1 STATE OF GEORGIA 2 3 BEFORE THE 4 GEORGIA PUBLIC SERVICE COMMISSION 5 6 7In Re: 8Georgia Power Company’s 92019 Integrated Resource Plan and 10Application for Certification of Capacity 11From Plant Scherer Unit 3 and Plant 12Goat Rock Units 9-12 and Application 13for Decertification of Plant Hammond 14Units 1-4, Plant McIntosh Unit 1, Plant 15Langdale Units 5-6, Plant Riverview 16Units 1-2, and Plant Estatoah Unit 1 17 18 19Georgia Power Company’s 20Application for the Certification, 21Decertification and Amended 22Demand Side Management Plan 23 24 ) ) ) ) ) ) ) ) ) ) ) ) ) Docket No. 42310 Docket No. 42311 25 26 DIRECT TESTIMONY OF JEFFREY R. GRUBB, NARIN SMITH, MICHAEL A. BUSH, AND JEFFREY B. WEATHERS March 14, 2019 DIRECT TESTIMONY OF JEFFREY R. GRUBB, NARIN SMITH, MICHAEL A. BUSH, AND JEFFREY B. WEATHERS IN SUPPORT OF GEORGIA POWER COMPANY’S 27 28 29 30 31 32 2019 INTEGRATED RESOURCE PLAN AND APPLICATION FOR CERTIFICATION OF CAPACITY FROM PLANT SCHERER UNIT 3 AND PLANT GOAT ROCK UNITS 9-12 AND APPLICATION FOR DECERTIFICATION OF PLANT HAMMOND UNITS 1-4, PLANT MCINTOSH UNIT 1, PLANT LANGDALE UNITS 5-6, PLANT RIVERVIEW UNITS 1-2, AND PLANT ESTATOAH UNIT 1 GPSC DOCKET NO. 42310 AND APPLICATION FOR THE CERTIFICATION, DECERTIFICATION AND AMENDED DEMAND SIDE MANAGEMENT PLAN GPSC DOCKET NO. 42311 I. INTRODUCTION 33Q. PLEASE STATE YOUR NAMES, TITLES AND BUSINESS ADDRESSES. 34A. My name is Jeffrey R. Grubb. I am the Director of Resource Planning for Georgia 35 Power Company (“Georgia Power” or the “Company”). My business address is 36 241 Ralph McGill Boulevard, N.E., Atlanta, Georgia 30308. 37 38A. My name is Narin Smith. I am the Director of Market Planning for Georgia 39 Power. My business address is 241 Ralph McGill Boulevard, N.E., Atlanta, 40 Georgia 30308. 1 2 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 2 of 59 41A. My name is Michael A. Bush. I am the Manager of Generation Planning and 42 Development for Southern Company Services, Inc. (“SCS”). My business address 43 is 600 North 18th Street, Birmingham, Alabama 35203. 44 45A. My name is Jeffrey B. Weathers. I am the Manager of Resource Planning for SCS. 46 My business address is 600 North 18th Street, Birmingham, Alabama 35203. 47 48Q. MR. GRUBB, PLEASE SUMMARIZE YOUR EDUCATION AND 49 PROFESSIONAL EXPERIENCE. 50A. I began my career with Georgia Power in 1992 as a cooperative education student 51 in Commercial and Industrial Marketing. I graduated from the Georgia Institute of 52 Technology in 1996 with a Bachelor of Science degree in Mechanical 53 Engineering. After joining the Company as a full-time employee in 1997, I 54 worked in various roles within Marketing until 2001 at which time I participated 55 in a Company developmental program where I gained experience in a wide range 56 of functional areas. During this period, I earned a Master of Business 57 Administration degree from Auburn University in 2000. 58 59 In 2003, I joined the Resource Policy and Planning organization at Georgia Power 60 where I served as a Project Manager through 2006. From 2007 through 2016, I 61 worked for SCS in various planning roles including SCS Forecasting Team 62 Leader (2007), SCS Fuels Planning Manager (2007-2011), and SCS Resource 63 Planning Project Manager (2011-2016) where I managed the team that supports 64 the development of the Southern Company System (“System”) Integrated 65 Resource Plan (“IRP”). In this role, I supported Georgia Power’s 2013 IRP 66 (Docket No. 36498) and 2016 IRP (Docket No. 40161). In 2016, I returned to 67 Georgia Power as Project Manager in Resource Policy and Planning where I 68 worked on the development of the IRP. Beginning in March 2018, I assumed my 69 current position of Director of Resource Policy and Planning for Georgia Power. 70 3 4 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 3 of 59 71Q. MR. GRUBB, HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE 72 GEORGIA PUBLIC SERVICE COMMISSION? 73A. Yes. I testified in Docket No. 41596, Georgia Power’s Application for the 74 Certification of the 2018/2019 REDI Utility Scale Power Purchase Agreements 75 (“PPAs”) and in Docket No. 41734, Georgia Power’s Application for the 76 Certification of the 2018/2019 REDI Utility Scale PPAs for the Commercial and 77 Industrial Program. 78 79Q. DR. SMITH, PLEASE SUMMARIZE YOUR EDUCATION AND 80 PROFESSIONAL EXPERIENCE. 81A. I graduated from Cukurova University in Adana, Turkey with a Bachelor of 82 Science in Economics and Auburn University with a Ph.D. in Economics and 83 fields in Econometrics, Industrial Organization, and Public Finance. I began my 84 career at Southern Company in 1999 as a System Planning Analyst in the 85 Generation and Energy Marketing organization. There, I modeled volatility in 86 commodity prices, analyzed risk in wholesale power contracts, and modeled 87 generation supply in the Southeast to help forecast marginal power prices. In 88 2001, I joined Georgia Power as Manager of Forecasting and Market Research 89 where I was responsible for the Company’s energy, revenue, and peak demand 90 forecasts. In that role, I supported the company’s 2004 IRP filing. 91 92 In the summer of 2004, I joined SCS’ Finance organization and held various roles 93 including Manager of Financial Modeling and Analysis, Manager of Long-Range 94 Financial Planning, Director of Corporate Analysis and Business Development, 95 and Director of Enterprise Risk Management. I also served as Assistant to 96 Southern Company’s Chief Financial Officer. In my various roles in the Finance 97 organization, I provided strategic and analytical support in the areas of capital 98 investment decisions, corporate mergers and acquisitions, and provided leadership 99 in governance, coordination, and execution of enterprise risk management and 100 business assurance activities at Southern Company. I also managed quantitative 5 6 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 4 of 59 101 risk modeling and analysis and risk control activities related to energy trading at 102 the Company’s trading floor. 103 104 I assumed my current position as Director of Market Planning in March of 2018. 105 In my current role, I am responsible for the Company’s energy, peak demand and 106 revenue forecasts along with economic analysis of demand side management and 107 marketing programs. 108 109Q. DR. SMITH, HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE 110 GEORGIA PUBLIC SERVICE COMMISSION? 111A. No. This is my first time testifying before the Georgia Public Service Commission 112 (“Commission”). 113 114Q. MR. BUSH, PLEASE SUMMARIZE YOUR EDUCATION AND 115 PROFESSIONAL EXPERIENCE. 116A. I began my career with Mississippi Power Company (“Mississippi Power”) in 117 1983 as a cooperative education student. I graduated from Auburn University with 118 a degree in Electrical Engineering. After working outside the Southern Company 119 for a few years I returned to work for Mississippi Power in 1990. From 1990 until 120 1995, I held various staff positions at which time I transferred to SCS in 121 Birmingham, Alabama to work in the wholesale marketing organization. 122 123 In 1996, I became a Term Trader and in 1999 I was appointed Manager of Energy 124 Trading. In 2003, I took the position of Director of Portfolio Management. After a 125 re-organization of the wholesale organization occurred in 2005 combining 126 Portfolio Management and Energy Trading, I took a leadership position in that 127 organization. In 2009, I moved to my current role as Manager of Generation 128 Planning and Development. My current responsibilities include providing 129 generation planning and development services to Southern Company’s retail 130 operating companies including Georgia Power. 7 8 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 5 of 59 131Q. MR. BUSH, HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE 132 GEORGIA PUBLIC SERVICE COMMISSION? 133A. Yes. I was a rebuttal witness in Georgia Power’s 2016 IRP in Docket No. 40161. 134 135Q. MR. WEATHERS, PLEASE SUMMARIZE YOUR EDUCATION AND 136 PROFESSIONAL EXPERIENCE. 137A. I graduated from Auburn University in 1996 with a Bachelor of Science in 138 Mechanical Engineering, and in 1998 with a Master’s in Business Administration 139 degree. I began my career at Southern Company in 1998 at Plant Farley and 140 joined SCS in 1999. Over the next seven years, I progressed through roles of 141 increasing 142 Management, and Southern Power Generation Development. I became the Energy 143 Analysis Manager in 2006 with responsibility for analyzing wholesale contracts, 144 trading, and pool transactions. In 2011, I became Manager of Financial and 145 Contract Services, with responsibility for the wholesale billing, settlement, and 146 analysis of the Intercompany Interchange Contract, the wholesale contracts of the 147 operating companies, and the Open Access Transmission Tariff. In December 148 2015, I moved into the role of Strategic Generation Planning Manager with 149 responsibility over energy budgeting, scenario planning and forecasting, and asset 150 valuations. In September 2016, I was named Resource Planning Manager and 151 assumed additional responsibilities related to the coordinated planning process. 152 My responsibilities now include integrated resource planning, energy budgeting, 153 evaluation of Requests for Proposals (“RFP”), reliability and reserve margin 154 analysis, scenario planning and forecasting, and production cost modeling and 155 analysis. responsibility in System Planning, Fleet Operations, Asset 156 157Q. MR. WEATHERS, HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE 158 GEORGIA PUBLIC SERVICE COMMISSION? 159A. Yes. I testified in Docket No. 39638, FCR-24, regarding the outage replacement 160 cost calculations for the 2013 outages at Plant Bowen, in Docket No. 41596, 9 10 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 6 of 59 161 Georgia Power’s Application for the Certification of the 2018/2019 REDI Utility 162 Scale PPAs, and in Docket No. 41734, Georgia Power’s Application for the 163 Certification of the 2018/2019 REDI Utility Scale PPAs for the Commercial and 164 Industrial Program. 165 166Q. WHAT IS THE IRP? 167A. The IRP is Georgia Power’s benchmark plan that contains the Company’s electric 168 demand and energy forecast for a 20-year period. The IRP contains the 169 Company’s plan for meeting the requirements shown in its forecast in an 170 economical and reliable manner and contains the Company’s analysis of all 171 capacity resource options, including both demand-side and supply-side options. In 172 addition, the IRP sets forth the Company’s assumptions and conclusions with 173 respect to the effect of capacity resource options on the future cost and reliability 174 of electric service. The IRP process is governed by the Commission and benefits 175 customers through the development of a diverse resource mix that provides fuel 176 flexibility while maintaining reliability and competitive rates. 177 178Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 179A. The purpose of our testimony is to present and seek approval of Georgia Power’s 180 2019 Integrated Resource Plan and Application for Certification of Capacity from 181 Plant Scherer Unit 3 and Plant Goat Rock Units 9-12 and Application for 182 Decertification of Plant Hammond Units 1-4, Plant McIntosh Unit 1, Plant 183 Langdale Units 5-6, Plant Riverview Units 1-2, and Plant Estatoah Unit 1. In 184 addition, this testimony is filed in support of Georgia Power’s Application for the 185 Certification, Decertification and Amended Demand Side Management Plan 186 (“DSM Application”) filed on January 31, 2019 concurrent with the Company’s 187 2019 IRP. We adopt the 2019 IRP and DSM Application as part of our testimony. 188 11 12 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 7 of 59 189Q. PLEASE SUMMARIZE THE TESTIMONY OF THE PANEL. 190A. As shown in this 2019 IRP, Georgia Power continues to navigate the evolving 191 energy landscape, taking proactive steps to capitalize on current market conditions 192 while also providing flexibility for the Company to respond to several possible 193 future conditions, for the benefit of customers. Working closely with the 194 Commission, the Company has maintained a diverse generation fleet and robust 195 transmission system, that together with a continued focus on energy efficiency, 196 collectively produce high reliability, customer rates well below the national 197 average, and customer satisfaction at the top of the industry. 198 199 The 2019 IRP was developed using the Company’s comprehensive planning 200 process to craft a plan through which the Company will continue providing 201 customers with reliable and affordable electric service from a diverse portfolio of 202 demand-side and supply-side resources. This portfolio – comprised of demand 203 response, energy efficiency, nuclear, natural gas, oil, coal, hydro, solar, wind, 204 landfill gas, and biomass generation – provides significant benefit to customers 205 and maximizes value for customers in a wide variety of future economic and 206 regulatory scenarios. 207 208 The continued implementation of demand-side programs remains an important 209 component of this IRP. In the DSM Application in Docket No. 42311, the 210 Company seeks certification of three new DSM programs, a certificate 211 amendment for three previously-certified programs, decertification of two DSM 212 programs, and approval of updated program economics for the five remaining 213 previously-certified DSM programs, along with Commission approval of certain 214 other energy efficiency-related activities. For all certified DSM programs, the 215 Company is requesting an Additional Sum equal to four cents for every kilowatt 216 hour (“kWh”) saved using verified gross energy savings in the first year of each 217 certified program created by customer participation. 218 13 14 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 8 of 59 219 The proposed DSM programs were developed following a thorough evaluation 220 using the Commission’s approved processes and in collaboration with 221 Commission Staff and numerous interested parties. The Company projects that the 222 proposed DSM programs will result, on average, in approximately 107 megawatts 223 (“MW”) of demand reductions and 375 gigawatt hours (“GWh”) of energy 224 reductions annually for 2020-2022, based on the planned implementation levels. It 225 is important to note that due to lower avoided costs, many of the current DSM 226 programs now appear less favorable under the Total Resource Cost (“TRC”) and 227 Rate Impact Measure (“RIM”) tests. However, the Company believes continuing 228 these programs is beneficial in the current environment as customers are 229 responding favorably and market efficiencies can be achieved by maintaining a 230 presence in the marketplace. 