy and distribution cooperatives: J F M A M J J A S O N D Month Hourly 8,760/year Monthly 12/year Monitoring line losses Monitoring transformer losses Identifying power theft Billing accounts with intermittent generation, such as solar. Analyzing energy data Contact information John Aiton, leader, energy data and metering infrastructure jaiton@grenergy.com These applications deliver substantial monetary value to utilities and reap a return on the MDMS investment. Powering what s possible

56 Fiber backhaul network Overview s fiber backhaul network connects its communication towers to the organization s headquarters building to transport or backhaul data from the field to its data centers. This system carries data from Great River Energy s trunked mobile radio system, 700 MHz wireless broadband (SCADA) network, load management system and member cooperative owned communication systems. The backhaul network is a critical component for Great River Energy and its member cooperatives to support important communication needs. The network is a combination of telephone company leased circuits, Great River Energy owned fiber and fiber shared with neighboring utilities. A fiber backhaul network is the backbone that supports other systems such as advanced metering infrastructure, automated meter reading and distribution automation. This network consists of two main components the fiber optic cable buried in the ground or hanging on Great River Energy s transmission lines and the electronics required to move the data over the fiber. F I B E R B A C K H A U L TELECOMMUNICATION S S Y S TEMS N E T W O R K SUBSTATIONS 700 MHZ WIRELESS TRUNKED MOBILE RADIO POWER LINE SWITCHES N E T W O R K DATA CENTER FIBER BACKHAUL 700 MHZ WIRELESS BROADBAND TRUNKED MOBILE RADIO F I B E R B A C K H A U L Project update is working to migrate the electronic equipment on its fiber backhaul network from SONET to multiprotocol layer switching (MPLS). This three-year project was started in conjunction with the trunked mobile radio system replacement, which was completed in early 2017, and the 700 MHz wireless broadband (SCADA) network replacement. The anticipated project completion date is March In conjunction with the MPLS upgrade, has been building out fiber to both transmission and distribution substations. So far, 70 transmission substations have been connected with fiber in addition to 60 member cooperative distribution substations. While bringing fiber to transmission substations has been a strategic goal, distribution substations have been added when it makes economic sense. Powering what s possible

57 Current state is currently migrating the electronic equipment from SONET to MPLS on its fiber backhaul network. The fiber has an expected life span of years, while the life span of the electronic components is only 7-10 years. s upgrade will only replace the electronics portion that is at end of life. This will prepare and others for future business needs in support of the future grid. s fiber backhaul is a combination of leased telecommunication circuits, owned fiber and shared fiber with neighboring utilities. The network was originally installed in 2006 to support the 700 MHz wireless broadband (SCADA) network deployed at the same time. It is a high-bandwidth fiber network extending across the majority of s service territory. Backhaul network transports 700 MHz wireless broadband (SCADA) network, trunked mobile radio, load management and business network traffic. Twenty-seven of s 28 member territories have an entry point or node available for use which offers them access to the network. Nearly all of s telecommunication sites are covered with backup power generators to ensure system reliability in the event of a power outage. Thirteen member cooperatives currently take advantage of the network for other uses. s lease for its fiber backhaul network is valid through How we use it today A number of member-owners are utilizing the network in various ways, including: Advanced metering infrastructure needs. Accessing offsite shared disk storage located at Great River Energy s headquarters. This enables Great River Energy to remotely support and troubleshoot issues on their networks. Accessing other members networks to fulfill after-hours dispatch responsibilities. Connecting their mobile radio repeaters, distribution automation sites and Verizon downline automation devices. Connecting member outpost service centers to one another. How we ll use it in the future and its member-owners are excited about the opportunities new technology and the changing industry provide. Years of planning and preparation have put in an excellent position to serve members well into the future. The updated fiber backhaul system will: Continue to support s day-to-day business operations. Support the backhauling of data as member cooperatives expand deployment of future grid technologies like advanced metering infrastructure, automated meter reading and distribution automation. Allow to strategically add optical ground wire on all new transmission lines. Enable expansion of rural broadband in Great River Energy s member territories through strategic partnerships. Bring fiber connections to all 110 of Great River Energy s transmission substations, in preparation for future North American Electric Reliability Corporation (NERC) requirements. Assist in bringing fiber connections to distribution substations to support member requirements. Contact information Chris Leleux, manager, infrastructure services cleleux@grenergy.com Michael Tate, telecommunications engineer II mtate@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

58 700 MHz wireless broadband (SCADA) network Overview s 700 MHz wireless broadband (SCADA) network connects to about half of its transmission substations and most of its members distribution substations, and automated switches. uses the broadband network primarily for SCADA communications, metering and network access including Wi-Fi and voice over internet protocol (VoIP) phones. Project update Currently underway, s multi-year 700 MHz wireless broadband (SCADA) network project will include the purchase of the spectrum license and the replacement of the aging electronics. The project will be done in two phases. Phase one includes the installation of a Cisco router with cellular backup. This will allow SCADA traffic to failover to the cellular network during the cutover to the new system in phase two. Phase one is currently underway with approximately 30 sites being installed each month. The project is expected to be complete by the end of Current state s 700 MHz wireless broadband (SCADA) network was originally installed in 2006 and includes 550 remote locations. The network requires two components to operate: radio frequency spectrum and electronics. The expected life span of electronic components is typically 5-7 years. s network electronic components have reached their end of life. This multi-year network project will include the purchase of the spectrum license that is currently leased and the replacement of the aging electronics. The network consists of 64 tower locations throughout s service territory. Almost 75 percent of s telecommunication sites are covered with backup power generators to ensure system reliability in the event of a power outage. 471 member distribution substations are connected to this network. leases radio frequency spectrum from a third party to operate the network. This lease expires in The lease holder has approached about purchasing the spectrum for its territory after the lease expires. s 700 MHz wireless broadband (SCADA) network will enable its member cooperatives to use AMI and meter data management technologies that may not be otherwise possible. Powering what s possible

59 How we use it today s 700 MHz wireless broadband (SCADA) network has become a critical component for and its member cooperatives. uses the broadband network primarily for SCADA communications, metering and network access including Wi-Fi and voice over internet protocol (VoIP) phones. Twenty-three of s member-owners use the network to connect to more than 400 devices for their own data communication needs. s member-owners primarily use the network for advanced metering infrastructure (AMI) and advanced meter reading (AMR) systems. How we ll use it in the future In planning for the future, sought to understand its member cooperatives plans for advanced metering infrastructure (AMI) and meter data management (MDM), as well as other technologies they may be considering. The new network will: Continue to support and participating member cooperatives day-to-day business operations in transporting SCADA data communications. Enable member cooperatives to use AMI and MDM technologies that may not be otherwise possible. Leverage meter data for mutual benefits through the use of secure, shared systems. Broadband companies could utilize Great River Energy s towers to provide rural broadband to their customers. Contact information Chris Leleux, manager, infrastructure services cleleux@grenergy.com Kathy Shaft, senior telecommunications engineer kshaft@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

60 Trunked mobile radio system Overview and over half of its member cooperatives own and use the Motorola trunked mobile radio (TMR) system for important two-way communications. When line crews are dispatched to remote locations or outage areas, they need to be able to talk to each other and to system operators so they can identify where faults are located and fix the problems. To do that, they rely on their TMR system. In early 2017, and its members completed a major update to this system from analog to digital technology. The new digital technology is critical to grid evolution as works to shape its future and provide more options for its member cooperatives, as well as improve reliability and security. Current state currently has a fully manufacturer supported, mission critical digital mobile radio system. The system includes 81 communication tower sites across Great River Energy s service territory and areas of North Dakota where its field crews operate. The system supports approximately 700 mobile radios used by Great River Energy and includes more than 500 radios owned by its 15 participating member cooperatives. The upgraded system is fully redundant with automatic failover at Great River Energy s backup control center to ensure continued reliability and security. How we use it today, its 15 participating member cooperatives and both groups of field crews use the TMR system for important two-way communications. The TMR is often used as a dispatching tool for those currently utilizing the system. The two-way radio system enables the Great River Energy system operations group to communicate critical information to the field services crews and with each other. and its participating cooperatives communicate with each other on the joint system. The twoway radio system allows participating field crews to communicate with each other and system operators during storms, outages or after being dispatched to remote locations. They also rely on the system to notify Great River Energy s system operations when safe entrance is needed to secured locations in order to conduct work in a safe manner. How we ll use it in the future Technologies that allow information to flow back and forth support the grid of the future by providing critical two-way communications. The upgraded TMR system will continue to support s and its member cooperatives day-to-day business operations using a highly reliable digital mobile radio system. During critical times of need, s TMR system will continue to offer reliable communications when other tools, such as cell phones, may be unavailable. During the recent TMR upgrade, on behalf of its membership, negotiated lower cost subscriber pricing making it more cost effective for the remaining member cooperatives to participate in the joint system in the future. encourages the use of the joint system by more member cooperatives as there s a benefit for all member cooperatives to be on the system for mutual aid and switching. Powering what s possible