231 232 Georgia Power is continuing its proactive and steady approach of adding 233 renewable resources projected to create long term savings for customers by 234 procuring energy from an additional 1,000 MW of renewable resources. To 235 maximize benefits for customers, these resources will be procured through a 236 competitive bidding process and evaluated utilizing the Commission-approved 237 Renewable Cost Benefit Framework (“RCB Framework”). Based on the success 238 of the commercial and industrial (“C&I”) Renewable Energy Development 239 Initiative (“REDI”) program, the new Customer Renewable Supply Procurement 240 (“CRSP”) program will procure 950 MW of utility scale renewable resources 241 available for subscription by both new and existing commercial and industrial 242 customers. These programs will offer renewable options that meet the needs of 243 customers and improve the competitiveness of Georgia’s business environment. 244 The Company also plans to procure energy from up to 50 MW of renewable 245 distributed generation (“DG”) resources and to expand its Simple Solar program 246 by adding an additional discounted pricing tier for Simple Solar Large Volume 247 participants, allowing greater pricing flexibility for large energy users. 248 15 16 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 9 of 59 249 The Company also seeks Commission approval to invest in energy storage 250 projects to allow for the deployment and continued exploration of utility scale 251 energy storage options operating both independently and in tandem with solar 252 resources. The Company proposes to evaluate the technical and economic 253 performance of these resources on its system relative to expectations, including 254 the ability to use battery energy storage projects for multiple applications. 255 256 The 2019 IRP includes the Company’s plans to comply with all applicable state 257 and 258 implementation of previous Commission-approved strategies, the Company has 259 achieved substantial emissions reductions and has implemented effective 260 environmental controls through making the best economical decisions in the 261 interest of customers. Georgia Power’s current strategy focuses on continued 262 operation of emission controls as well as compliance with recent land and water 263 regulations, such as the Coal Combustion Residuals (“CCR”) and Effluent 264 Limitations Guidelines (“ELG”) rules. To comply with these rules, the Company 265 will design and install additional environmental controls for wastewater treatment 266 and dry ash handling and permanently close 29 ash ponds at its coal-fired power 267 plants. federal environmental laws and regulations. Through successful 268 269 The detailed economic analysis of certain fossil-fueled resources included in the 270 Company’s Unit Retirement Study (“URS”) shows that sustained low gas prices 271 and reduced load growth continue to place economic pressure on the Company’s 272 coal-fired generating units. Consequently, the Company recommends retirement 273 of Plant McIntosh Unit 1 and Plant Hammond Units 1-4. The Company’s 274 remaining coal units continue to provide fuel diversity and economic benefit for 275 customers across a wide range of potential future fuel and carbon prices. The 276 Company plans to balance deferring major resource decisions for its remaining 277 coal units while continuing to meet environmental compliance requirements. The 278 retirement of additional units at this time would be premature, exposing customers 17 18 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 10 of 59 279 to significant reliability risk due to potential generation shortfall and potential 280 transmission-related reliability issues that could occur with the abrupt retirement 281 of additional generation. 282 283 To provide decision-making flexibility and ensure future reliability, the Company 284 plans to make appropriate transmission upgrades and issue two capacity-based 285 RFPs. The first RFP will seek resources that can provide capacity beginning in 286 2022-2023, while the second RFP will seek resources that can provide capacity 287 beginning in 2026-2028, ahead of the Company’s currently forecasted capacity 288 need. 289 290 Additionally, the Company is making the necessary investments to retain the 291 value of its hydro fleet, while also retiring some older, smaller hydro plants. In 292 this IRP, Georgia Power is seeking Commission certification of capacity upgrades 293 at Plant Goat Rock resulting from the replacement of turbines for existing units 294 with larger, updated and more efficient turbines. 295 296 The Company is taking steps to ensure that it can adapt its planning processes to 297 meet the changing demands of the system to reliably meet the energy needs of its 298 customers for the foreseeable future. To ensure proper reliability and economics, 299 the Company evaluates the required amount of resources needed above forecasted 300 peak demand, or reserve margin, prior to each triennial IRP filing to establish a 301 Target Reserve Margin for the System for both the short-term and the long-term 302 planning horizons. Historically, the Company’s capacity planning decisions have 303 been driven by a combination of summer peak loads and a corresponding 304 summer-focused Target Reserve Margin. These planning techniques have proven 305 to be successful in supporting reliability while cost-effectively meeting the needs 306 of customers. However, recent operational experiences and forecasted conditions 307 confirm the significant shift in reliability risk from the summer season to the 308 winter season, consistent with the winter reliability drivers first identified in the 19 20 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 11 of 59 309 Reserve Margin Study filed with the 2016 IRP. Due to the continued increases in 310 winter reliability risks, the Company is adopting seasonal planning to better 311 address these winter reliability issues and provide greater visibility into both 312 summer and winter capacity needs rather than limiting reliability decisions to a 313 single season. 314 315 In accordance with the Commission’s Order in Docket No. 26550, Georgia Power 316 is offering 25 MW of Plant Scherer Unit 3 capacity to the retail jurisdiction to 317 serve retail customers when the current wholesale agreement for this capacity 318 expires at the end of 2019. To meet the requirement that the transaction be offered 319 at then-current wholesale market terms, the Company is utilizing the previously 320 approved application of a Market Differential Adjustment (“MDA”). If the 321 Commission accepts the Company’s offer, Georgia Power is also seeking 322 certification for this additional capacity from the Company’s most economical 323 coal resource. 324 325 The 2019 IRP will economically provide customers high levels of reliability in 326 their electric service through a diverse portfolio of resources now and into the 327 future. The collaborative planning process established by the IRP Act and guided 328 by the Commission has allowed the Company and the Commission to chart a 329 balanced course in meeting customer demand in a dynamic environment, all while 330 maintaining rates below the national average. 331 332Q. WHAT AREAS OF THE IRP ARE THE FOCUS OF YOUR TESTIMONY? 333A. Section II of our testimony covers reliability, the reserve margin, and seasonal 334 planning. Section III covers the Load and Energy Forecast. Section IV discusses 335 the Company’s demand side strategy and DSM Application in Docket No. 42311. 336 Section V addresses the Company’s supply side strategy including the need for 337 decision making flexibility, the proposed capacity RFPs, additional investment in 338 the Company’s hydro fleet, the certification of capacity upgrades at Plant Goat 21 22 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 12 of 59 339 Rock, the requested decertification of Plant Hammond Units 1-4, Plant McIntosh 340 Unit 1, Plant Langdale Units 5-6, Plant Riverview 1-2, and Plant Estatoah Unit 1, 341 the Company’s expansion to its renewable resources portfolio, and the 342 deployment of energy storage. Section VI outlines the Company’s offer and 343 requested certification of wholesale to retail capacity from Scherer Unit 3. Section 344 VII briefly discusses the Company’s Transmission Plan and Section VIII 345 discusses emerging resilience needs. Finally, Section IX addresses the Company’s 346 proposed accounting treatment and cost recovery requests for the plans included 347 in the 2019 IRP. 348 349Q. WHAT AREAS OF THE COMPANY’S CASE ARE ADDRESSED BY THE 350 OTHER WITNESSES’ TESTIMONY? 351A. The Panel of Mark S. Berry and Aaron D. Mitchell provide additional information 352 on the Company’s environmental compliance strategy. 353 354 II. RELIABILITY 355 356Q. WHAT IS “RESOURCE ADEQUACY”? 357A. Resource Adequacy is the process by which a utility determines the appropriate 358 level of resources to maintain reliability on its system. Accepted utility practice 359 requires that electric utilities maintain a sufficient amount of supply- and demand- 360 side resources to adequately serve the electricity needs of its customers. Georgia 361 Power continuously evaluates Resource Adequacy through its assessment of 362 existing resources on the system and calculation of peak demand and Target 363 Reserve Margin. The Company includes this analysis and the Reserve Margin 364 Study in its triennial IRP process. 365 366Q. WHAT IS THE RESERVE MARGIN AND WHAT IS ITS PURPOSE? 367A. The reserve margin is the difference between the total existing and committed 368 capacity, including the impact of demand response programs, and the Company’s 23 24 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 13 of 59 369 projected peak demand. The reserve margin is generally expressed as the 370 percentage of existing and committed capacity above the projected weather- 371 normal peak demand (e.g., a reserve margin of 16.25% means that capacity 372 resources are 16.25% above the projected weather-normal peak demand). In 373 accordance with accepted utility practice, Georgia Power maintains capacity 374 reserves greater than the Company’s projected peak demand in order to achieve 375 the desired level of reliability in light of various risk factors (such as weather, 376 economic growth uncertainty, generator unit performance, market availability 377 risk, etc.) that could cause the actual peak demand, or generation available to meet 378 the peak demand, to differ from projections. 379 380Q. WHAT IS THE TARGET RESERVE MARGIN? 381A. The Target Reserve Margin is the reserve margin that the Company uses for 382 reliability planning purposes. The actual reserve margin will vary over time due to 383 variations in the actual peak demand and resource availability, among other 384 things. In contrast, the Target Reserve Margin remains fixed (until updated 385 through a Reserve Margin Study) and is used to guide the Company’s resource 386 planning decisions. The Company evaluates three components in determining the 387 Target Reserve Margin: economics; risk tolerance; and reliability. The Target 388 Reserve Margin is set at a level that will minimize the combined expected costs of 389 maintaining reserve capacity, production costs, and customer costs associated 390 with service interruptions, while adjusting for risk and maintaining a minimum 391 level of reliability. 392 393Q. HOW DOES THE COMPANY DETERMINE ITS TARGET RESERVE 394 MARGIN? 395A. A Reserve Margin Study is conducted by SCS for the System at least every three 396 years. The study identifies the Target Reserve Margin for the System considering 397 both the costs and risks to customers and the reliability of the System. The target 398 planning reserve margin for each of the retail operating companies is then 25 26 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 14 of 59 399 determined taking into consideration the benefit of System reserve sharing and 400 load diversity. 401 402Q. HOW DOES THE RESERVE MARGIN STUDY DIFFER FROM OTHER 403 IRP ANALYSES? 404A. The Reserve Margin Study is similar to other IRP studies in that it uses production 405 cost techniques to simulate the operation of the System. However, unlike other 406 IRP analyses, the Reserve Margin Study evaluates the system under a broad set of 407 abnormal system conditions such as the impact of economic uncertainty on loads 408 as well as the impact of abnormal weather on both loads and resources. Each of 409 the subsequent IRP analyses are based on weather-normal conditions. Thus, the 410 Reserve Margin Study is the only analysis in the IRP that directly evaluates the 411 Company’s ability to serve load in abnormal, yet historically occurring, weather 412 conditions and unit availability. In addition, the Reserve Margin Study is the only 413 IRP analysis that directly positions the Company to deal with economic 414 uncertainty impacts to peak demand. 415 416Q. WHY IS THE RESERVE MARGIN STUDY CONDUCTED AT A SYSTEM 417 LEVEL? 418A. Because the System is dispatched as a pool (providing numerous benefits to 419 Georgia Power customers) and the pooling arrangement requires a coordinated 420 planning process, it is necessary to conduct the Reserve Margin Study at the 421 System level. 422 423Q. HOW DOES THE POOL DISPATCH AND COORDINATED PLANNING 424 BENEFIT GEORGIA POWER CUSTOMERS IN THE CONTEXT OF THE 425 TARGET RESERVE MARGIN? 426A. Because Georgia Power has the ability to “share” (i.e., utilize) the reserves of the 427 other operating companies and because there is load diversity among the 428 operating companies, Georgia Power can plan to a lower Target Reserve Margin 27 28 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 15 of 59 429 while the higher System target is maintained. This reserve sharing benefits 430 customers by lowering the amount of generation capacity needed by Georgia 431 Power to serve customers which lowers the cost of generation capacity for which 432 customers pay. 433 434Q. WHY IS A DIFFERENT TARGET RESERVE MARGIN USED FOR 435 SHORT- AND LONG-TERM PLANNING? 436A. Over the short-term (inside three years), there is typically less economic 437 uncertainty and therefore, a lower target planning reserve margin can be used for 438 short-term planning than is used for long-term planning. 439 440Q. PLEASE EXPLAIN WHY THE COMPANY IS ADOPTING SEASONAL 441 PLANNING. 442A. Historically, the Company’s capacity planning decisions have been driven by a 443 combination of summer peak loads and a corresponding summer-based Target 444 Reserve Margin. These planning techniques have proven to be successful in 445 supporting reliability while cost-effectively meeting the needs of customers in all 446 seasons of the year. The Company is not recommending a change to this summer- 447 based Target Reserve Margin. However, recent operational experiences and 448 forecasted conditions indicate a significant shift in reliability risk from the 449 summer season to the winter season, thus requiring the Company to adapt its 450 historically summer-based capacity planning approach to specifically address 451 these risks. Therefore, because the nature of the changing system has resulted in 452 increased winter reliability risks, the Company is adopting seasonal planning to 453 address the winter reliability issues previously identified in the 2016 IRP as well 454 as a newly-identified reliability risk factor. Seasonal planning provides greater 455 visibility into both summer and winter capacity needs rather than limiting 456 reliability decisions to a single season. To facilitate this seasonal planning, the 457 Company is adopting a Winter Target Reserve Margin for the winter season in 29 30 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 16 of 59 458 addition to the traditional Target Reserve Margin focused on the summer season 459 (“Summer Target Reserve Margin”). 460 461Q. WHAT WERE THE DRIVING RISKS THAT CAUSED THE COMPANY 462 TO ADOPT SEASONAL PLANNING? 463A. Prior to the 2014 Polar Vortex, the System had experienced an extended period of 464 relatively mild winter weather, during which the System was also undergoing 465 significant load response and generator availability changes related to extreme 466 cold weather conditions. These changes in System response to cold weather did 467 not have the opportunity to manifest themselves until the 2014 Polar Vortex and 468 therefore had not previously been modeled in any reliability studies. The 2015 469 Reserve Margin Study filed in the 2016 IRP was the first study that included 470 assumptions and modeling impacts to capture these changes and reflected a 471 significant increase in winter reliability risks. The 2015 Reserve Margin Study 472 identified several drivers associated with these changes, including: (1) narrowing 473 of the difference between summer and winter weather-normal peak loads; (2) 474 higher volatility of winter peak demands relative to summer peak demands; (3) 475 cold-weather-related unit outages; (4) penetration of solar resources; and (5) 476 increased reliance on natural gas. To address winter reliability issues, the 2016 477 IRP Order approved an increase in the Target Reserve Margin from 15% to 478 16.25% based on summer load values and summer resource values. 479 480 In preparing the 2019 IRP, the 2018 Reserve Margin Study not only reidentified 481 the five risks enumerated above, but also identified a sixth driver associated with 482 market purchase availability under both extreme summer and winter conditions. 483 Upon further consideration and examination of these six reliability risks, the 484 Company is now recognizing the need for a broader seasonal planning approach. 485 Given the risk of higher than normal winter loads as well as differences in both 486 availability and dependability of resources in the summer and winter peak 487 periods, it has become necessary to independently evaluate Resource Adequacy in 31 32 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 17 of 59 488 both the summer and winter peak periods to ensure that System reliability has 489 been adequately evaluated and addressed. 490 491Q. WHAT ARE THE COMPANY’S RECOMMENDED SUMMER AND 492 WINTER TARGET RESERVE MARGINS? 493A. The Company plans to maintain the current 16.25% long-term Target Reserve 494 Margin for the System as the Summer Target Reserve Margin to be applied to the 495 summer peak planning season. This Target Reserve Margin is calculated as it 496 traditionally has been, by comparing resources available in the summer – at their 497 summer peak period capacity – to the forecasted weather-normal summer peak 498 load. To address winter reliability concerns, the Company plans to add a long- 499 term Winter Target Reserve Margin of 26% for the System to be applied to the 500 winter peak planning season. This 26% reserve margin is calculated based on 501 winter peak period resource capacities and the forecasted weather-normal winter 502 peak load. 503 504 For the short-term, the Company plans to increase the Summer Target Reserve 505 Margin from 14.75% to 15.75%, with a commensurate short-term Winter Target 506 Reserve Margin of 25.5%. As explained in the Reserve Margin Study, the gap 507 between the long-term and short-term periods (regardless of season) has reduced 508 from roughly 1.5% to 0.5%. 509 510Q. WHY IS THE WINTER TARGET RESERVE MARGIN HIGHER THAN 511 THE SUMMER TARGET RESERVE MARGIN? 512A. The Winter Target Reserve Margin can have the appearance of being higher than 513 the Summer Target Reserve Margin because forecasted weather-normal winter 514 peak loads are lower than forecasted weather-normal summer peak loads and 515 because winter generating capacity can have different operational characteristics 516 than summer generating capacity. However, for every summer reserve margin 517 there exists an equivalent winter reserve margin that, for the same given System 518 conditions, represents the same cost and reliability. In fact, as explained in the 33 34 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 18 of 59 519 2018 Reserve Margin Study, the planned 26% long-term Winter Target Reserve 520 Margin is consistent with the results of the 2015 Reserve Margin Study if it had 521 generated an equivalent Winter Target Reserve Margin for the System. 522 523 The chart below provides an example of how the Summer Target Reserve Margin 524 and the Winter Target Reserve Margin result in a similar level of capacity 525 requirement for Georgia Power in an example year. 526 527 528 529Q. WHICH TARGET RESERVE MARGIN WAS USED FOR PLANNING 530 PURPOSES DURING PREPARATION OF THE COMPANY’S 2019 IRP 531 FILING? 532A. The Company used the Commission-approved, summer-focused, 16.25% Target 533 Reserve Margin for planning purposes in preparing the 2019 IRP. The Company 534 did not make or alter any resource decisions in this IRP based on the 35 36 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 19 of 59 535 recommended Winter Target Reserve Margin. However, the Company includes 536 sensitivities to demonstrate that while the change is minimal for Georgia Power in 537 this IRP, the adoption of seasonal planning is necessary to enable the Company to 538 act upon winter-based reliability concerns. 539 540Q. DOES THE ADOPTION OF SEASONAL PLANNING CHANGE THE 541 TIMING OF THE COMPANY’S NEXT CAPACITY NEED? 542A. No. Despite implementation of the seasonal Target Reserve Margins, Georgia 543 Power’s next capacity need occurs in the summer rather than in the winter, 544 indicating that the timing of the Company’s next capacity-based decision 545 continues to be driven by summer needs. Future capacity planning decisions, 546 however, could be driven by winter needs, especially if existing winter reliability 547 risks are not adequately addressed, winter and summer loads continue to narrow, 548 and seasonal resources continue to be added to the system. 549 550 III. LOAD AND ENERGY FORECASTS 551 552Q. PLEASE SUMMARIZE GEORGIA POWER’S DEMAND AND ENERGY 553 FORECASTS THAT WERE FILED IN THE 2019 IRP. 554A. A twenty-year forecast of energy sales and peak demand was developed to meet 555 the planning needs of Georgia Power. The Budget 2019 Load and Energy Forecast 556 (“Budget 2019”) includes the retail classes of residential, commercial, industrial, 557 Metropolitan Atlanta Rapid Transit Authority (“MARTA”) and governmental 558 lighting. The energy and peak demand forecasts have been adjusted for the effects 559 of the DSM programs, cogeneration, behind-the-meter solar, and electric vehicles. 560 Additionally, the peak demand forecast is also adjusted for the effects of real time 561 pricing (“RTP”) customers’ response to price signals. 562 37 38 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 20 of 59 563Q. WHAT ARE THE MAIN DRIVERS OF THE LOAD FORECAST? 564A. The two major drivers of the load forecast are the economy and the penetration 565 and efficiency trends in electric end uses. Historically, there has been a closer 566 relationship between economic growth and energy sales. Following the great 567 recession, however, this relationship weakened due partly to improvements in 568 energy efficiency. 569 The United States and Georgia both experienced solid economic growth from 570 2013-2017. Over this period, U.S. Gross Domestic Product (“GDP”) growth 571 averaged 2.3% per year, while Georgia’s economy experienced growth of 3.1% 572 per year. Also, during this period the unemployment rate fell from 8.0% to 4.1% 573 in the U.S. and from 8.7% to 4.5% in Georgia. In 2018, the unemployment rate 574 fell below 4% for both the U.S. and Georgia. 575 Despite solid economic growth in Georgia, Georgia Power’s total retail energy 576 sales have flattened since 2007, with weather normalized total energy sales 577 declining an average of -0.2% per year and remaining below 2007 levels. The 578 commercial and industrial classes declined over this same period, down an 579 average of -0.2% and -0.8% per year, respectively. The residential class is the 580 only customer class that experienced modest growth, up an average of 0.2% per 581 year over the past ten years. In recent years, retail sales began to grow due to the 582 strength of the economy in Georgia, as evidenced by strong growth in the number 583 of customers. Between 2013 and 2018, total retail energy sales grew at an average 584 annual rate of 0.4%. 585 Georgia’s economic growth is expected to continue. One factor contributing to 586 growth is that the state is an attractive place to do business. Georgia’s low cost of 587 doing business and low cost of living, the deep pool of knowledge and technical 588 workers coming from its university system, its globally connected airport and 589 transportation infrastructure (e.g. ports, highways), and its business-friendly 590 government policies will continue to attract businesses. Positive demographic 591 trends are another factor driving growth in the state. As businesses continue to 39 40 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 21 of 59 592 relocate and expand in Georgia, the state will experience solid employment 593 growth, which will attract new residents. As a result, population growth will 594 remain above the U.S. average. 595 596 Georgia Power anticipates a boost to energy sales from the addition of more 597 businesses and a growing population. From 2019-2029, total energy sales are 598 projected to grow at an average annual rate of 0.7%. Residential sales are 599 expected to grow by an average of 1.2% per year over this period as customer 600 growth outpaces the reduction in use-per-customer resulting from energy 601 efficiency. Industrial sales are expected to increase at an average annual rate of 602 1.0% primarily due to the addition of a large customer in 2019 and 2020. Sales to 603 the commercial class are expected to decline slightly over this period by an 604 average of -0.1% per year due partly to energy efficiency. Peak demand is 605 expected to increase at an average rate of 0.5% per year. 606 607Q. HOW HAS THE DIFFERENCE BETWEEN THE SUMMER AND 608 WINTER PEAK DEMANDS CHANGED? 609A. Over the past decade, especially following the great recession, energy 610 consumption in the winter and summer months has narrowed, causing winter and 611 summer peak demand projections to also narrow in consecutive forecasts. As 612 discussed earlier, the growth in energy sales has declined measurably since the 613 great recession. This decline in growth has been more pronounced in the summer 614 months than in the winter months, driving the narrowing between winter and 615 summer peaks. In fact, since 2007, average annual growth in weather normal 616 energy sales in the month of January has been positive 0.5%, whereas average 617 annual growth in energy sales in July has been negative 0.4%. In the 15-year 618 period prior to the great recession, both January and July energy sales grew at 619 approximately 2.5% annually on a weather normal basis. Tighter HVAC 620 efficiency standards over time have been a significant driver of the decline in 621 energy use in the summer months. 41 42 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 22 of 59 622 IV. DEMAND SIDE STRATEGY 623 624Development of the DSM Portfolio 625 626Q. DESCRIBE GEORGIA POWER’S CURRENT DSM PORTFOLIO. 627A. The Company’s current DSM portfolio consists of energy efficiency programs, 628 demand response programs, pricing tariffs, and other activities. The Company 629 projects that by 2022 this portfolio will represent approximately 1,600 MW, or 630 approximately 10% of the Company’s current peak demand. In this IRP, the 631 Company is proposing a DSM plan that will result in an additional 375 GWh of 632 annual energy savings and 107 MW of peak demand savings. 633 634Q. PLEASE DESCRIBE THE DEVELOPMENT OF THE PROPOSED DSM 635 PLAN. 636A. In accordance with the 2016 IRP Order, the Company continued to work with the 637 Demand Side Management Working Group (“DSMWG”), including Commission 638 Staff, and followed the DSM Program Planning Approach. The Company retained 639 third-party consultants to assist with the planning, implementation, and evaluation 640 of the ten DSM programs certified in the Commission’s 2016 IRP Order. The 641 Company completed a Technical Reference Manual in December 2017 and 642 completed and filed the Achievable Energy Efficiency Potential Assessment in 643 January 2018. In August 2018, the Company filed complete Process and Impact 644 Evaluation result reports for the ten DSM programs currently certified. 