61 Participating member owners system operations Arrowhead North Itasca Itasca-Mantrap Lake Country Power Co-op Light & Power Lake Region Todd- Wadena Crow Wing Mille Lacs Runestone East Central Energy Stearns Agralite Connexus Kandiyohi Meeker McLeod Wright- Hennepin Dakota Nobles Redwood Brown County South Central BENCO Minnesota Valley Steele- Waseca Goodhue County Federated Trunked mobile radio system (TMR) Contact information Chris Leleux, manager, infrastructure services Kathy Nelson, principal telecommunications engineer Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

62 RESEARCH AND DEVELOPMENT

63 Upcoming projects The process of researching, designing and implementing innovative new projects and programs to better serve members and also prepare for the energy grid of the future are an ongoing effort within every division at. The following are descriptions of pilot projects from s generation and member services divisions that are in various stages of this process. Dickinson Solar Project storage and tracking partnered with member Wright- Hennepin Cooperative Electric Association on a 2.25-megawatt solar array that directly serves the distribution cooperative s membership. The 8,000-plus panels, 464 racks and three inverters went into service Aug. 22, 2016, marking the end of the project s first phase. The second phase, which would add tracking arrays, incorporate battery storage and include smart grid technologies, is currently in project development. Project leaders hope to learn and understand the cost and benefits of fixed versus tracking arrays with and without battery storage. Contact information Vince Herda, principal engineer, generation vherda@grenergy.com Cole Funseth, engineer II, generation cfunseth@grenergy.com EnergyWise MN Store is partnering with Simple Energy, the No. 1 provider of utility-branded marketplaces, to launch a new EnergyWise MN Store. It will feature integrated instant rebates on smart home and energy efficiency products. With a few clicks of a mouse, members across the state can validate their eligibility and unlock significant savings on LED lighting, Wi-Fi thermostats, smart home products, and water saving products from popular brands like Nest, ecobee, Philips, GE and more. Those involved in the project wanted to make it easy and affordable for cooperative members to make significant changes that can greatly increase their energy efficiency and comfort. The EnergyWise MN Store will be the first marketplace of its kind to serve customers of multiple energy cooperatives under a single platform and brand. Contact information Tara Collins, senior marketing specialist tcollins@grenergy.com Zero-Net Energy dairy farm has joined EPRI s Advanced Energy Communities Supplemental Project to evaluate the application of a Zero Net Energy (ZNE) dairy farm affiliated with the University of Minnesota-Morris, West Central Research and Outreach Center. EPRI has conducted extensive research into Advanced Energy Communities to better understand how customer-side systems enable utility customers as well as how they impact the electricity grid. Net Zero communities are typically envisioned as residential communities, but the same applies for commercial, industrial and agricultural institutions. Powering what s possible

64 The project will evaluate how ZNE works in reality with the farm and focus on understanding the thermal energy flows and opportunities for heat recovery and energy efficiency. It will also identify additional opportunities for energy efficiency at the farm, including the potential conversion of thermal loads from fossil heating systems to electric heating systems. It will conduct measurements of energy usage and develop a load-shape model using the operating schedules and functioning of the dairy farm as well as look at how applications of renewables, both solar and wind generation (currently at the farm and planned for 2017 installation) will impact net-load shape and distribution system impacts. Efforts on this project began in December 2016 and are estimated to continue through December Contact information Jeff Haase, strategic energy and efficiency program representative jhaase@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

65 Battery electric school bus pilot Overview As part of s commitment to innovation and minimizing its impact on the environment through reducing emissions, as well as responding to member interest, it is seeking to demonstrate the performance of battery electric school buses (BESB) on our system. The objectives of the BESB pilot are to showcase new energy-efficient technologies, demonstrate its performance in Minnesota s cold-weather climate and on longer, suburban and rural routes due to the unique service territories of Great River Energy s 28 member cooperatives. The team also would use the opportunity to document the regional economics of the addition of BESBs, including operation and maintenances cost savings and also quantify associated emissions reductions directly in the communities that the co-ops serve. One model of BESB that is being evaluated is the elion and is manufactured by the Lion Bus Company. It has a range of up to 100 miles with the optional fifth battery module and takes approximately six-and-a-half hours overnight to charge. Currently, 29 elions are on routes across North America and the company plans to produce 70 more in Project phases While in the process of mapping out key participants for this pilot, the announcement came that Volkswagen would need to invest $2.7 billion in environmental mitigation efforts with eligible projects including replacing diesel vehicles with electric. Of this amount, approximately $43 million was initially allocated to Minnesota. This created the opportunity to develop a phase II pilot for buses two and three in areas requiring more significant grant funding. Knowing the VW settlement funding would not be available for at least another year, the first phase is the purchase of one BESB that is being fully funded by the three major participants (, its local distribution cooperative and the student transportation provider). The current base price of a dedicated BESB is about $325,000, compared to $100,000 to $125,000 for a diesel-fueled school bus. Phase II will rely on more significant grant funding for the purchase of two additional BESBs to help subsidize participation costs for smaller, rural member cooperatives and their transportation providers. In all, is seeking a 50 percent cost share for the overall $1.2 million BESB project, with $600,000 being cash from participants, and a goal of receiving $600,000 of the VW settlement funds. Having multiple BESBs on the system will demonstrate how this technology works in more extreme northern Minnesota climates as well as the southern Minnesota area and on suburban routes closer to the Twin Cities. believes funding a variety of emerging technologies across the state is the most prudent use of the VW settlement funding. Schedule BESB pilot program development began in third quarter of 2016 with business models, the cost/benefit and funding options following in the fourth quarter, continuing into the beginning of Site selection, and securing commitments from the participating member cooperative and student transportation service is slated to continue throughout second quarter. Following that, data gathering and analysis will carry on through until mid-2018 when state and federal grant application and award cycle begins. An evaluation report and recommendation is then planned to be presented in the second quarter of Contact information Sandra Broekema, director, corporate and business development sbroekema@grenergy.com David Ranallo, leader, member services and marketing dranallo@grenergy.com Powering what s possible

66 Conservation voltage reduction pilot project with ECE Overview and its members are researching how members can use conservation voltage reduction (CVR), a term sometimes used interchangeably with demand voltage reduction (DVR), to decrease energy use, lessen their peak loads and reduce demand charges while continuing to serve their members within established voltage parameters. To that end, and East Central Energy (ECE) are conducting a pilot project to retrieve end-offeeder data from the East Central AMI system to automate and enhance the performance of the CVR/DVR control. The initial phase includes two sites with four distribution substation transformers. Description and East Central Energy are working on a pilot project that will allow them to access the data in their AMI to assess whether they can identify opportunities to lessen their peak loads and reduce demand charges. Why it matters employees from IT and transmission are in the midst of setting up the pilot project. Involvement is required from a number of external parties to achieve the equipment installation, data integrations and software installation required to enable the capability. If successful, this pilot will allow other co-ops the opportunity to learn about CVR and how it might impact their bottom line. Sensus Primary Datacenter 900Mhz Flex Net EOL Capacitor EOL EOL Recloser Sub #2 Sub #n EOL Voltage Regulator EOL AMI Sub #1 EOL Legend Sensus DR Datacenter GRE Elk River Primary Site East Central Energy Brahm Primary Site Operation Consoles Multi-Speak EOL End of Line Device Meter Control Devices Distribution Substation Computers/consoles SCADA Xchange for DA SCADA Xchange DNP 3.0 Protocol Voltage levels, signals from cap bank, foult etc. EMS/ SCADA VVC DMA Control Center SCADA Communications AMI Communications Internet Powering what s possible

67 Tentative Schedule the goal date for pilot start is a June/July timeframe. The feasibility of the schedule is being confirmed with the software vendor and other parties involved in the pilot. Work in progress: Execution of non-disclosure agreements and software contracts Set up work by Sensus ECE equipment installation Next Steps Confirmation of schedule and execution of software contract Configuration and development activities Project cost : Software license and implementation costs; internal labor and product user training. East Central Energy: Software license and implementation costs; internal labor and product user training; field hardware and installation costs. Contact information Dick Pursley, manager, system operations dpursley@grenergy.com Vern Johnson, vice president of operations and engineering East Central Energy vern.johnson@ecemn.com Test planning and execution Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

68 Data analytics As advanced metering infrastructure (AMI) and meter data management systems (MDMS) are deployed, utilities are left with exponentially greater amounts of data. Translating mass amounts of raw data into actionable business intelligence is a challenge for cooperatives that may be unaccustomed to data analytics. With the proper resources and strategy, data analytics can improve operations, service to members and efficiency. Data analysis is already shedding new light on some of the nagging questions utilities have long faced: Where should we prioritize our investments? What types of end-use members give us the shortest payback for an energy efficiency program? Although this type of work is relatively new to utilities, it is common in other industries. When data becomes available in abundance, statistical methods are used to identify trends and opportunities. Analysis by Accenture suggests that the potential value of analytics could approach $40 to $70 per electric meter per year, with benefits divided 60 percent to the consumer and 40 percent to the utility. A study conducted by the Electric Power Research Institute found that data analytics can spur improvements in many areas of utility operations. Load shapes constructed from AMI interval data contributed to better targeting of customers for utility programs. Analysis of distribution curves identified where energy efficiency and demand response programs would have the greatest impact to optimize distribution planning. Once accepted as a resource within an organization, data analytics aided in decision-making. Completed projects To help members get the value out of business intelligence and data collected through AMI and MDMS systems, a sub-team with three member cooperatives identified three data analytic projects of interest to their cooperatives to demonstrate how the use of data analytics could be used to improve the efficiency of their distribution system. These member-driven projects Powering what s possible

69 were initiated with the condition they could be repeated and seamlessly integrated to other member cooperatives., in collaboration with Lake Region Electric Cooperative, Minnesota Valley Electric Cooperative and Steele-Waseca Cooperative Electric have completed data analytics projects related to: KRTA data analytics* Residential cycled AC response* Substation losses* * To learn more about these projects, see the individual fact sheets within this book. Projects under consideration The following projects have been vetted and are under consideration as s member cooperatives determine if the projects are of interest and would add value to their cooperatives. Distribution line loss measurement Develop a methodology that utilizes s AMI data and member owners AMI data and SCADA connected reclosers to verify that an aggregation of a substation s feeder data can be used to accurately measure substation losses. Demand response program measurement Member distribution cooperatives have various retail programs that they use to aid in controlling peak load (e.g. cycled AC, peak shave water heating). Currently there are few methods in place to analyze the impact of the retail programs. To improve and aid in expansion of the program offerings, member distribution cooperatives need to better understand the kw impact of the programs in relation to system peak and energy sales, in addition to informing consumers of the potential impact and savings by participating in the retail programs. Target marketing Member distribution cooperatives have various retail programs that they use to aid in either controlling peak load (e.g. cycled AC, peak shave water heating) or strategic energy growth (electric water heaters). Currently there are limited methods in place to target market these programs to (1) maximize the benefit of the program, (2) avoid free riders, and (3) to ensure optimal program enrollment. To improve and aid in expansion of the program offerings, member distribution cooperatives need to better understand who are their customers who participate in their demand response program, identify potential new participants and ensure program marketing campaigns are targeting and enrolling the proper end-use customers. Contact information Nathan Grahl, principal data analyst ngrahl@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

70 Member and community solar initiative A variety of solar technologies and configurations are being tested at s headquarters site. Background began an effort in 2013 to develop and demonstrate distributed generation technologies including solar and other non-traditional technologies in collaboration with its member cooperatives across the state and as direct resources with a goal of advancing internal skills and overall knowledge around these technologies. At this time, the state of Minnesota had enacted a solar energy standard for investor-owned utilities that would require a specific percentage of retail electricity sales to be generated from solar energy. decided to participate in the solar market in response to member interest and needs as a matter of importance to prepare for a future in which solar generation is part of the generation portfolio for both utilities and consumers. developed two action plans to meet its initial solar goals. Headquarters project The first in the series of solar installations was completed at s Maple Grove, Minn., headquarters site in May The 250-kilowatt (kw) project has a research and demonstration component that tests the performance of solar panels from three different manufacturers (Sharp, tenksolar, Suniva) and three inverter manufacturers (Solectria, tenksolar, Advanced Energy). The array provides up to 325,000 kilowatt-hours (kwh) of renewable energy annually, which is enough electricity to power about 27 homes. Member projects Solar arrays were installed in 2014 and 2015 at sites owned by s members with project management led by. The installations are part of a series of 19 projects, each with an electricity generating capacity of 20 kw. The solar projects are helping and its member cooperatives Powering what s possible

71 evaluate the impact of solar energy while providing up to 450,000 kwh of renewable energy annually, which is equivalent to powering about 38 homes. The installations were managed by, which worked with each participating member cooperative to identify the ideal location for their project. Additionally, assisted the member cooperatives with interconnection efforts and collecting and displaying key information about energy production and system interaction. Most of the solar arrays are a packaged system design from tenksolar, while one installation includes panels made by Silicon Energy and another uses panels by SolarWorld. Nine of the participating cooperatives chose to add solar arrays to serve as community solar gardens that were installed at the same time as their 20-kW arrays in the same location, which was done at an incremental cost. This partnership with saved members nearly 40 percent on project installation costs and provides up to 430,000 kwh of renewable energy annually, equivalent to powering about 36 homes. Reflections and next steps These demonstration and membership projects provided an awareness and understanding of the variables tied to solar, which impact both the performance and economics along with the challenges associated with development and implementation of smaller-scale distributive solar projects. As a result of the projects completed so far, Great River Energy firmly believes that community solar developed by the distribution cooperative is the best option for both the utility and end-use consumer. It provides the simplest, lowest cost solar solution and maintains the relationship between the distribution cooperative and end consumer. Great River Energy continues to assist and support its member cooperatives in their community solar garden ventures, with projects in development at Cooperative Light & Power, East Central Energy, Cooperative, Runestone Electric Association and Steele-Waseca Cooperative Electric. In 2016, partnered with member cooperative Wright-Hennepin Cooperative Electric Association to install a 2.25 MW solar array that serves the co-op s membership. The Dickinson Solar Project, named due its location at the Dickinson Converter Station site, provides the membership experience in the development, installation and ongoing operations of a utility-scale solar installation. The array is the largest single solar resource to date for both cooperatives, and is the largest solar array installed by a cooperative in Minnesota. staff continues to track and report on the long-term performance and maintenance of the demonstration and membership solar projects. Opportunities to further explore the understanding and involvement with distributed generation technologies, including battery storage and smart inverters, are ongoing. To view the energy output from s statewide solar projects, visit greatriverenergy.com/solar. Contact information Vince Herda, principal engineer, generation vherda@grenergy.com Mark Rathbun, renewable energy lead mrathbun@grenergy.com The 2.25 MW Dickinson Solar Project serves Wright- Hennepin Cooperative Electric Association s membership. Nathan Domyahn, director, peaking and generation engineering ndomyahn@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

72 PROJECTS AND PROGRAMS

73 Community storage Energy and environmental stakeholders are uniting around community storage to solve the electric industry s energy storage challenge. The Community Storage Initiative has received the support of key industry groups, including the nation s utility trade associations, environmental groups, manufacturers and more than a dozen individual utilities. Both and the Minnesota Rural Electric Association are members of the initiative. Community storage refers to a spectrum of utility-sponsored programs which aggregate electric storage resources available throughout the community, such as water heaters and electric vehicles, to improve the efficiency of electric energy services for consumers. Community storage programs offer the industry the practical steps to rapidly increase the amount of energy storage available. Initiative members have been implementing community storage programs and, through the Initiative, will work together to evolve those programs. Like community solar, community storage enables consumers and utilities to share the system-wide benefits of energy storage environmental benefits, lower costs and grid optimization in communities large and small across the country. Such programs maximize the value of distributed energy resources, many of which are already available to participate in energy storage programs through simple retrofits and program design. The Initiative s advisory council includes representatives from the American Public Power Association, Edison Electric Institute, Natural Resources Defense Council, National Rural Electric Cooperative Association, and Peak Load Management Alliance. The Initiative is chaired by Gary Connett, director of member services at Great River Energy. A list of founding supporters and brief descriptions of their community storage efforts is available on the Initiative s website: communitystorageinitiative.com. Initiative members are conducting a range of innovative community storage programs, including grid-interactive water heating, electric vehicle charging, grid-interactive space heating, ice storage technology, and residential battery storage. Research conducted by The Brattle Group and sponsored by the Initiative s founding members recognized that the nation s 50 million residential electric water heaters collectively represent a significant and vastly underutilized energy storage resource capable of leveraging substantial environmental and cost benefits. An article in the November 2015 edition of Public Utility Fortnightly introduced the community storage concept. Links to both the report and the article can be found on the Community Storage Initiative s website. The Initiative hosted a two-day forum in July 2016 at the University of Minnesota Law School campus where attendees heard group members explain their mission and guiding principles. Those in attendance also discussed where they fit into the growing collaborative and how to help further its vision. Connett participated in a summit at the White House where federal and private sector organizations gathered to discuss scaling renewable energy and storage with smart markets and spoke about the Initiative. He also educated those on Capitol Hill about the Initiative during a congressional briefing about community storage, introducing the concept of how the energy industry can use tried-and-true household technologies to help meet consumer energy needs in a new era. Powering what s possible