645 646 The Company continues to follow the Commission’s economic screening policy 647 outlined in the 2004 IRP Final Order in Docket No. 17687, which directs that the 648 proposed DSM plans minimize upward pressure on rates and maximize economic 649 efficiency. The Company evaluates the impact of its DSM programs on rates 650 through the RIM Test and determines the economic efficiency of its DSM 651 programs using the TRC Test. As demonstrated through the Company’s processes, 43 44 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 23 of 59 652 DSM is given priority and reduces the Company’s energy and demand forecast 653 before supply-side alternatives are considered. The Company fully complied with 654 the DSM Program Planning Approach in developing its proposed DSM plan. The 655 DSM Program Plans included in the DSM Application represent a well-balanced 656 portfolio of residential and commercial DSM programs that are structured to help 657 customers reduce and better manage their energy usage. 658 659Q. DOES THE PLANNING PROCESS USED TO DEVELOP THE 660 PROGRAMS FOR THIS FILING SATISFY THE COMMISSION’S DSM 661 EVALUATION RULE? 662A. Yes. Completion of the DSM Program Planning Approach, including the filing of 663 the Achievable Energy Efficiency Potentials Assessment and the development of 664 the Technical Reference Manual, satisfies the requirements of Commission Rule 665 515-3-4-.04(4). 666 667Q. WHAT ASSISTANCE DID THE DSMWG PROVIDE IN THIS PROCESS? 668A. The Company met with the DSMWG eight times in 2017 and 2018 in an effort to 669 collaboratively develop program concepts for the 2019 IRP. The Company also 670 hosted a two-day meeting with a subset of the DSMWG, including Commission 671 Staff, for the sole purpose of DSM program ideation. The DSMWG provided 672 feedback on the Achievable Energy Efficiency Potential Assessment, the 673 Technical Reference Manual, and the measures and programs being evaluated. 674 The Company shared the results of the economic screening with the DSMWG. 675 Additionally, several measures were added to the DSM programs included in the 676 Company’s Proposed Case at the request of DSMWG members, such as the 677 Residential Thermostat Demand Response program and the income-qualified 678 programs. 679 680Q. 45 46 WHAT PROGRAM EVALUATION WAS CONDUCTED WITH RESPECT Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 24 of 59 681 TO THE PROGRAMS CERTIFIED BY THE COMMISSION IN THE 2016 682 DSM APPLICATION? 683A. In accordance with the 2016 IRP Order, the Company provided Commission Staff 684 detailed evaluation plans for each of the ten certified DSM programs to solicit 685 comments and feedback on the proposed evaluation plans in advance of the 686 evaluations themselves. Georgia Power completed process and impact evaluations 687 on each of the ten certified DSM programs prior to the 2019 IRP. The Company 688 selected Nexant and Illume to perform the program evaluations. Program 689 evaluations were completed and filed with the Commission on August 14, 2018. 690 The results of the program evaluations were considered in the development of the 691 2019 IRP and applied to the program plans included in the DSM Application. 692 693Q. WHAT SPECIFIC APPROVAL IS SOUGHT BY THE COMPANY? 694A. In Docket No. 42311, the Company seeks Commission approval of a certificate of 695 public convenience and necessity for three new DSM programs, an amendment to 696 the certificate for three previously certified DSM programs, decertification of two 697 DSM programs, updated program economics for the remaining five previously- 698 certified DSM programs, and a modified Additional Sum calculation, as detailed 699 further in the Company’s 2019 DSM Application. The Company also intends to 700 continue the Power Credit residential program, certified in Docket No. 6315, and 701 its Education and Energy Efficiency Awareness initiatives. Consistent with the 702 2016 IRP Order, the Company seeks Commission approval of a budget for pilot 703 studies which are used to better understand emerging energy efficiency options 704 for customers. Additionally, the Company seeks approval of the Income-Qualified 705 Tariff Based Financing Pilot and associated budget. 47 48 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 25 of 59 706The DSM Programs 707 708Q. PLEASE DESCRIBE THE RESIDENTIAL INCOME-QUALIFIED 709 (CROWD FUNDING) PROGRAM THAT THE COMPANY SEEKS TO 710 CERTIFY. 711A. The Income-Qualified (Crowd Funding) program is a new offering that aims to 712 provide greater financial assistance to income-qualified households that are 713 historically under-represented in energy efficiency program participation. The 714 program provides members of the community who opt-in with access to a 715 centralized web portal where they can learn about opportunities to help contribute 716 and raise funds for a neighbor in need of home weatherization assistance or home 717 energy efficiency improvements. Georgia Power will work with community 718 partners and local nonprofits to identify, assess, and implement projects. The 719 Income-Qualified (Crowd Funding) program will offer direct installation of 720 energy efficiency measures for both single family and multifamily properties. 721 Eligible energy efficiency measures include, but are not limited to, smart 722 thermostats, efficient lighting, air and duct sealing, attic insulation, and HVAC 723 system servicing and repairs. Georgia Power will provide up to $2,000 per home 724 to offset the cost of the energy efficiency improvements. Any funds crowd-funded 725 will be additive to the funding Georgia Power provides as part of the DSM tariff. 726 727Q. PLEASE DESCRIBE THE RESIDENTIAL THERMOSTAT DEMAND 728 RESPONSE PROGRAM THE COMPANY SEEKS TO CERTIFY. 729A. The Residential Thermostat Demand Response program is a new offering based 730 on a pilot program Georgia Power implemented in early 2018. The Residential 731 Thermostat 732 improvements and shifting of electricity usage during peak demand periods – hot 733 summer days, cold winter days, and during periods in which the Company is 734 experiencing extreme supply and demand conditions. The program provides 735 customers that are willing to help reduce energy during a demand response event 49 50 Demand Response program promotes energy efficiency Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 26 of 59 736 periods with either the installation of a free, bi-directional communicating smart 737 thermostat or financial incentives for customers with an existing smart thermostat. 738 Georgia Power, or its representative, can manage the load from participants’ 739 HVAC systems by adjusting thermostat settings. Residential customers in either 740 single family or multifamily houses with central, all electric HVAC systems are 741 eligible to participate. The program is designed so that customers may not even 742 notice any changes in their heating or cooling as their thermostat settings are 743 adjusted during a demand response event. 744 745Q. PLEASE DESCRIBE THE COMMERCIAL BEHAVIORAL PROGRAM 746 THE COMPANY SEEKS TO CERTIFY. 747A. Georgia Power’s Commercial Behavioral program is designed to encourage 748 customer engagement with facility energy management and energy efficiency to 749 reduce energy consumption. Similar to the Residential Behavioral program, the 750 Commercial Behavioral program provides customer-specific information that 751 allows customers to compare their energy use for the month, and over the past 752 year, to the consumption of a peer group of similar commercial facilities and 753 facilities that are considered energy-efficient or through their own disaggregated 754 meter data. Participating customers electronically receive a Business Electric 755 Report several times a year with a summary of their energy consumption data and 756 the energy consumption of their peers over the same time period. The reports also 757 include seasonal and facility-appropriate energy savings tips, as well as 758 information on other commercial energy efficiency programs. 759 760Q. PLEASE DESCRIBE WHY THE COMPANY SEEKS TO DECERTIFY 761 THE RESIDENTIAL EARTHCENTS NEW HOME PROGRAM. 762A. The Company requests decertification of the Residential EarthCents New Home 763 program due to failing program economics. The EarthCents New Home program 764 promoted the installation of energy-efficient measures in new home construction 765 to improve the electric energy performance of participating homes by at least 51 52 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 27 of 59 766 7.5% above the existing residential state energy code at the time the home was 767 built. Experience has shown that new homes are not only compliant but already 768 exceed the state energy code requirements without the need for any incentive 769 from Georgia Power. The results and economics of the program evaluations 770 conducted during 2017 and 2018 did not support continuation of the EarthCents 771 New Home program. 772 773Q. PLEASE DESCRIBE WHY THE COMPANY SEEKS TO DECERTIFY 774 THE RESIDENTIAL HVAC SERVICE PROGRAM. 775A. The Company requests decertification of the HVAC Service program due to low 776 customer participation rates. The HVAC Service program targeted HVAC 777 performance issues by offering customers a rebate on the cost of having a 778 qualified contractor conduct an assessment and tune up their HVAC System. 779 However, due to lack of HVAC service contractor participation because of 780 overlapping servicing timelines with peak HVAC sales season, Georgia Power 781 recommends this program for decertification. 782 783Q. FOR WHICH PROGRAMS IS THE COMPANY REQUESTING 784 AMENDMENTS TO PROGRAM CERTIFICATES? 785A. Georgia Power is requesting to amend the certificates of the following programs: 786 Residential Home Energy Improvement program; Residential Specialty Lighting 787 program; and Commercial Midstream Products. 788 789Q. FOR WHICH CERTIFIED DSM PROGRAMS IS THE COMPANY 790 PRESENTING UPDATED ECONOMICS? 791A. The Company is updating program economics for the Residential Behavioral, 792 Residential Refrigerator/Freezer Recycling, Commercial Custom, Commercial 793 Prescriptive and the Small Commercial Direct Install programs. The updated 794 economics can be found in Appendix E of the DSM Application. 795 53 54 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 28 of 59 796Evaluation and Impact of DSM Programs 797 798Q. WHAT IMPACTS ARE THE COMPANY’S PORTFOLIO OF PROPOSED 799 DSM PROGRAMS EXPECTED TO HAVE ON PEAK DEMAND AND 800 ENERGY USAGE? 801A. The Company projects that its proposed energy efficiency programs will result, on 802 average, in approximately 107 megawatts (“MW”) of peak demand reduction and 803 375 gigawatt hours (“GWh”) of energy reductions annually for 2020-2022, based 804 on the planned implementation levels. 805 806Q. WHAT IS THE IMPLEMENTATION SCHEDULE FOR THE DSM 807 PROGRAMS DESCRIBED IN YOUR TESTIMONY? 808A. Provided the Commission approves the DSM Application, the Company will 809 finalize its plans for implementation of these DSM programs during the last five 810 months of 2019. This will include continuation of existing programs, 811 modifications of the existing programs, and start-up activities for new programs, 812 such as infrastructure refinement and contracting with third-party vendors, where 813 applicable. Barring any unforeseen issues, the Company will initiate all three new 814 programs and will begin promoting these programs to customers during the first 815 quarter of 2020. 816 817Q. HOW WILL GEORGIA POWER MEASURE THE SUCCESS OF THE 818 THESE DSM PROGRAMS? 819A. Program performance and progress towards achieving established goals will be 820 tracked on an ongoing basis. In addition, Georgia Power will contract with 821 independent, third-party evaluators through a Request for Proposal solicitation to 822 conduct comprehensive program evaluations at regular intervals (initially planned 823 for three-year intervals). The evaluations will include market, process, and impact 824 evaluations to review the program’s operations, evaluate the program’s impact on 825 the local market, and verify the energy and demand savings produced by the 55 56 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 29 of 59 826 program. The Company will begin implementing evaluation results and applying 827 deemed savings to the new program cycle beginning in January 2023 to be 828 consistent with the Company’s three-year IRP and DSM planning cycles. 829 830Q. PLEASE DESCRIBE THE COST-EFFECTIVENESS OF THE PROPOSED 831 DSM PROGRAMS. 832A. The DSM programs in the Company’s Proposed Case will average approximately 833 $118 million in TRC benefits while putting upward pressure on rates of 834 approximately $238 million annually over years 2020 – 2022. Relative to the 835 2016 IRP economic test results, the TRC Test results declined and RIM Test 836 results worsened for the Company’s Proposed Case. In the 2016 IRP, the 837 Company’s Proposed Case averaged approximately $149 million in TRC benefits 838 while putting upward pressure on rates of approximately $184 million annually 839 over years 2017 – 2019. 840 841Q. WHAT IS THE PRIMARY CAUSE OF DECLINING DSM PROGRAM 842 ECONOMICS? 843A. The overall decline in the cost of natural gas has reduced the marginal cost of 844 generating electricity. The lower cost of natural gas not only saves customers 845 money, but also lowers the Company’s avoided cost. With these lower avoided 846 costs, the value of each kWh saved as a result of DSM participation has declined. 847 These changes in avoided cost savings have a negative impact on the economics 848 of the Company’s current and proposed DSM programs. 849 850Q. WHY IS THE COMPANY CONCERNED WITH THE DECLINING TRC 851 TEST RESULTS AND THE WORSENED RIM TEST RESULTS? 852A. The Company continues to follow the Commission’s policy outlined in the 2004 853 IRP Order, Docket No. 17687, which requires the Company to offer a DSM plan 854 that minimizes upward pressure on rates and maximizes economic efficiency. This 855 Commission policy has been affirmed by the Commission in each subsequent IRP 57 58 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 30 of 59 856 since 2004. The Company used this same philosophy in analyzing the slate of 857 programs considered for certification in the DSM Application and the 2019 IRP. 858 Nevertheless, as the benefits from these programs decline and the cost in terms of 859 rate impact increases, it becomes a bigger challenge to maintain that balance. 