74 Electric thermal storage water heating Electric thermal storage (ETS) water heating is a load control strategy that provides households with their daily hot water needs by charging their water heaters only during the lower-cost, off-peak hours. Memberconsumers participating in the ETS program heat their water from the hours of 11 p.m. to 7 a.m. In exchange for this level of control, provides discounted wholesale energy to its member cooperatives for energy sales associated with the ETS program. The strategy requires that a household install a large capacity storage water heater, which is typically between 85 and 105 gallons in size, with the larger water heaters provided to households that have more family members. s ETS resource is able to store a gigawatt of energy each night by controlling the ETS water heaters of more than 65,000 end-use members. This effective form of community storage aggregates distributed energy technologies increases energy efficiency and allows for better integrate renewable energy resources onto the grid and reduce customers monthly electric bill. Electric vehicles Electric vehicles provide another valuable form of community storage. continues to look at ways to make it easier for consumers to drive electric vehicles and currently offers rebates for residential charging stations that encourage off-peak or timeof-use vehicle charging. This strategy enables consumers to use more electricity during night-time hours when prices are typically lower and when the electricity is frequently produced from the region s abundant wind resources. in 2015 launched Revolt, a first-of-its kind program that allows members of its 28 cooperatives to upgrade the electricity they use to fuel their PEVs to wind energy at no additional cost. While the PEVs enrolled in Revolt will be powered by wind energy, standard or offpeak rates still apply for the electricity used to charge them. This program extends to members who already own or lease a PEV and members who purchase or lease one by Dec. 31, Contact information Gary Connett, director of member services gconnett@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

75 Electric Thermal Storage water heating The battery in your basement Electric Thermal Storage (ETS) water heating Electric thermal storage (ETS) water heating is a load control strategy that provides households with their daily hot water needs by charging their water heaters only during the lower-cost, off-peak hours. Member-consumers participating in the ETS program heat their water from the hours of 11 p.m. to 7 a.m. In exchange for this level of control provides discounted wholesale energy to its member cooperatives for energy sales associated with the ETS program. The strategy requires that a household install a large capacity storage water heater, which is typically between 85 and 105 gallons in size, with the larger water heaters provided to households that have more family members. s ETS resource is able to store a gigawatt of energy each night by controlling the ETS water heaters of more than 65,000 end-use members. A recent study from the global economic consulting firm The Brattle Group dubbed this approach to energy storage as community storage. By aggregating distributed energy technologies and home appliances, electric cooperatives are developing community storage to increase energy efficiency, better integrate renewable energy resources onto the grid and reduce customers monthly electric bill., the National Rural Electric Cooperative Association (NRECA), the Natural Resources Defense Council and the Peak Load Management Alliance commissioned the study, The Hidden Battery, to launch a community storage initiative to aggregate battery-like features of appliances. Household water heating Household water heating is one of the more predictable energy consuming activities in a household. The primary variable that dictates hot water consumption is household size. According to the Energy Information Administration s 2009 Residential End-Use Consumption Survey, water heating is responsible for approximately 15 percent of total household consumption. Water Heaters by Type Million Households IA, MN, ND, SD Electricity 1.4 Propane 0.3 Water heaters are often one of the more underappreciated appliances in a home. Typically located in the basement, they tend to be ignored until there is an issue and you run out of hot water. The only thing a homeowner expects from a water heater is hot water. A utility can utilize hot water heaters as a resource, but only if this basic function is met. Grid-interactive water heating Can a water heater provide grid benefit? Natural Gas 2.2 In response to the proposed water heating standards, which would effectively have eliminated the manufacture of electric resistance water heaters larger than 55 gallons, and the NRECA successfully pursued legislation that allows large capacity water heaters to be a component of utility demand response programs. In addition to strategies such as ETS and interruptible water heating, utilities across the country are beginning to look at water heaters to interact with the grid and provide ancillary services. Due to the variable nature of demand, which is now coupled with the variable nature of increased renewable generation, grid operators look at generators to Powering what s possible

76 provide ancillary service to the wholesale market. The generator is turned up or down to provide regulation services which keep generation matched to load and help to maintain voltage throughout the system. This same type of system regulation can occur through the variable control of water heaters. By turning a number of water heaters on or off, or by dynamically increasing or decreasing the current to those water heaters, the natural variations of supply and demand can be managed more effectively at the grid level. It is s belief that as long as the hot water needs of a household are met, water heaters can effectively provide this type of service to the grid. Successful execution of this type of dynamic control strategy can reduce the wholesale cost of energy or cause it to be a revenue producer. Integration with renewable energy Steele-Waseca Cooperative Electric, based in Owatonna, Minn., has packaged its kw community solar project with ETS water heating. A member can purchase a 410-watt solar panel for $170 when they join the ETS water heating program. Contact information Jeff Haase, strategic energy and efficiency program representative jhaase@grenergy.com Demand/Trans. Type/Method Energy Cost Other Costs Total Cost Uncontrolled $256 $50 - $200 $306 - $456 Grid-Interactive LMP Optimized $108 0 $108 Grid-Interactive with Regulation ($80) 0 ($80) This is an estimate of potential market costs of a gridinteractive water heater vs. an estimate of market costs for a controlled water heater Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

77 Electric vehicles As a cooperative, is motivated by listening to and providing services for its member-owners and their consumers. So when leaders noticed a growing interest in plug-in electric vehicles (PEVs), they decided to explore the technology and our potential role in that market. What they discovered after s initial research efforts is the important role PEVs will play in increasing energy security, improving fuel economy, lowering consumers overall fuel costs and reducing emissions. also believes that electric utilities play an intrinsic role in consumers consideration of PEVs as a personal transportation option. Fleet electrification may also prove beneficial for business and industry. Electric vehicles play an important role in utility community storage efforts. Community storage refers to utility programs which aggregate electric storage resources available throughout the community, such as electric vehicles and water heaters, to improve the efficiency of electric energy services for consumers. Community storage programs offer the industry the practical steps to rapidly increase the amount of energy storage available. continues to look at ways to make it easier for consumers to drive electric vehicles and currently offers rebates for residential charging stations that encourage off-peak or time-of-use vehicle charging. This strategy enables consumers to use more electricity during night-time hours when prices are typically lower and when the electricity is frequently produced from the region s abundant wind resources. Revolt SM takes renewables on the road is supporting the advancement of electric vehicles by embracing early adopters. Research showed that electric vehicle drivers were motivated primarily by the cars reduced environmental impact. That inspired Revolt. It is the first program of its kind in the world, allowing cooperative members to fuel their vehicles with wind energy at no additional cost. Renewable resources represent a growing portion of s power mix, and the Revolt program provides a more direct connection between wind energy and the electric vehicle driver. To participate in Revolt, a cooperative member must own, purchase or lease a PEV or plug-in hybrid electric vehicle and register with their cooperative. Standard or off-peak rates still apply for the electricity used to charge them. This program extends to members who already own or lease a PEV and members who purchase or lease one by Dec. 31, Powering what s possible