860 861Q. WHY HAS THE COMPANY RECOMMENDED CONTINUATION OF 862 THE DSM PROGRAMS? 863A. The Company’s recommendation to continue the programs at this time is based on 864 the desire to minimize market disruption, to continue meeting customers’ 865 expectations, and to maintain working relationships with vendors performing 866 qualified program improvements. The Company recommends discontinuation or 867 decertification of DSM programs that fail economic screening or do not meet its 868 participation goals. 869 870DSM Pilot Programs 871 872Q. IS THE COMPANY PROPOSING ANY PILOT PROGRAMS IN THIS 873 IRP? 874A. Yes. The Company is seeking Commission approval of the Income-Qualified 875 Tariff Based Financing Pilot. In addition, similar to the Company’s request in the 876 2016 IRP, the Company seeks Commission approval of a residential and 877 commercial pilot budget to develop and evaluate pilot projects. DSM pilot 878 programs allow the Company to gather valuable information to aid in the 879 examination of new technologies and additional ways to enhance programs. 880 Conducting small scale pilots allows the Company to test a program in a 881 controlled environment with limited financial and customer satisfaction risks. The 882 knowledge gained through pilots allows the Company to get programs up and 883 running quickly and smoothly when they are approved for certification. 59 60 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 31 of 59 884Q. PLEASE EXPLAIN THE INCOME-QUALIFIED TARIFF BASED 885 FINANCING PILOT PROGRAM THE COMPANY HAS INCLUDED IN 886 ITS REQUEST? 887A. The Income-Qualified Tariff-Based Financing Pilot Program will be offered as a 888 non-certified pilot directly targeting income-qualified households that are 889 historically under-represented in energy efficiency program participation. Upfront 890 cost is one of the reasons income-qualified customers typically do not participate 891 in energy efficiency programs. For participants in Georgia Power’s Income- 892 Qualified Tariff-Based Financing Pilot, Georgia Power will cover the upfront cost 893 of eligible energy efficiency measures installed. The customer then repays the cost 894 of the energy efficiency upgrades and installation through his or her electric utility 895 bills via a Commission approved tariff (to be included in Georgia Power’s base 896 rate case in 2019). The program will be designed to provide net energy and 897 financial savings for participating customers because the new monthly bill 898 amount, including Georgia Power’s monthly charge to recover the cost of the 899 upgrades, will be designed to be lower than the monthly energy bill before the 900 upgrades were installed, assuming similar household size, usage, and weather- 901 normalized consumption pre- and post-installation. The Income-Qualified Tariff- 902 Based Financing Pilot will be offered to up to 200 income-qualified residential 903 customers in select, targeted areas of the state with the goal of saving 20% of their 904 baseline household electric energy with an investment of up to $7,500 per 905 household. 906 907Q. HOW DOES THE COMPANY PROPOSE TO RECOVER THE COST OF 908 THE INCOME-QUALIFIED TARIFF BASED PILOT PROGRAM? 909A. Georgia Power intends to recover the cost of the energy efficiency upgrades and 910 installation costs, including the return on any deferred costs associated with the 911 investments, through participating customers via the Income-Qualified Tariff, 912 which will be included as part of the Company’s 2019 base rate case. Should 913 Georgia Power be unable to fully recover the cost of the installed upgrades under 61 62 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 32 of 59 914 the new tariff, those remaining costs will be included for recovery in the 915 residential DSM tariff. In addition, Georgia Power proposes to recover the costs 916 for program administration, customer education and awareness campaigns, 917 oversight and evaluation through the residential DSM tariff. 918 919Q. IS THIS PROGRAM THE ONLY INCOME-QUALIFIED DSM PROGRAM 920 THE COMPANY OFFERS? 921A. No. The Company is also seeking to certify an Income-Qualified (Crowd 922 Funding) program as part of the portfolio of certified residential DSM programs. 923 The Company will also continue to provide annual funding to HopeWorks, which 924 provides income-qualified seniors with in home energy efficiency assessments 925 and improvements and carve out $500,000 for income-qualified customers in the 926 Company’s 927 Additionally, income-qualified customers are eligible to participate in all of 928 Georgia Power’s residential DSM programs. certified Residential Home Energy Improvement program. 929 930Q. WHAT BUDGET HAS THE COMPANY REQUESTED FOR PILOT 931 STUDIES? 932A. The Company seeks Commission approval of $2 million for residential and $2 933 million for commercial pilot studies. In addition, the Company estimates that the 934 cost of the Income-Qualified Tariff Based Pilot Program will be $6 million. 935 936Certified Cost of DSM Programs and Additional Sum 937 938Q. WHAT ARE THE COSTS THE COMPANY REQUESTS THAT THE 939 COMMISSION APPROVE? 940A. The Company requests Commission approval of the DSM program and pilot 941 budgets, costs associated with certain other DSM activities, and the Additional 942 Sum amount. The budgets and costs for the Company’s DSM programs are set 63 64 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 33 of 59 943 forth in Appendix C to the DSM Application and the Additional Sum amounts are 944 set forth in Appendix F to the DSM Application. 945 946Q. PLEASE DESCRIBE GEORGIA POWER’S 947 ADDITIONAL SUM. 948A. As stated in the DSM Application, the Company requests an Additional Sum 949 equal to four cents for every kWh saved using verified gross energy savings 950 values applied to all certified DSM programs in the residential and commercial 951 DSM portfolios. Moreover, the Company proposes a revised sliding scale 952 approach to encourage achievement of certified energy savings goals while 953 ensuring cost-effective program implementation. Under this approach, if the 954 reported energy savings fall below 50% of the certified energy savings goal by 955 class, or as a portfolio during any year within the IRP cycle, the Additional 956 Sum will be collected at two cents per kWh saved. If the reported energy savings 957 fall between 50% and 120% of certified energy savings goal by class and without 958 exceeding class level budget, or as a portfolio during any year within the IRP 959 cycle, the Additional Sum on the reported savings will be collected at four cents 960 per kWh saved beginning at the first kWh. If the reported energy savings 961 grow higher than 120% of certified energy savings goal by class, or as a portfolio 962 during any year within the IRP cycle, the Additional Sum on the reported savings 963 beyond 120% will be collected at five cents per kWh saved. A chart summarizing 964 the applicable Additional Sum given the range of energy savings is included 965 below: Reported Energy Savings Below 50% 50% to 120% Greater than 120% 65 66 REQUEST FOR AN Additional Sum (¢/kWh saved) 2¢ for all kWh 4¢ for all kWh 4¢ for kWh up to 120%, 5¢ for kWh above 120% Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 34 of 59 966 967 Despite the proposed change in methodology, the requested Additional Sum does 968 not result in an increased incentive amount for the Company and is in fact less 969 than the Additional Sum approved by the Commission in the 2016 DSM 970 Certification case in Docket No. 40162. Any authorized Additional Sum will be 971 specific to the corresponding customer class and will be collected through the 972 Residential and Commercial DSM tariffs. 973 974Q. IF THE INCENTIVE AMOUNT IS NOT SIGNIFICANTLY DIFFERENT, 975 WHY DOES THE COMPANY WANT TO CHANGE THE ADDITIONAL 976 SUM METHODOLOGY? 977A. The proposed Additional Sum methodology is simpler and likely to be more 978 stable. As proposed, the change in methodology better aligns the Additional Sum 979 with the energy savings achieved from the customer classes eligible to participate 980 in the Company’s residential and commercial DSM programs. Furthermore, under 981 the current methodology Georgia Power receives little to no Additional Sum from 982 residential DSM programs that deliver kWh savings. The Company believes the 983 proposed approach will also help streamline the reporting process and provide 984 more clarity with the annual DSM tariff true-up process. 985 986Q. SHOULD ENERGY SAVINGS BE ADJUSTED FOR MARKET EFFECTS? 987A. No. Market effects such as free-ridership and spillover are recognized in the 988 industry as important research data points for deciding whether to modify or 989 continue DSM programs. While market effects are useful for program evaluations 990 and modifications, future program design and system planning, the Company 991 believes that for energy savings targets and the Additional Sum, verified gross 992 energy savings are a better indicator of program success. 993 67 68 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 35 of 59 994Q. WHY IS IT NOT APPROPRIATE TO ADJUST THE ENERGY SAVINGS 995 FOR MARKET EFFECTS USED IN CALCULATING THE ADDITIONAL 996 SUM? 997A. There are a number of reasons why no adjustment should be made for market 998 effects. First, market effects are constantly changing and thus should not be 999 utilized as the basis for a static adjustment to the Additional Sum. While the 1000 Company employs industry-standard methods to quantify market effects, the 1001 estimate generated only provides information regarding the particular point in 1002 time that the surveys are conducted. 1003 1004 Second, the Company has no control over free riders and does not have the ability 1005 to structure programs in such a way as to eliminate free riders. Thus, it is not 1006 appropriate to hold the Company accountable for such market effects. The factors 1007 over which the Company does have control, such as program implementation and 1008 budgets, directly influence gross energy savings, and thus gross energy savings is 1009 the more appropriate basis for calculation of the Additional Sum. 1010 1011 Third, the Company’s DSM programs are intended to bring about market 1012 transformation and market transformation will, over the long run, result in 1013 increasing levels of free ridership. As such, it runs contrary to the stated goals of 1014 the Company’s programs to hold the Company accountable for free riders. 1015 1016Q. HOW WOULD DSM PROGRAM COSTS, AS WELL AS THE PROPOSED 1017 ADDITIONAL SUM, BE COLLECTED? 1018A. Georgia Power proposes that costs of approved and certified DSM programs and 1019 activities, as well as the Additional Sum amount for certified DSM programs, be 1020 collected through the existing Residential and Commercial DSM tariffs. These 1021 tariffs would be filed as part of the Company’s 2019 base rate case and would be 1022 implemented with any approved change in rates on January 1, 2020. 1023 69 70 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 36 of 59 1024Q. WILL THE DSM TARIFFS BE TRUED UP? 1025A. Yes. Consistent with current practice, the DSM tariffs will initially be based on 1026 projected program costs, participation levels, and projected Additional Sum 1027 values approved in the 2019 IRP and DSM Application and will subsequently be 1028 trued-up annually based on actual program participation levels, actual program 1029 costs, and actual revenues collected using the true-up methodology agreed to by 1030 the Company and Commission Staff. 1031 1032 V. SUPPLY-SIDE STRATEGY 1033 1034Overview 1035 1036Q. PLEASE DESCRIBE SOME OF THE MAJOR SUPPLY-SIDE RELATED 1037 ACTIVITIES COMPLETED BY THE COMPANY SINCE THE 2016 IRP. 1038A. In accordance with the Commission’s order in the 2016 IRP, the Company retired 1039 Plant Mitchell Units 3, 4A, and 4B, retired Plant Kraft Unit 1 CT, and completed 1040 the sale of the Company’s ownership in the Intercession City CT to Duke Energy 1041 Florida. Georgia Power commenced and subsequently suspended new nuclear site 1042 investigation and combined license (“COL”) work at a site in Stewart County, 1043 Georgia. The Company initiated construction and installation of equipment 1044 necessary for dry ash conversions, wastewater treatment, and preparation for ash 1045 pond closures at the Company’s coal-fired plants in compliance with federal and 1046 state rules and permits including the Clean Water Act and the Resource 1047 Conservation and Recovery Act. As of the effective date of the 2016 IRP Order, 1048 Georgia Power was limited to annual capital expenditures of $1 million for Plant 1049 McIntosh Unit 1 and $5 million for Plant Hammond Units 1-4, and in fact spent 1050 less than those limitations in total. 1051 1052 Through the leadership of the Commission and collaboration with stakeholders, 1053 Georgia Power expects to have approximately 3.1 gigawatts (“GW”) of renewable 71 72 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 37 of 59 1054 resource capacity online by the end of 2021 through currently approved projects. 1055 The Company has continued its measured and proactive approach to acquiring 1056 new renewable resources. Georgia Power completed the 2018/2019 REDI RFP, 1057 procuring energy from 510 MW of utility scale solar resources through 1058 competitive bidding, with the resulting PPAs certified by the Commission in 1059 January 2018. Leveraging the reserve list from the 2018/2019 REDI RFP, the 1060 Company designed and implemented the C&I REDI program, which contracted 1061 for 177.5 MW of utility scale solar resources to supply the program. The 1062 Company issued the 2020/2021 REDI RFP in December 2018 seeking to procure 1063 540 MW of renewable resources and is currently evaluating the submitted bids. In 1064 addition, the Company launched the REDI Customer-Sited DG program in 1065 November 2017 to procure energy from 47.5 MW of distributed solar resources 1066 and issued the REDI DG RFP in July 2018 to purchase energy from 114.5 MW of 1067 distributed solar resources. 