78 It s important to listen to a variety of stakeholders regarding this effort. participates in Drive Electric Minnesota, a coalition of groups that work collaboratively to bring electric vehicles and plug-in charging infrastructure here. also conducted a summit in 2015 to learn more about PEVs from nonprofits, government and environmental groups, subject matters experts, electric engineers as well as PEV owners. held training on PEV charging and infrastructure for member co-ops as well. As part of its effort to educate consumers on PEVs, and Revolt sponsored the first all-electric display at the Twin Cities Auto Show in The Electric Room hosted about a dozen electric vehicles from different manufacturers to help showcase and explain what separates them from hybrids and other types of cars. It was also an opportunity to dispel misconceptions consumers may have and show that, for a lot of people, an electric vehicle suits their everyday driving needs. Great River Energy s sponsorship of this room continued in 2017 with the 44th Twin Cities Auto Show, where the Chevrolet Bolt made its Midwest debut. and its member cooperatives will continue making an effort to increase PEV market stimulation as well as go further down the paths of stakeholder engagement, research, demonstration, infrastructure pilots and partnerships. leaders believe they can provide utility leadership in educating members and promoting PEVs as a realistic transportation option. Contact information David Ranallo, leader, member services and marketing, and Revolt program manager dranallo@grenergy.com Gary Connett, director of member services gconnett@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

79 Energy Wise MN home Background and its 28 member cooperatives are committed to promoting energy efficiency, reducing environmental impact and educating member-consumers and communities on ways to use electricity wisely. A wide assortment of rebates and incentives are offered to help home and business owners become more energy efficient. believes that with the right information and opportunities, member-owners can maximize the value of electricity without sacrificing their lifestyle or a single degree of comfort. is now thinking beyond members participating in one program or taking advantage of a few rebates but living in an entire Energy Wise MN home. Situation and strategy want to continue educating memberconsumers that electricity is a smart choice. The current market has created an opportunity for increased homebuilder activity on a national and local level, so it is important to inform members about the benefits of electricity-based applications for the homes they reside in now and the ones they may purchase or build in the future. The approach is to create a bundle of smart-home options thermostats, LED lighting, electric thermal storage water heaters, air source heat pumps, electric vehicle service equipment, community solar, among others to make being energy efficient easier for homebuilders. This bundle, or Energy Wise MN home, offers consumer appeal due to its green energy and high-tech components. There are different paths to different audiences in this strategy. s approach includes educating builders on why building an Energy Wise MN is now a viable option through bundled program rebates and incentives as well as why this type of home would give them a distinct advantage in the market place. Builders are looking for a contribution to construction. Great River Energy also needs to educate consumers on why they should specify Energy Wise MN when buying or building a new house and how it delivers a more comfortable, economical and sustainable living experience. Goals s short-term goals include creating consumer-facing marketing and tools for cultivating relationships with builders as well as some of Great River Energy s member-owner cooperatives having a presence in 2016 s and this year s Fall Parade of Homes event, presented by the Builders Association of the Twin Cities (BATC). Homes included in the service territories of member cooperatives Connexus Energy, Dakota Electric Association, Minnesota Valley Electric Cooperative and Wright-Hennepin Cooperative Electric Association are on Powering what s possible

80 display for this event so that current and future homeowners and homebuilders could see these Energy Wise MN programs in use. Other cooperatives not in the BATC territory can apply these tools to model homes or existing homes in their territories. Long-term goals include developing enhanced relationships with builders and other key audiences. There may also be opportunities to blend in renewable attributes to the concept of a near net-zero home option in the future as well as other automated technological advancements made possible through the use of electricity. Essentially, is developing a contribution to the construction process for members that they can offer their builders that will bundle beneficial electrification technologies with enhanced rebates for new homes. Great River Energy will create and provide marketing and sales tools for builder meetings and program growth strategies. Contact information David Ranallo, leader, member services and marketing dranallo@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

81 Geographic Information Systems (GIS) Overview A geographic information system or geographical information system (GIS) is a combination of hardware and software platforms designed to capture, store, manipulate, analyze, manage and present all types of spatial or geographical data. How we use it today Virtually every department in currently uses some facet of GIS. We developed a standard webbased application for office employees to access GIS information from any facility. We also have both cloud based and mobile applications developed for viewing and capturing information real time from the field. These applications are tied to almost every other business system at and provide the foundation for the development of several targeted GIS solutions. Outlined below are few examples of GIS solutions currently being used at : Transmission assets uses GIS to keep track of vegetation management. Status updates on clearing work come in from the field real-time and reports and maps can then be generated from this data to keep the foresters up to date on all vegetation clearing efforts. Land Rights agents use GIS for site and route acquisition. Using GIS data on a mobile device, agents can see all of the parcel data in conjunction with the proposed route and any alternative routes. They can meet with landowners to discuss and pinpoint where the easements will be located on their property and make any adjustments to the route needed from the field device. Agents can also track the status of easement acquisitions and permitting using GIS. A GIS dashboard and set of tools was developed for System Operations. This included redesigning Great River Energy s system one-line which is now tied and driven completely by GIS data. Three widgets were developed for the web viewer that allow the operators to view the locations of all service vehicles on the The GIS standard web viewer contains all of the functionality of our enterprise GIS system and allows the user to zoom into and out of key assets and locations and get information about the assets from other connected business systems as well as overlay additional layers of spatial information. Powering what s possible

82 map using data from our AVL system. They can view live weather and lightning information on a map and EMS predicted faults by capturing data from the SCADA system and using that data to trace downstream a give distance and placing a dot on the line to mark the possible location of the fault. Field crews are using the GIS application on mobile devices for navigation and situational awareness. Combined with data from s asset management system, this mobile GIS application becomes a very powerful tools in storm restoration efforts. It is also a replacement for a paper map book which is outdated the day you print it. Finance uses GIS to help with property tax calculations. All of the projects outlined were a part of s first enterprise GIS road map designed to spatially enable all of s business systems. There are several more examples of uses and plans for future development of GIS at Great River Energy contained in GIS Road Map 2. How we ll use it in the future In the future, employees will be able create their own maps from GIS data and their department specific data to visualize and preform analyses. The possible uses for GIS solutions are endless. Here are a few possibilities in Road Map 2: Provide tools and dataset to manage transmission asset projects from planning to close out. This will allow all employees and contractors that are working on these projects to collaborate with each other using an easy to use visual tool. We are looking to see where GIS can play a role in the development of future grid projects. Create ties to AMI and the meter data mart. employees will have the ability to visualize and preform analyses on meter data from these systems. GIS could show visually where the load is on the grid and with ties to DRMS; Great River Energy could make decisions on where to control the load and also see visually if it was controlled or not by changing the color of the controlled meters in the map. Developing GIS dataset and tools for the Transmission Construction and Maintenance Department which will include work order management, inspection tools, time reporting and status updates from mobile devices. This will help get into field force automation and streamline several processes which would result in considerable cost savings. In System Operations, GIS may become the front end of the EMS and SCADA system. Operators would use GIS to perform their day-to-day work rather than the native software that comes with these two systems. These are a few of the proposed uses for GIS in the future there are more outlined in Road Map 2. Overall, the future of GIS at will put tools and data into the hands of the end users allowing them to visualize, maintain and preform analyses on data they are charged with maintaining. Resources ESRI.com Arcgis.com Road Map 1 Road Map 2 Contact information Jeff Grussing, leader, GIS development jgrussing@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 7/5/2016

83 DryFining Fuel enhancement process The DryFining fuel enhancement process developed by refines or beneficiates lignite coal through a thermal drying and mechanical segregation process. Drying utilizes residual or waste heat to raise the heating value of the coal per pound. The refining component segregates the lignite stream and removes the higher density compounds that contain higher levels of sulfur and mercury. has proven results at its Coal Creek Station, a 1,180-megawatt lignite coal-fired plant in North Dakota, which has used DryFine lignite since Through the DryFining fuel enhancement process, fuel quality is upgraded to its original design specifications. Fuel moisture is reduced from 38 to 28 percent, and higher heating value is increased from 6,200 to 7,100 BTU. This lignite could be dried further. However, returning the heating value to the original boiler design is the best operating condition for this particular plant. DryFining drives off fuel moisture before combustion, reducing the total volume of flue gases throughout the entire balance of plant and increasing overall plant efficiency while reducing operating cost. Increased efficiency Over 25 years of operation, the quality of the coal delivered to Coal Creek Station had deteriorated from the 6,800 Btu/lb design specification to about 6,200 Btu/lb, and the moisture in the coal had increased to about 38 percent by weight. As a result, more fuel was required for the plant to achieve its nameplate capacity, which increased the volume of flue gas and overworked the induced draft fans. Plus, processing the additional coal required all of the plant s pulverizers to operate at full capacity, leaving little opportunity for regular maintenance. It took up to 50 percent more hot air from the primary air fans to dry the higher moisture coal and move it along the conveyors to the burners. This also limited the amount of available air for burner optimization for NOx control. Increases overall plant efficiency by ~4% Reduces emissions: Sulfur dioxide >40% Mercury up to 40% Nitrogen oxide >20% Carbon dioxide ~4% Saves more than $20 million in annual O&M Powering what s possible

84 Station east of Jamestown, N.D. That product is shipped over 150 miles in enclosed rail cars to prevent moisture from reentering the coal. At full capacity, Spiritwood Station uses approximately 610,000 tons of DryFine coal annually. For more information on DryFine Technology commercialization Business Contact Sandra Broekema Cell About dries and refines additional quantities of lignite at its Coal Creek Station near Underwood, N.D., and then transports that DryFine coal to its Spiritwood Technical Contact Charlie Bullinger Cell DryFining at Coal Creek Station 10% less DryFine Feedstock B O I L E R Reduced fuel moisture lowers: flue gas volume flue gas velocities exit gas temperature power for mills power for FD & ID fans duct erosion & maintenance ESP or Baghouse Less: SO 2 40% CO 2 4% NO x 20% Hg 40% Ash 2.5% Stack SO 2 Scrubber More MW/ton INCREASED EFFICIENCY Less flue gas Lower velocities Less evaporation Lower stack temp Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 7/5/2016

85 GRID RESILIENCE

86 Cybersecurity Overview A safe, stable and resilient cyberspace and infrastructure is critical to protecting the reliability and security of the electric power system. Since the North American Electric Reliability Corporation (NERC) introduced cybersecurity standards in 2005, has continued its commitment to compliance and taken proactive measures to safeguard from cyber threats and vulnerabilities. By partnering with industry, government and other related organizations in a collaborative effort, is in a better position to prevent, protect against and respond to cyber incidents in a constructive manner. Current state has implemented a standards-based security model and policy framework to ensure compliance with NERC standards. Meeting NERC standards has always been a part of s daily operations, and the organization continues to devote resources to compliance as the standards evolve. s management regularly reports on cybersecurity issues and risks to its board of directors. The organization conducts periodic cyber intrusion scenario drills, which allows to test emergency response plans and communication protocols. Collaboration with others participates in the sharing of actionable intelligence around cybersecurity, including: Electricity Subsector Coordinating Council (ESCC) The ESCC is made up of industry CEOs who set strategies for addressing cybersecurity issues. The council works with US Government officials to coordinate and align utility efforts toward common national security, resilience and preparedness related goals. Electricity Information Sharing and Analysis Center (E-ISAC) The E-ISAC acts as an information clearing house and coordinates information sharing about cyber incidents for utilities. Department of Energy Cyber Risk Information Sharing Program (CRISP) CRISP enables near real-time exchange of threat and incident data. volunteered in 2014 to participate in the pilot project originally developed by the U.S. Department of Energy to protect highly sensitive government networks. Through the program, and others benefit by sharing and obtaining valuable cyber threat data, analyzing that data and receiving mitigation measures. Great River Energy was the first cooperative involved in the pilot project, which has now been extended to one of its member cooperatives, Minnesota Valley Electric Cooperative. continues to explore options to bring other members into the program. Powering what s possible

87 NERC GridEx III The two-day exercise, was designed to enhance the coordination of cyber and physical security resources and practices within the industry, as well as communication with government partners and other stakeholders, including those in Canada and Mexico. The biennial exercise gave participants, like Great River Energy, the opportunity to self-assess their emergency response and recovery plans through a simulated exercise that took place across North America. Cooperative collaboration opportunities Many cooperative collaboration opportunities exist through organizations like the Cooperative Research Network (CRN), Electric Power Research Institute (EPRI) and the National Rural Electric Cooperative Association (NRECA). Other opportunities to consider include cooperative best practice visits and participating in pilot projects. hosted a one-day security summit for its member cooperatives to showcase best practices and provide an environment to facilitate information sharing. The idea took shape at the suggestion of members who underlined the importance of security issues facing all utility cooperatives. The agenda included member cooperative speakers, speakers, and external security experts. The NERC Grid Security Conference (GridSecCon) will be held in St. Paul, Minn., Oct.17-20, The conference brings together cybersecurity and physical security experts from industry and government to share emerging security trends, policy advancements, and lessons learned related to the electricity sub-sector. Employee accountability Cybersecurity is not just about technology. Employee accountability for maintaining and improving security is critical at. Much like safety, security is everyone s responsibility. Every employee has responsibilities under the NERC compliance program. Through training and education, Great River Energy has created a culture of security and risk management. Employees understand that security is everyone s responsibility. has established a Security Policy Statement that guides employee actions. It reads: recognizes the value of its physical, cyber and information assets in the ongoing operation and success of its business and the potential for significant harmful consequences should these assets be compromised or destroyed. As such, Great River Energy is committed to the establishment and implementation of controls to protect its assets that meet or exceed industry standards and practices. The protection and security of s assets is the responsibility of s employees, contractors and agents. Great River Energy will enforce compliance with its security standards; violations may result in disciplinary actions, termination of employment, legal prosecution and/or other actions as warranted. Helping to shape the future partnered with Thomas Edison State University, Utilities Telecom Council and other top utility cybersecurity professionals to design a master s degree program for students wanting to specialize in utility cybersecurity. The program, called the Graduate Certificate in Cybersecurity Critical Infrastructure, blends both information technology and operational technology, and focuses specifically on critical infrastructure sectors such as energy, water, gas and transportation. Contact Information Marc Child, information security program manager mchild@grenergy.com Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

88 Aging infrastructure assessment tool transmission leaders are researching how to best evaluate breakers, meters, remote terminal unit (RTU) and electro-mechanical relays to identify which ones are in need of being replaced and how to go systematically through the system to rank that equipment. Leaders are looking at a focused plan and the development of a prioritization tool that would dovetail into the budget cycle so that older equipment, which is prone to fail, would be replaced before any system impacts occur. Of note, older equipment often continues to perform the tasks it needs to. This process and tool would analyze the health of the system and the individual components, based on age, condition criticality and obsolescence. The tool would help leaders understand which equipment to focus on and which need help. What was doing before creating the assessment tool? Before deciding to come up with an assessment tool, many of the projects were replaced when they failed or when there was a good case that they needed to be updated. It was up to individual groups to make those business cases. Field services, system operations, relays and transmission line crews had a list of projects that they wanted to see funded. They d bring those projects forth during the capital budget prioritization process, and leaders would decide which projects should be funded. How will the assessment tool change the way does business? Projects will be funded based on best business cases and if they will help overall. Leaders are looking at how to assess these projects together. Oftentimes it s comparing apples to oranges. For example, a relay project doesn t look the same as a line project nor do the costs align or are they similar. What leaders are trying to do is come up with a uniform way for these projects to be standardized and then ranked, so that the best projects really do come out on top and receive appropriate funding during the prioritization process. Which projects will receive funding? Leaders are looking at certain criteria to determine which projects should be funded. Most of these projects replace something already out on the system. They might be smarter but essentially the equipment will perform the same basic function. Transmission leaders are creating a standard evaluation that can be replicated for these very different projects, and so can determine how to rank them. The process is expected to be fully initiated by Contact information John Setala, manager, project management and engineering services, transmission jsetala@grenergy.com Kerry Livingston, principal engineer, transmission klivingston@grenergy.com Powering what s possible

89 Energy Sector Climate Resilience Partnership Overview In early 2014, the Obama Administration released the first-ever Quadrennial Energy Review, which examines how to modernize the nation s energy infrastructure. As part of the initial stage, the Energy Sector Climate Resilience Partnership was formed, with Great River Energy, the Department of Energy and 16 utilities as partners. CEOs from the 17 utilities that make up the partnership convened in April 2015 at the Department of Energy. The participating utilities represent a broad array of investor-owned, federal, municipal and cooperative utilities, including and Hoosier Energy. s President and CEO David Saggau attended the meeting. The Partnership for Energy Sector Climate Resilience is an initiative to enhance U.S. energy security by improving the resilience of energy infrastructure to extreme weather and climate change impacts. The goal is to accelerate investment in technologies, practices, and policies that will enable a resilient 21st century energy system. Under this Partnership, owners and operators of energy assets will develop and pursue strategies to reduce climate and weather-related vulnerabilities. Collectively, these utility partners and the Department of Energy (DOE) will develop resources to facilitate risk-based decision making and pursue cost-effective strategies for a more climate-resilient U.S. energy infrastructure. This partnership is an opportunity for to learn and share best practices as it relates to extreme weather, climate change and energy security. In addition, this partnership will help enhance its response to major events and gain knowledge on planning and transmission facility design. Transmission is a long-term investment and historical weather patterns may not be a good indicator of what to expect in the future. Great River Energy needs to plan and design its systems to meet the new challenges. submitted this report to the Department of Energy as part of the Energy Sector Climate Resilience Partnership in February Initial stage In the initial stage, submitted a report in February 2016 called Assessments of Transmission Assets in Response to Climate Change. The report looked specifically at s transmission and generation portfolio to determine how climate change might impact reliable service in the future. The report gave an opportunity to engage with others in the industry to better understand the vulnerabilities climate change could impose on the electric system and to find solutions. shared key findings including: during the course of this century, climate change is expected to increasingly impact the Northern Great Plains and Powering what s possible