1068 1069 The Company also commenced the development of nine self-build projects 1070 totaling approximately 200 MW, including projects at military bases and 1071 universities, projects to supply the Community Solar program, and the Right-of- 1072 Way Solar project with The Ray. Additionally, the Company commenced 1073 development of up to 10 MW of solar demonstration projects planned for the 1074 closed ash ponds at Plant McDonough and Plant Hammond. 1075 1076Decision Making Flexibility. 1077 1078Q. PLEASE DESCRIBE THE STATUS OF GEORGIA POWER’S CURRENT 1079 SUPPLY-SIDE PLAN. 1080A. Georgia Power’s current supply-side plan as set forth in the 2019 IRP will 1081 economically provide capacity and energy to Georgia Power customers in a clean, 1082 safe, reliable and affordable manner. As described more fully below, the Company 73 74 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 38 of 59 1083 continues to take action to maintain the flexibility and reliability of its diverse 1084 fleet of supply-side generation resources. 1085 1086Q. WHY IS IT VITAL THAT THE COMPANY MAINTAIN A DIVERSE 1087 FLEET OF GENERATING RESOURCES? 1088A. Maintaining a diverse fleet of generating resources gives the Company the ability 1089 to utilize the lowest cost fuel options over the long term, reduce the volatility of 1090 retail electricity prices paid by customers, respond to changing system conditions 1091 and improve the overall reliability and resiliency of the electric system. A fleet 1092 that is over-reliant on one particular fuel source or operational characteristic 1093 would impose significant risk on customers with respect to the cost and 1094 availability of that particular fuel. By maintaining a diverse fleet of resources, the 1095 Company mitigates risk with respect to any particular fuel source by being able to 1096 shift between differing types of generation technologies in most hours of the year 1097 in order for customers to benefit from the lowest cost fuel option. 1098 1099 Not only are there economic benefits to a diverse fuel supply but there are also 1100 reliability benefits. Over-reliance on any one fuel type, fuel supply basin, or fuel 1101 transportation provider would subject customers to reliability and resiliency risks 1102 associated with the production or transportation of the fuel. Georgia Power 1103 enhances reliability for customers by maintaining diversity of generation options, 1104 fuel types, fuel source locations and fuel transportation providers. 1105 1106Q. WHEN IS GEORGIA POWER’S NEXT CAPACITY NEED? 1107A. The planned and committed resources included in the 2019 IRP provide for 1108 adequate reserves until 2028 at which point the Company is currently projected to 1109 have a capacity need based on projected load growth, expiration of PPAs, and the 1110 decertifications requested in this IRP. 1111 1112Q. 75 76 WHY DOES THE COMPANY NEED TO ISSUE TWO CAPACITY RFPS? Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 39 of 59 1113A. The Company may encounter a capacity need prior to 2028 due to potential future 1114 unit retirements. To satisfy capacity needs, maintain reliable electric service, and 1115 provide decision making flexibility, the Company plans to issue two capacity- 1116 based RFPs. The first RFP will seek resources that can provide capacity beginning 1117 in 2022-2023 (“2022-2023 RFP”), while the second RFP will seek resources that 1118 can provide capacity beginning in 2026-2028 (“2026-2028 RFP”) ahead of the 1119 Company’s currently forecasted capacity need. 1120 1121Q. WHAT ARE THE DRIVERS OF THE FIRST CAPACITY RFP? 1122A. The first capacity RFP is needed to provide Georgia Power with greater decision- 1123 making flexibility. In light of the economic challenges facing Plant Bowen Units 1124 1-2 in some scenarios, the Company intends to defer major investments in new 1125 infrastructure at these units to the extent practicable while maintaining existing 1126 infrastructure 1127 Consequently, to maintain reliability and fill a capacity need in the potential 1128 absence of these units, the Company intends to issue a capacity-based RFP, 1129 seeking resources that can provide capacity beginning in 2022 or 2023. In the 1130 event the market cannot provide adequate and economic capacity during the 1131 2022-2023 RFP, the Company intends to preserve the ability to continue operating 1132 Plant Bowen Units 1-2. for environmental compliance and operational readiness. 1133 1134Q. HOW MUCH CAPACITY WILL THE COMPANY SEEK TO PROCURE 1135 IN THE 2022-2023 RFP? 1136A. Details regarding the procurement will be determined once final outcomes of this 1137 IRP proceeding are determined. In the event Plant Bowen Units 1-2 are 1138 unavailable, the Company will likely need to procure a minimum of 1,000 MW in 1139 the 2022-2023 RFP based on assumptions contained in this IRP to replace the 1140 approximately 1,450 MW of capacity of Plant Bowen Units 1-2. 1141 1142Q. 77 78 WHAT ARE THE DRIVERS OF THE SECOND CAPACITY RFP? Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 40 of 59 1143A. The Company is requesting approval to issue a second capacity-based RFP which 1144 can provide capacity beginning in the 2026-2028 timeframe, ahead of the 1145 Company’s currently projected capacity need. The 2026-2028 RFP provides the 1146 Company sufficient time and flexibility to complete necessary transmission 1147 improvements and allow for a five-to-seven-year process for the evaluation of 1148 bids and permitting, engineering, procurement, construction, and start-up testing 1149 of a new capacity resource by the Company or market participants, should new 1150 construction prove to be in the best interests of customers. 1151 1152Q. HOW MUCH CAPACITY WILL THE COMPANY SEEK TO PROCURE 1153 IN THE 2026-2028 RFP? 1154A. Based on the assumptions in the 2019 IRP, the Company will encounter a capacity 1155 need in 2028 regardless of the potential future retirements of steam units beyond 1156 Plant Hammond Units 1-4 and Plant McIntosh Unit 1. This need grows 1157 substantially in the year 2030 due to the expiration of PPAs. Therefore, it is likely 1158 the Company will seek to procure more than 1,000 MW in the 2026-2028 RFP. 1159 This procurement strategy will allow the Company to meet capacity needs that 1160 could materialize as early as 2026 while also minimizing the large need projected 1161 in 2030. 1162 1163Q. WHAT IS THE COMPANY PLANNING TO DO WITH THE RESULTS OF 1164 THESE RFPS? 1165A. The Company will use the information and results of the two RFPs to inform the 1166 Company’s next IRP planning process and filing. If the RFPs present economic 1167 and beneficial opportunities to meet the needs of customers, the Company would 1168 likely bring selected resources from these RFPs before this Commission for 1169 certification, together with any unit retirement decisions, in its 2022 IRP. 1170 1171Q. WHAT RESOURCES WILL BE ELIGIBLE TO PARTICIPATE IN THE 1172 TWO CAPACITY RFPS? 79 80 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 41 of 59 1173A. Any resource capable of meeting the capacity and reliability requirements 1174 specified in the RFP, as determined by the Company in conjunction with the 1175 independent evaluator and Commission Staff, will be eligible to participate. The 1176 Company anticipates that potential resources will include combined cycle units, 1177 combustion turbines, and renewable resources combined with storage providing 1178 sufficient capacity and duration. 1179 1180Hydroelectric Investment and Certification of Goat Rock Capacity 1181 1182Q. WHY IS GEORGIA POWER INCREASING ITS INVESTMENT IN ITS 1183 HYDRO FLEET? 1184A. Georgia Power has conducted an extensive review of its hydro fleet and 1185 determined that numerous, essential components at several facilities are at or near 1186 the end of their useful lives and require additional investment beyond the 1187 Company’s normal level of investment to continue operation. The need for 1188 additional investment is demonstrated by recent performance issues, facility 1189 conditions, and operational experiences at several units. These investments will 1190 allow these resources to operate for at least another forty years while improving 1191 the efficiency, integrity, and safety of the hydro fleet and preserving valuable 1192 carbon-free resources for the long-term benefit of all customers. 1193 1194Q. WHY IS GEORGIA POWER INCREASING THE CAPACITY AT PLANT 1195 GOAT ROCK? 1196A. In its assessment of the hydro fleet, Georgia Power identified an opportunity at 1197 Plant Goat Rock to replace four aging turbines with updated turbine technology 1198 that will have more capacity, higher efficiency, and fewer maintenance 1199 requirements. The existing units, Units 3-6, need replacing due to performance 1200 issues and age. The units have been operational since 1915, 1920, 1955 and 1956, 1201 respectively. The upgraded turbines will increase capacity by nearly 50%, with 1202 the capacity of each unit increasing from 5 MW to 9.6 MW. 81 82 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 42 of 59 1203 1204 Additionally, the newer turbines will correct flow imbalances among the 1205 Chattahoochee River hydro fleet and provide critical capacity and dynamic 1206 reactive support to the local transmission system during peak periods. At its 1207 current size, there is a mismatch in discharge capability between Goat Rock and 1208 the other dams on the Chattahoochee – Bartletts Ferry, Oliver, and North 1209 Highlands Dams all discharge approximately 13,000 cubic feet per second (“cfs”), 1210 whereas Goat Rock can only discharge approximately 9,000 cfs at its present size. 1211 Georgia Power currently accommodates higher flow from the upstream dam by 1212 further drawing down Goat Rock Lake and running the units longer each day. If 1213 the lake were not drawn down further each day, then during the next day’s peak, 1214 Goat Rock would be inundated with peak flows from Bartletts Ferry and would 1215 have to spill water that does not get used to generate power. Increasing the 1216 capacity of the Goat Rock units will make daily operations more economical. 1217 1218Q. WHY IS GEORGIA POWER SEEKING CERTIFICATION OF THE 1219 CAPACITY UPGRADES AT PLANT GOAT ROCK? 1220A. In accordance with the O.C.G.A. § 46-3A-3, Georgia Power is required to obtain 1221 a certificate of public convenience and necessity or an amendment to a certificate 1222 prior to increasing the capacity of a generating unit of an electric power plant by 1223 more than 15%. Since the proposed upgrades at Plant Goat Rock will almost 1224 double the capacity of the units, Georgia Power is requesting certification of the 1225 new units and capacity increases for Plant Goat Rock Units 9-12. 1226 1227Decertification Requests 1228 1229Q. IS THE COMPANY PROPOSING TO DECERTIFY ANY GENERATION 1230 UNITS AS PART OF THE 2019 IRP? 1231A. Yes. The Company is requesting decertification of Plant Hammond Units 1-4, 1232 Plant McIntosh Unit 1, Plant Estatoah Unit 1, Plant Langdale Units 5-6, and Plant 83 84 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 43 of 59 1233 Riverview Units 1-2 (collectively, the “Retirement Units”), for a total 1234 decertification amount of 982.9 MW. The Company proposes that each unit be 1235 decertified effective as of the date of the Commission’s final order in this 2019 1236 IRP proceeding. 1237 1238Q. PLEASE EXPLAIN WHY THE COMPANY HAS REQUESTED 1239 DECERTIFICATION OF PLANT HAMMOND UNITS 1-4? 1240A. Plant Hammond Units 1-4 are coal-fired units with a total capacity of 840 MW. 1241 The economic analysis conducted as part of the URS indicates that continued 1242 operation of Plant Hammond Units 1-4, including the costs to comply with state 1243 and federal environmental regulations, is not economical or in the best interest of 1244 customers. 1245 1246Q. PLEASE EXPLAIN WHY THE COMPANY HAS REQUESTED 1247 DECERTIFICATION OF PLANT MCINTOSH UNIT 1? 1248A. The Company’s economic evaluations, combined with other operational 1249 considerations, led to the conclusion that retirement of Plant McIntosh Unit 1 is in 1250 the best interest of customers. 1251 85 86 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 44 of 59 1252Q. IS IT ECONOMIC TO CONTINUE OPERATIONS AT THE REMAINING 1253 COAL UNITS IN GEORGIA POWER’S FLEET? 1254A. Yes. While it is true that Georgia Power’s remaining coal units are not insulated 1255 from the economic challenges of low natural gas forecasts, modest load growth, 1256 and continued incremental environmental compliance costs, it is still economic to 1257 continue operations at the remaining coal fired units in the Company’s fleet in the 1258 majority of the nine scenarios evaluated. The remaining coal units are still needed 1259 to reliably serve customers and continue to provide meaningful benefits for 1260 customers. If any remaining coal units are retired, the Company would encounter 1261 an immediate capacity need. If these capacity needs are not fully addressed before 1262 additional retirements occur, customers would be exposed to significant reliability 1263 risk up to and including the curtailment of load. In this IRP, the Company 1264 discusses certain challenges faced by Plant Bowen Units 1-2 in certain scenarios, 1265 which has led the Company to pursue steps in this IRP to provide for needed 1266 flexibility in the future. 1267 1268Q. PLEASE ELABORATE ON THE POTENTIAL CHALLENGES FACED BY 1269 PLANT BOWEN UNITS 1-2. 1270A. Although Plant Bowen Units 1-2 continue to provide economic benefits to 1271 customers, they also face challenges. In higher gas price scenarios, Plant Bowen 1272 Units 1-2 remain economically competitive. However, these benefits diminish in 1273 moderate and low gas price environments while future carbon pressure may 1274 eliminate the economic upside of these units altogether. After reviewing these 1275 economic signals, the Company believes it is appropriate to delay or limit further 1276 investment at Plant Bowen Units 1-2 as described below. These steps balance the 1277 economic and reliability impacts associated with potential retirement while 1278 minimizing the risk associated with large capital investments. 1279 1280Q. ARE YOU REQUESTING DECERTIFICATION OF PLANT BOWEN 1281 UNITS 1-2? 87 88 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 45 of 59 1282A. No. Despite the economic challenges presented in some scenarios, the continued 1283 operation of Plant Bowen Units 1-2 is imperative to maintaining reliability, 1284 reducing exposure to generation shortfall and maintaining the resiliency of the 1285 system and in many cases continues to provide benefits to customers. 