90 Midwest region s energy infrastructure. Great River Energy s transmission system and generation facilities are forecasted to see a rise in flooding events, increased ice storms and warmer summers with prolonged heat waves. Since weather is one of the greatest risks Great River Energy faces in the generation and reliable delivery to its 28 member cooperatives, risks associated with climate change will continue to be assessed and mitigated. The other utility partners also submitted their reports for review by the DOE. Second stage along with the other 18 utilities of the Partnership for Energy Sector Climate Resilience submitted their mitigation plans for Climate Resiliency in November. s approach for addressing climate change risk for the near-term period will focus on the prevention and recovery aspects of resiliency and evaluated for their impact on the reliability of electric system. Climate risks to generation have been reduced through proactive projects at Coal Creek Station and winterization measures at the combustion turbine facilities. annually reviews its Transmission System Restoration Response Plan and evaluates the plan s performance against the previous restoration events. The evaluation currently does not contain a long-term view for risks associated with climate change. Future stages Partnership met in January of 2017 to discuss its mitigation plans and the future of the partnership. Based on the work plan priorities the results point to the following top three topics: 1. Case studies and stories Experiences (positive and negative) engaging with internal departments, customers, regulators, communities, suppliers, other stakeholders, etc. Regional impacts and resilience strategies Best practices (e.g., developing climate scenarios, screening resilience strategies, evaluating investments) 2. Inventory of benefits that could be considered in a cost-benefit analysis of resilience investments 3. Outreach to regulators on various topics (e.g., standards, benefits of resilience investments, guidance, success stories) Resources Assessments of Transmission Assets in Response to Climate Change Contact information Gordon Pietsch, director, transmission planning and operations gpietsch@grenergy.com Michael Brytowski, standards specialist mbrytowski@grenergy.com Partners forming the Partnership for Energy Sector Climate Resilience Consolidated Edison of New York Department of Energy Dominion Virginia Power Dominion Entergy Corporation Exelon Corporation Hoosier Energy Iberdrola USA National Grid New York Power Authority Pepco Holdings, Inc. Pacific Gas and Electric Public Service Electric and Gas Sacramento Municipal Utility District San Diego Gas and Electric Seattle City Light Southern California Edison Tennessee Valley Authority Xcel Energy Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

91 GridBallast research project and Connexus Energy are taking part in a pilot research project funded by the Department of Energy (DOE) focused on grid reliability. The DOE will invest $1.3 million in the GridBallast project to create low-cost, demand-side management tools for improving the resiliency of the country s electric grid and to better control peak demand. The effort is led by the National Rural Electric Cooperative Association (NRECA). NRECA and its research partners plan to create two devices: a water heater controller and a smart circuit breaker capable of controlling plug-in appliances. The project team will develop an algorithm to continuously monitor the voltage and frequency of electricity feeds directly at the plug and automatically respond with rapid, low-scale adjustments. The goal of the GridBallast project is to make load management an inherent part of grid operations rather than a central control action, which is currently how demand-response programs are managed. Unlike traditional demand-response programs that manage devices from a central location, the new controllers will function autonomously, monitoring electrical anomalies in the field and making rapid, low-scale adjustments. Averting the need for communications infrastructure, GridBallast could reduce load control costs by at least 50 percent, according to project s leaders. The devices will be deployed at homes and businesses in Connexus Energy s service territory while Great River Energy will support the research and share those findings with its other cooperatives. Researchers will focus on defining control algorithms that will allow GridBallast devices to work together without a network. The research team assembled by NRECA includes experts from Carnegie Mellon University, Eaton and SparkMeter. Eaton will develop the water-heater controller. SparkMeter will build a smart circuit controller. NRECA and co-ops will pilot the devices on their systems in partnership with cooperatives. NRECA recently drafted a Technology To Market (T2M) document that outlines a strategy to move the technology as tested in the GridBallast program to a sustainable commercialized product. An Industry Advisory Board has been formed that includes representatives from participating cooperatives and NRECA leadership to provide guidance and support for the T2M portion of the project. By participating in this project, hopes to further its knowledge on ways to help stabilize the grid as it undergoes a period of transition. This project is an opportunity to better understand the impact renewable energy resources will have on s system and how the cooperative can deploy autonomous intelligent technologies to respond rapidly, without human intervention, to maintain the power quality and reliability its members expect. The GridBallast project will take place over a two-and-a-half year period with field demonstrations beginning in July 2018 and concluding in April Contact information Gary Connett, director, member services gconnett@grenergy.com Tom Guttormson, principal technology engineer Connexus Energy tom.guttormson@connexusenergy.com Powering what s possible

92 ICE pilot project results Context As interest in new generation sources increases, costs for wind and solar power decrease and battery storage becomes more feasible, adding distributed energy resources (DER) with battery storage to the electric system continues to become a more viable way to address reliability issues on the electric system. worked on a pilot project in 2016 to study the differences between the benefits of investments in transmission assets versus distributed generation and storage as a means for improving system reliability. In this pilot project partnered with member cooperative East Central Energy to develop further understanding of the members being served and if investments in non-wire alternatives (distributed generation and storage systems) would be more prudent than investments in s transmission assets as a means to improve system reliability. The pilot project served as a reference point for cost comparisons when considering replacement of transmission lines or potential benefits of distributed energy resource additions to the transmission system or to member distribution systems. The pilot project idea emerged from s involvement in the Department of Energy s Energy Sector Climate Resilience Partnership, where participating utilities were introduced to a new Interruption Cost Estimator (ICE) tool. The ICE tool helps estimate the cost of service interruptions and/or the benefits associated with reliability improvements. saw an opportunity to leverage this tool to assist in planning efforts and identify cost-effective non-wire alternative investments. Description partnered with member cooperative East Central Energy to gather reliability data, which accounted for a 10-year average in industry standard metrics system average interruption duration index (SAIDI), system average interruption frequency index (SAIFI), and customer average interruption duration (CAIDI). Data for reliability at individual distribution substations and commercial and residential usage also were used. From those inputs, the ICE tool could determine the cost of outages and potential outage reduction savings by investing in either non-wire alternatives or traditional transmission infrastructure. Using this information, customer socioeconomic data and time of day/year data, the total annual cost of sustained interruptions was calculated for each substation. There were 30 East Central Energy substations included in the analysis. Why it mattered has been committed to serving its members with a high standard of reliability since it was formed and has consistently made reliability improvements when needed. This study proved that those investments have created a highly reliable system. The results showed that deploying distributed energy resources as simply a way to improve reliability did not make sense for a number of reasons. First, s system is highly reliable. Interruptions sustained and momentary aren t so prolonged as to warrant extensive investment. Second, neither the load nor customer base is dense enough in any part of s service territory to create enough of an economic hardship that would drive the value proposition of non-wire alternatives such that investments would be worthwhile solely for reliability purposes. The study considered two types of DER technologies in the study battery storage and diesel generators. Solar was not considered in the cost of DER implementation due to the fact that reliability was the driving aspect of the study. If Great River Energy is looking to increase reliability with DERs, then the variable, non-dispatchable nature of solar wouldn t increase reliability without accompanying storage, which would increase the costs to a level that would preclude consideration. The analysis showed that the pay back period for adding diesel generators to the system would be 59 years, and for a battery system the payback (only in terms of reliability) would be 208 years. The cash flows on an annual basis represented the ICE tool output for the value of a 40% improvement in SAIDI. Simply put, to install DER for reliability does not make sense for at this time. Several assumptions were made throughout the study to give a best case scenario look at the non-wire alternatives, and to attempt to stress-test the numbers to see if a positive NPV would be possible. Powering what s possible