1286 1287Q. IS THE COMPANY TAKING STEPS TO MINIMIZE RISK TO 1288 CUSTOMERS OF FUTURE UNIT RETIREMENTS? 1289A. Yes. In recognition of the economic challenges facing Plant Bowen Units 1-2 in 1290 certain scenarios, the Company is taking steps to minimize future investment in 1291 these units. While some investment is required due to maintenance and 1292 environmental mandates, the Company intends to defer major retrofit projects and 1293 continue to optimize the units’ maintenance strategy so as to manage the near- 1294 term availability of these units. These steps mitigate the risk related to significant 1295 capital expenditures. Moreover, Georgia Power plans to initiate activities 1296 necessary to ensure the timely completion of the necessary transmission upgrades 1297 or equivalent solutions and take steps to enable decision making flexibility with 1298 regards to potential future retirements. 1299 1300Q. WHAT IS THE COMPANY REQUESTING IN THIS IRP TO PROVIDE 1301 FLEXIBILITY FOR THE FUTURE? 1302A. Based upon the retirement analysis performed by the Company, additional coal 1303 retirements beyond Plant Hammond Units 1-4 and Plant McIntosh Unit 1 would 1304 create an immediate capacity shortfall and jeopardize the reliability of the system. 1305 For the transmission system to accommodate potential future retirements beyond 1306 those recommended in this IRP, the Company must invest in transmission 1307 infrastructure beyond what is identified in the base 10-year transmission plan. 1308 1309Q. WHY ARE THESE PROJECTS NOT IN THE 10-YEAR TRANSMISSION 1310 PLAN? 89 90 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 46 of 59 1311A. The 10-year transmission plan evaluates the needs of the transmission system 1312 under current assumptions. These needs are evaluated based on NERC planning 1313 criteria and specifically identify projects to accommodate load growth as well as 1314 generation changes. As the Company is requesting decertification of Plant 1315 Hammond Units 1-4 and Plant McIntosh Unit 1, the 10-year plan incorporates 1316 that assumption. However, the Company is not requesting decertification of Plant 1317 Bowen Units 1-2 in this IRP. Therefore, the 10-year transmission plan does not 1318 assume retirement of these units. Instead, potential changes to the 10-year plan, as 1319 a result of retirement, are incorporated in the unit retirement study as benefits of 1320 keeping the existing unit. 1321 1322Q. PLEASE EXPLAIN WHY THE COMPANY HAS REQUESTED 1323 DECERTIFICATION OF THREE HYDRO UNITS? 1324A. The economic analyses for Plant Estatoah Unit 1, Plant Langdale Units 5-6, and 1325 Plant Riverview Units 1-2 show that continued operation of these units is no 1326 longer in the best interest of customers. Given the size, age and location of the 1327 units the Company anticipates minimal impact on the local transmission system. 1328 1329Renewable Resources 1330 1331Q. IS 1332 RENEWABLE RESOURCES AS PART OF THIS IRP? 1333A. Yes. Georgia Power will continue to expand its renewable portfolio using its 1334 steady and measured approach to procure renewable resources from both small 1335 and large-scale generators and implement customer-focused renewable energy 1336 programs. The Company plans to procure energy from an additional 1,000 MW of 1337 renewable resources through a competitive bidding process at prices below the 1338 Company’s projected avoided costs. The Company will target 950 MW of utility 1339 scale renewable resources through its CRSP program, which will be customer 91 92 THE COMPANY PROPOSING TO ACQUIRE ADDITIONAL Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 47 of 59 1340 focused and modeled after the C&I REDI program. The Company also proposes 1341 to procure 50 MW of DG resources. 1342 1343Q. PLEASE DESCRIBE THE CRSP PROGRAM. 1344A. The CRSP program will be designed to build upon the success of the C&I REDI 1345 program, matching procurement efforts with customer subscriptions. On the 1346 procurement side, Georgia Power proposes to contract for energy from up to 950 1347 MW from utility scale renewable resources greater than three MW alternating 1348 current (“AC”) in size, at prices below projected avoided costs. The Company 1349 intends to issue two RFPs, the 2022 Renewable RFP and the 2024 Renewable 1350 RFP, to procure these utility scale renewable resources that will achieve 1351 commercial operation by 2022 and 2024, respectively. The Company will select 1352 the resources that produce the greatest total net benefit for customers when 1353 compared to Georgia Power’s projected avoided costs utilizing the RCB 1354 Framework. 1355 1356 The Company will take ownership of all renewable energy credits (“RECs”) and 1357 other environmental attributes produced by these facilities, to retire either on 1358 behalf of the CRSP participants and/or all Georgia Power customers. Bid fees will 1359 be established to recover RFP-related administrative and technical evaluation 1360 costs incurred by the Company. The Company will work with Commission Staff 1361 and interested stakeholders to further develop the timeline for the RFPs. As 1362 authorized by statute, the Company requests to receive a levelized additional sum 1363 of 10% of the net present value of projected benefits from the PPAs. 1364 1365 For customers, the energy produced from the renewable resources procured 1366 through CRSP will be available for subscription by both new and existing 1367 commercial and industrial customers. The Company seeks to satisfy the growing 1368 demand from customers who wish to support renewable energy by offering 1369 existing customers with aggregated load greater than three MW the opportunity to 93 94 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 48 of 59 1370 subscribe to a portfolio of up to 500 MW of new renewable resources. 1371 Additionally, to attract large companies with renewable energy goals who desire 1372 to relocate or expand operations in Georgia, the Company will offer up to 450 1373 MW of new renewable resources for subscription by customers with incremental, 1374 new load additions greater than 25 MW. 1375 1376 Similar to the C&I REDI program, participating customers will enter into a 1377 customer agreement specifying the pricing, terms, and conditions of their 1378 participation in the CRSP tariff. The Company will credit participating customers 1379 based on the actual hourly marginal energy cost of incremental generation 1380 multiplied by the amount of energy produced by the CRSP facilities during those 1381 hours. The monthly fee to participate in CRSP will be in addition to the 1382 customer’s regular monthly electric service payments. Concurrent with the two 1383 renewable RFPs, interested customers will be given the opportunity to submit a 1384 Notice of Intent (“NOI”) identifying their proposed subscription level in MW, 1385 contract term length, and other requirements related to their interest in the 1386 program. The Company proposes a required NOI participation fee to offset the 1387 costs of pre-program implementation. Detailed elements of the CRSP Program 1388 will be shared and approved through a subsequent filing after the 2019 IRP 1389 process concludes. 1390 1391Q. HOW WILL THE TWO CRSP RENEWABLE RFPS BE STRUCTURED? 1392A. In each of the two CRSP renewable RFPs, the Company will target the 1393 procurement of energy from 250 MW of resources for existing customers. The 1394 Company will also target up to 450 MW in the first renewable RFP to match the 1395 requested renewable energy from new customers who provide notice of their 1396 interest to Georgia Power through the NOI process. Any portion of the 450 MW 1397 allocated for new customers not subscribed through the first renewable RFP will 1398 be rolled forward and made available through the second renewable RFP. 1399 95 96 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 49 of 59 1400Q. WHAT ARE THE CUSTOMER QUALIFICATION CRITERIA TO 1401 PARTICIPATE IN CRSP? 1402A. Existing commercial and industrial customers with a minimum annual peak 1403 demand of three MW at one account (or an aggregate of GPC accounts under 1404 common control) may participate and can subscribe in an amount up to 100% of 1405 their preceding year’s total annual energy consumption for each of the customer’s 1406 qualifying premises aggregated to meet the eligibility criteria. Additionally, 1407 prospective economic development customers choosing to expand or locate new 1408 facilities in Georgia that add incremental new load of 25 MW or greater are 1409 eligible to participate under the same subscription criteria, based on projected 1410 energy consumption. 1411Q. WHAT HAPPENS IF THE CUSTOMER SUBSCRIPTION LEVELS 1412 EXCEED OR FALL SHORT OF THE ANTICIPATED CAPACITY? 1413A. Consistent with the methodology used in the C&I REDI program, if the level of 1414 existing customer capacity interest exceeds the available MW for each 1415 solicitation, Georgia Power will allocate subscriptions pro rata among 1416 participating customers who complete the NOI process. If any portion of the total 1417 950 MW of renewable capacity is not subscribed by participating customers 1418 (whether existing or new), Georgia Power will procure the capacity difference to 1419 serve all Georgia Power customers. 1420 1421Q. HOW WILL ALL CUSTOMERS BENEFIT FROM RENEWABLE 1422 RESOURCES PROCURED THROUGH THE CRSP PROGRAM? 1423A. All customers will benefit from the projected energy savings provided by the 1424 added renewable resources on the System over the term of the PPAs. Participating 1425 customers will subscribe to CRSP over the specified term of their customer 1426 agreements, covering the cost of the PPAs during the early part of the term of the 1427 supplying PPAs when the Company’s avoided costs are projected to be lower than 1428 in the latter part of the term. When the subscribing customer agreements terminate 1429 or expire, the energy savings and associated RECs will become available to serve 97 98 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 50 of 59 1430 all of Georgia Power’s customers at a time when savings from the supplying PPA 1431 are projected to be higher than earlier years. 1432 1433Q. PLEASE DESCRIBE THE DG RFP. 1434A. The Company intends to issue an RFP for renewable DG resources sized less than 1435 or equal to three MW AC. The Company will procure these resources through a 1436 competitive RFP at prices below Georgia Power’s projected avoided costs using 1437 the RCB Framework. The Company requests to receive a levelized additional sum 1438 of 10% of the net present value of projected benefits realized from the PPAs. As 1439 with the utility scale RFP, bid fees will be established to recover administrative 1440 and implementation costs incurred by the Company and the Company will take 1441 ownership of all RECs and other environmental attributes produced by these 1442 facilities. 1443 1444Q. ARE THESE PROGRAMS THE ONLY OPTIONS AVAILABLE FOR 1445 CUSTOMERS TO SUPPORT RENEWABLE RESOURCES? 1446A. No. As stated in the IRP, the Customers will continue to have the option to sell 1447 renewable energy to Georgia Power as Qualifying Facilities (“QF”) under the 1448 Public Utility Regulatory Policies Act of 1978 (“PURPA”). In addition, customers 1449 can sell the output of solar photovoltaic, fuel cell, or wind turbine distributed 1450 generation facilities through the renewable and non-renewable (“RNR”) tariff. 1451 Georgia Power has interconnected more than 2,000 solar projects, including 1452 customers who choose to offset energy usage with behind-the-meter solar 1453 installations, through RNR or as a QF. Customers can also participate in the 1454 Company’s Community Solar and Simple Solar programs. 1455 1456Q. WHY IS THE COMPANY PROCURING MORE UTILITY SCALE 1457 RESOURCES THAN DG RESOURCES? 99 100 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 51 of 59 1458A. The Company’s experience shows that utility scale resources leverage economies 1459 of scale to produce significantly more total net benefits than DG resources and 1460 therefore are a better value for Georgia Power’s customers. 1461 1462Q. WILL GEORGIA POWER CONTINUE TO USE THE RCB 1463 FRAMEWORK? 1464A. Yes. The Company will continue to apply the RCB Framework to the evaluation 1465 of renewable projects and pricing for the new procurement programs offered in 1466 the 2019 IRP. 1467 1468Q. DID GEORGIA POWER MAKE ANY CHANGES TO THE RCB 1469 FRAMEWORK AS PART OF THE 2019 IRP? 1470A. Although no new components are recommended for inclusion in the RCB 1471 Framework at this time, the Company made several improvements to the RCB 1472 Framework document in the 2019 IRP to provide additional clarity, consolidate 1473 and simplify where appropriate, and to document the history of the RCB 1474 Framework since the 2016 IRP. The Company has also moved one component 1475 from “Placeholder” status to “Exclude” status. In addition to the RCB Framework 1476 document, the Company has filed three additional documents that provide 1477 illustrative quantifications of the costs and benefits (excluding acquisition costs) 1478 of DG solar, utility scale fixed tilt solar, and fixed and variable wind delivered to 1479 Georgia. 1480 1481Q. IS THE COMPANY PROPOSING ANY OTHER CHANGES TO ITS 1482 RENEWABLE PROGRAMS? 1483A. Yes. As customer interest in the Simple Solar program continues to grow, Georgia 1484 Power has identified the need for greater flexibility for large customers. The 1485 Company proposes to revise the Simple Solar Tariff Large Volume Purchase 1486 Option pricing to change the 0.5¢ per kWh per month tier for the next 1,650,000 1487 kWh of RECs and add a new additional pricing tier where all remaining kWh of 101 102 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 52 of 59 1488 RECs exceeding that amount to be priced at the current REC market price offer at 1489 the time of contract. The additional market pricing tier is designed to continue to 1490 collect the full administrative costs of the program while preserving the ability to 1491 offer more competitively-priced solar RECs for energy-intensive users. 1492Battery Energy Storage System 1493 1494Q. WHAT IS THE COMPANY’S BATTERY ENERGY STORAGE SYSTEM 1495 PROPOSAL? 1496A. The Company proposes to develop a total of 50 MW of energy storage capacity to 1497 evaluate the technical and economic performance of battery energy storage 1498 systems (“BESS”) relative to expectations, including the ability to use BESS for 1499 multiple applications as part of the Company’s generation fleet. More specifically, 1500 the Company intends to install BESS in at least two separate applications, one 1501 independently sited and one located at or near a solar facility. 1502 103 104 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 53 of 59 1503Q. WHAT DOES THE COMPANY HOPE TO LEARN FROM THESE BESS 1504 FACILITIES? 1505A. Due to technical performance advancements and projected cost reductions, BESS 1506 can be a solution to address a wide range of challenges related to the generation 1507 and delivery of electric power across the grid. Through these BESS deployments, 1508 Georgia Power intends to: track and validate operational and performance 1509 capability of the systems in a real-time environment; examine integration of 1510 storage technology, operating assumptions, and development costs as part of new 1511 build resources; more fully evaluate the benefits and costs of combinations of 1512 resources, such as solar plus battery storage; and obtain operational and 1513 performance analytics to inform and refine operation and maintenance practices. 1514 Therefore, the Company seeks approval to acquire, own, and implement these 1515 BESS projects to advance its understanding of storage capabilities while 1516 providing real-world operating experience to better integrate future storage 1517 projects. 1518 1519 VI. WHOLESALE TO RETAIL CAPACITY 1520 1521Q. WHY IS THE COMPANY OFFERING 25 MW OF PLANT SCHERER TO 1522 RETAIL CUSTOMERS? 1523A. Approximately 25 MW of Plant Scherer Unit 3 capacity is currently under a 1524 contract with Flint EMC that will expire on December 31, 2019. Pursuant to the 1525 Commission’s July 30, 2008 Order in Docket No. 26550, Georgia Power is 1526 offering the 25 MW of capacity to the retail jurisdiction to serve retail customers 1527 when the capacity becomes available on January 1, 2020. 1528 105 106 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 54 of 59 1529Q. HAS THE COMPANY PREVIOUSLY MADE WHOLESALE CAPACITY 1530 OFFERS TO RETAIL JURISDICTION? 1531A. Yes. Since the July 2008 Order has been in place, the Commission has previously 1532 certified several offers to bring resources to the retail jurisdiction, including 1533 resources at Plant Scherer Unit 3 and resources from Wholesale Blocks 1 through 1534 6. The multiple wholesale offerings to the retail jurisdiction have resulted in a 1535 range of Market Differential Adjustments (“MDA”) based on the generation 1536 resource(s) involved and the wholesale conditions present at the time. 1537 1538Q. HOW DOES GEORGIA POWER VALUE OR PRICE THE CAPACITY 1539 BEING OFFERED TO RETAIL JURISDICTION? 1540A. Consistent with prior wholesale offers, Georgia Power proposes to use the 1541 Commission-approved application of an MDA to meet the requirement that the 1542 transaction be offered at then-current wholesale market terms. The MDA 1543 represents the difference between the market price and the levelized revenue 1544 requirement of the net asset over its remaining useful life, expressed on a dollar 1545 per kilowatt-month basis. 1546 1547Q. WHY IS THE COMPANY ALSO SEEKING TO CERTIFY THIS 1548 CAPACITY? 1549A. The Company believes it is appropriate to take this opportunity to acquire 1550 additional capacity from the Company’s most economical coal resource, Plant 1551 Scherer, considering the loss of significant coal capacity in the past several years, 1552 and the current request to decertify additional coal capacity at Plants Hammond 1553 and McIntosh in this IRP. Further, Georgia Power’s offer of the 25 MW wholesale 1554 capacity to retail aligns with the Company’s plan to maintain fuel diversity for the 1555 benefit of retail customers. 1556 107 108 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 55 of 59 1557Q. WILL THIS ADDED CAPACITY BE INCLUDED IN RATES? 1558A. Yes. The generating assets supporting the capacity will be included in retail rate 1559 base at their net book value using the MDA to determine the associated revenue 1560 requirement rather than using a traditional revenue requirement calculation. 1561 Following the MDA methodology previously approved by this Commission 1562 results in a reduction to the retail base revenue requirement associated with the 1563 current offer as compared to the revenue requirement as calculated under 1564 traditional ratemaking. As with other generating assets in retail rate base, all 1565 prudently incurred actual fuel costs associated with the resource will be recovered 1566 through the fuel cost recovery process. 1567 1568Q. WHAT VALUE WILL PROCURING THESE 25 MW OF SCHERER 1569 UNIT 3 BRING TO CUSTOMERS? 1570A. These 25 MW represent added capacity from the Company’s most economic coal 1571 resource, which is already reliably serving Georgia Power’s customers. Returning 1572 this capacity to retail jurisdiction will offer customers additional access to a 1573 resource with a stable, low cost fuel supply, resulting in an attractive variable cost 1574 with a significantly discounted fixed cost, allowing the Company to continue to 1575 serve customers from a diverse fleet of generation resources that rely on fuel 1576 supply basin diversity. Customers will benefit from the diversity of the fuel type 1577 given the retirement of older coal units in this IRP. 1578 1579 VII. TRANSMISSION 1580 1581Q. PLEASE DESCRIBE GEORGIA POWER’S TRANSMISSION PLAN 1582 FILED IN THE 2016 IRP. 1583A. This IRP includes the Company’s updated ten-year transmission plan, which 1584 identifies the transmission improvements needed to maintain a strong and reliable 1585 transmission system. The development of this plan is conducted in accordance 1586 with the Southern Company and Georgia Integrated Transmission System (“ITS”) 109 110 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 56 of 59 1587 transmission planning guidelines and with the most current NERC planning 1588 standards. Along with the ten-year plan, Georgia Power has included a 1589 comprehensive and detailed bulk transmission plan of the Georgia ITS as required 1590 by the amended rules adopted by the Commission in Docket No. 25981. 1591 Additional transmission information is also provided as required by Docket No. 1592 31081. 1593 1594 VIII. EMERGING RESILIENCE NEEDS 1595 1596Q. WHAT IS RESILIENCE? 1597A. Resilience refers to the ability of the electric system to withstand or recover from 1598 high impact events with a low probability such as physical attacks, cyber-attacks, 1599 and extreme weather events. In addition to the ability to reliably provide 1600 customers with the quantity and quality of power demanded, resilience addresses 1601 the ability of the system and utilities to reduce magnitude, duration and damage 1602 from high impact disruptive events. A lack of resilience can impede a utility’s 1603 ability to reliably serve customers under these conditions. 1604 1605Q. WHY IS GEORGIA POWER INCLUDING A DISCUSSION 1606 EMERGING RESILIENCE NEEDS IN ITS IRP? 1607A. As society becomes increasingly reliant on electric energy, the Company remains 1608 committed to maintaining a robust and resilient electric system that is capable of 1609 reliably delivering electric service, even in the face of unexpected events such as 1610 natural and man-initiated disruptions. The Company has an excellent track record 1611 of managing and planning for reliability risk through its reserve margin process, 1612 transmission planning analysis, and similar reliability studies, while also 1613 demonstrating substantial commitment to infrastructure protection initiatives. 1614 However, the energy industry is changing and how the Company generates 1615 electricity and operates its fleet is evolving. 1616 111 112 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 57 of 59 OF 1617 For example, at the bulk power system level, the Company routinely evaluates 1618 various contingencies as part of its Transmission Planning process and proposes 1619 projects to mitigate the risks associated with these contingencies when in the best 1620 interest of customers. This level of planning meets or exceeds current NERC 1621 standards. However, as the Company’s generation resource mix continues to 1622 change, utilizing less coal and more renewables and gas generation, continued 1623 transmission planning considerations must be given to these changing conditions 1624 to ensure future reliability and resilience of the bulk power system. This may 1625 require additional assessments of contingencies for the Company to study. Such 1626 assessments should focus on the simultaneous failure of multiple elements of the 1627 electricity supply chain such as transmission substations, gas pipelines, 1628 communication infrastructure, and generating stations. When in the best interest 1629 of customers, the Company may propose future projects based on these 1630 assessments to minimize or eliminate the potential for high-impact outcomes that 1631 may not otherwise be required or proposed under the existing NERC planning 1632 standards. 1633 113 114 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 58 of 59 1634Q. ARE THESE TYPES OF RESILIENCE RISKS INCLUDED IN THE 1635 RESERVE MARGIN STUDY? 1636A. Although the Company regularly evaluates generation risks (e.g. outage risk, 1637 weather risk, and fuel transportation risk) in its Reserve Margin Study, this study 1638 does not focus on other potential long duration, high impact events. Rather, the 1639 objective of the Reserve Margin Study is to establish the Target Reserve Margin 1640 that maintains reliable and affordable service across a range of possible futures 1641 that represent anticipated recurrence of past variations in weather, loads, and unit 1642 performance. 1643 1644Q. WILL RESILIENCE BE CONSIDERED IN FUTURE RETIREMENT 1645 DECISIONS? 1646A. The Company’s scenario resource planning process has resulted in multiple 1647 retirements that are in the best economic interests of customers. As future coal 1648 unit retirements remain a possibility, the Company will need to balance the 1649 economic benefits of retirement and the ability to take advantage of low-cost gas 1650 commodity prices against the potential resilience risk associated with gas fuel 1651 supply. Striking the right balance requires consideration of numerous options such 1652 as energy storage, inactive reserve, or fuel storage, which may preserve on-site 1653 fuel while minimizing spend. These items could prove to be an important 1654 resilience consideration with respect to potential retirement decisions in future 1655 IRPs. 1656 1657Q. IS THE COMPANY REQUESTING APPROVAL FOR ANY SPECIFIC 1658 RESILIENCE ENHANCEMENTS? 1659A. No. The Company is not requesting specific resilience enhancements in this IRP 1660 related to high impact low probability events. However, the growing threat of 1661 these risks and the transition of the generating fleet compels the Company to 1662 consider these risks and, where appropriate, propose projects for the 1663 Commission’s consideration. 115 116 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 59 of 59 1664 IX. ACCOUNTING TREATMENT AND COST RECOVERY 1665 1666Q. PLEASE DESCRIBE THE ACCOUNTING TREATMENT BEING 1667 REQUESTED BY THE COMPANY TO RECLASSIFY THE NET BOOK 1668 VALUE OF PLANT HAMMOND UNITS 1-4 AS OF THE RETIREMENT 1669 DATE TO A REGULATORY ASSET ACCOUNT. 1670A. The Company proposes to reclassify the Plant Hammond Units 1-4 net book value 1671 remaining on the proposed retirement date to a regulatory asset account. The 1672 regulatory asset would be amortized ratably over a period equal to the respective 1673 unit’s remaining useful life, as approved by the Commission in Docket No. 1674 36989. 1675 1676Q. PLEASE DESCRIBE THE ACCOUNTING TREATMENT BEING 1677 REQUESTED BY THE COMPANY TO RECLASSIFY THE NET BOOK 1678 VALUE OF PLANT MCINTOSH UNIT 1, PLANT ESTATOAH UNIT 1, 1679 PLANT LANGDALE UNITS 5-6, AND PLANT RIVERVIEW UNITS 1-2 AS 1680 OF THEIR RESPECTIVE RETIREMENT DATES TO A REGULATORY 1681 ASSET ACCOUNT. 1682A. The Company proposes to reclassify the net book value of Plant McIntosh Unit 1, 1683 Plant Estatoah Unit 1, Plant Langdale Units 5-6 and Plant Riverview Units 1-2 1684 remaining on the respective retirement dates to a regulatory asset account. The 1685 regulatory asset would be amortized ratably over a three-year period in the 1686 Company’s next base rate case. Due to the projected net book value of these units, 1687 the Company believes a shorter recovery period is appropriate. 1688 1689Q. PLEASE 1690 REQUESTED BY THE COMPANY TO RECOVER THE REMAINING 1691 MATERIALS AND SUPPLIES INVENTORY BALANCES ASSOCIATED 1692 WITH THE RETIREMENT UNITS. 117 118 DESCRIBE THE ACCOUNTING TREATMENT Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 60 of 59 BEING 1693A. The Company proposes to reclassify any unusable material and supplies inventory 1694 balance remaining at the unit retirement dates to a regulatory asset for recovery 1695 over a period to be determined by the Commission in the Company’s next base 1696 rate case. This proposal is consistent with the treatment of the remaining material 1697 and supplies inventory balances from the 2016 IRP Final Order. While the 1698 Company will take appropriate steps to find uses for existing inventory, including 1699 the sale of such inventory, it is reasonable to expect there will be some inventory 1700 that cannot be sold or used at other Georgia Power generating plants. 1701 1702Q. IS THE COMPANY SEEKING APPROVAL OF ANY ENVIRONMENTAL 1703 COMPLIANCE COSTS? 1704A. Yes. The Company’s environmental panel of Dr. Mark S. Berry and Aaron D. 1705 Mitchell address Georgia Power’s request regarding approval of environmental 1706 compliance costs in their direct testimony. 1707 1708 X. CONCLUSION 1709 1710Q. WHAT IS GEORGIA POWER REQUESTING OF THE COMMISSION IN 1711 THE 2019 IRP? 1712A. The Company seeks approval of its 2019 IRP including the associated Action 1713 Plan, which include all the actions necessary for the Company to continue to 1714 provide clean, safe, reliable, and affordable electric service for its retail 1715 customers. 1716 1717Q. DOES THIS CONCLUDE YOUR TESTIMONY? 1718A. Yes. 119 120 Direct Testimony of Jeffrey R. Grubb, Narin Smith, Michael A. Bush, and Jeffrey B. Weathers On behalf of Georgia Power Company Docket Nos. 42310 & 42311 Page 61 of 59