93 Ultimately, the annual benefits did not accrue to enough of a cash flow to offset initial investments and annual costs. The average battery project cost would have been $4.4 million, and average diesel project cost at $1.2 million. The investments were still borderline with a total elimination of interruptions, which would not be a realistic assumption. There is potential for battery storage to become economic, but only if additional value propositions outside of reliability were stacked such that the sum of the values would create annual cash flows to offset the still large initial investments. Using DERs would not be a cost-effective alternative to transmission system upgrades to improve the reliability of the system. can continue to use the ICE tool in the future as members want to see the cost of an outage and to use it in other areas. The cost of battery storage is declining; the study used an aggressively optimistic cost estimate for installed costs of battery storage in For the economics to improve for battery investments, other benefits such as ancillary services payments from the Midcontinent Independent System Operator (MISO) would need to be included, as well as additional payments for a storage unit as a generator, as load, and as a transmission asset. Stacking payments could result in a cost-effective investment in battery storage technology. The MISO market is still lacking a defined construct for payments to storage assets, and will need to re-examine the assumptions of this project when a more defined market construct is in place. Currently, there are no state or federal subsidies on batteries that might help their value proposition. Goals and objectives The objectives of the pilot project included: 1. Identify the status and availability of the data that indicates the condition of s transmission assets that serve a co-op. 2. Develop a long term health/risk index for transmission assets that serve that co-op s load (another project is addressing health/risk for all transmission assets), predicated upon: Asset condition Historical reliability indices Customers being served Criticality to operations 3. Utilize the ICE tool to compare the cost benefits for improved reliability/resilience of investment in non-wire alternatives versus investment in transmission assets. A longer term goal would be to create a system that prioritizes existing transmission assets for replacement or upgrade in the capital projects process. 4. Inform the future grid steering committee, member managers, senior staff and board members on the study results, and provide recommendations to expand the analysis to other interested cooperatives. 5. This project will additionally serve to inform the longer term transmission and resource planning processes. The project may also serve as a reference for methods to identify and compare the costs of transmission and distribution facility replacements to the cost of implementing targeted DER. Project start date: May 27, 2016 Project end date: Nov. 17, 2016 Participating Organizations East Central Energy Department of Energy (provided tool used) Contact information Gordon Pietsch, director, transmission planning and operations gpietsch@grenergy.com Michael Brytowski, standards specialist mbrytowski@grenergy.com Zac Ruzycki, senior resource strategist zruzycki@grenergy.com Elm Creek Boulevard Maple Grove, Minnesota greatriverenergy.com 1/17/2017

94 TODAY S ENERGY MARKET

95 Portfolio evolution is crafting a dependable and economical portfolio through new resources and using existing generation in new ways. A rise of dispersed and variable renewable generation resources primarily wind energy has had major market effects that are shaking up the economics of conventional power plants. Ten years ago, the Midwest energy market included 1,000 megawatts of wind generation. Today, there are 15,000 megawatts and more development is expected. Using existing resources in new ways Because there is more energy available, market prices have fallen. And, since the output of renewable resources swings up and down depending on the wind, there is a growing need for generation resources that can adjust their output. The roles of baseload and renewables have changed dramatically. Coal and natural gas power plants are now called on to be the steadying force in the market. To remain competitive in today s power market, Great River Energy adapted Coal Creek Station to the new market forces. Operational changes and minor modifications will enable the 1,146-megawatt plant to ramp down to less than 300 megawatts. More wind on the way is taking advantage of favorable pricing of renewable resource and market trends to strategically expand its renewable portfolio. The 300-megawatt Emmons-Logan project is scheduled to begin providing power to s members in The project will bring s renewable energy capacity to more than 1,000 megawatts. Renewable 14% Hydro 8% Capacity Fuel oil 3% Natural gas 36% Coal 39% Natural gas 3% Renewable 12% Hydro 8% Energy Market 11% Coal 66% 2016 capacity sources by fuel type 2016 energy sources by fuel type Powering what s possible

96 Reducing reliance on coal After serving s members for more than 50 years, the Stanton Station power plant will be retired in Retiring the plant was in the best interest of Great River Energy s member-owner cooperatives. The plant s closure will reduce s costs while also reducing the cooperative s carbon dioxide emissions and reliance on coal. The retirement of Stanton Station follows s 2015 exit from a contract for half the output of a Wisconsin coal plant. Solar rising Following its 2015 statewide buildout of solar arrays, applied its newfound knowledge to develop the largest cooperative-owned solar installation in Minnesota. and Wright-Hennepin Cooperative Electric Association collaborated on the Dickinson Solar Project, a 2.25-megawatt installation consisting of 8,352 panels on 13-acres in Buffalo, Minn. s board of directors adopted a resolution in 2013 that includes the following provisions: Address potential base load stranded costs through the accelerated depreciation of Coal Creek Station and Stanton Station over the next fifteen (15) years, beginning in July 2013 Manage carbon dioxide emissions to 2005 levels or lower Implement cost effective opportunities to reduce greenhouse gas emissions now and develop and implement a plan to substantially reduce s dependence on coal by 2028 Meet any future growth with conservation, energy efficiency, renewable energy, natural gas and market purchases Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017

97 Environmentally beneficial electrification Technological progress is making appliances and other electric devices ever more efficient. Power plant retirements and renewable development will continue to reduce the environmental effect of the electric system. These two converging trends are making one thing very clear: electricity is a smart choice. As the electric system continues to become cleaner and more efficient, there is growing support for using electricity in new ways. continues to offer its Revolt SM program, which allows electric vehicle drivers to charge their cars entirely with wind energy at no added cost. Its memberowner cooperatives offer a catalog of programs that incentivize energy efficiency retrofits ranging from LED lighting to ground-source heat pumps. In partnership with its member-owner cooperatives, Great River Energy also works to attract economic development through financial support and unique energy solutions. Cooperatives are also leading the charge on community energy storage, which employs common household appliances to provide critical services the electric grid needs. Benefits for co-ops Electrification provides cooperatives with relief from financial pressure due to declining electric sales. It also builds member engagement by helping home- and businessowners save money and improve efficiency. Powering what s possible

98 Regional transmission leadership The electric industry is in the midst of an evolution that began more than 20 years ago. In the first 10 years, gradual but radical change in the transmission industry was driven by the federal government. Modernizing the grid became a national priority with concerns focusing on reliability, national security, the environment and the need for more efficient markets to keep electricity affordable and serve customers better. and its members stayed ahead of the curve as: A founder and leader of the CapX2020 grid expansion Early members and market participants in the Midcontinent Independent System Operator (MISO) Leading the CapX2020 grid expansion was a founder and leader of CapX2020, a joint initiative of 11 investor-owned utilities, generation and transmission cooperatives, and municipal joint action agencies. CapX2020 is upgrading and expanding the electric transmission grid in Minnesota, North Dakota, South Dakota and Wisconsin to ensure continued reliable and affordable service; meet state and regional energy policy goals; and support a diverse generation mix, including renewable energy. A core objective of CapX2020 is collaboration in the planning and execution of projects. A University of Minnesota Humphrey School of Public Affairs report in 2016 said the CapX2020 organization ushered in a new era of multi-state transmission planning and served as an example that other utilities can and should emulate as they cooperate on regional projects. There are five major CapX2020 projects that comprise a $2 billion investment in 800 miles of 230-kV and 345-kV transmission lines. It is the largest development of new transmission in the Midwest in nearly 40 years. Prepared for today s transmission environment is prepared for today s competitive transmission environment. was accepted as a MISO-qualified transmission developer in late 2014, which allows the cooperative to compete for the right to build certain regional transmission projects. MISO created the qualified developer status in January 2014 in response to the Federal Energy Regulatory Commission s (FERC) Order 1000 that eliminated the right of first refusal. Having the right of first refusal allowed utilities the right to develop new transmission facilities Powering what s possible

99 more than 100 kv that connect to substations the utility owns and, in FERC s opinion, prevented competition in the market for transmission expansion projects. Although Order 1000 eliminated the right of first refusal on the federal level, a number of states exercised their authority to address the issue at the state level. Minnesota, North Dakota and South Dakota each passed state laws retaining the right of first refusal (ROFR). Great River Energy, in collaboration with CapX2020, advocated for the Minnesota ROFR bill in Also, is heavily involved in inter-utility and MISO transmission planning activities, working actively to help ensure appropriate regional-scale projects are approved by MISO when they would benefit its members. Continued grid evolution While transmission continues to evolve, exponential change is expected over the next 15 to 20 years on the distribution side of the grid and in retail markets. This time, change is not being driven by government but instead by customers. Key drivers include: High expectations of today s consumers Concerns about carbon and other emissions Rapidly developing technologies for consumerization of energy Elm Creek Boulevard Maple Grove, MN greatriverenergy.com 3/28/2017