Integrated Resource Plan Summary Report

Transcription

1 2016 Integrated Resource Plan Summary Report

2 Alabama Power Company 2016 Integrated Resource Plan Summary Report EXECUTIVE SUMMARY I. INTRODUCTION II. ENVIRONMENTAL STATUTES AND REGULATIONS II.A. General II.B. Air Quality II.C. Water Quality II.D. Coal Combustion Residuals II.E. Global Climate Issues III. INTEGRATED RESOURCE PLAN III.A. Process Overview III.B. Load Forecast III.C. Fuel Forecast III.D. Reserve Margin III.E. Resource Options III.F. Summary of Results IV. CONCLUSION APPENDIX Integrated Resource Plan - Existing Supply-Side Resources Figure A1-1: Alabama Power Existing Generating Resources. A1-1 i

3 EXECUTIVE SUMMARY The Alabama Power Company ( Alabama Power or Company ) 2016 Integrated Resource Plan ( 2016 IRP ) serves as the foundation for certain decisions affecting the Company s portfolio of supply-side and demand-side resources. Like prior IRPs, the 2016 IRP is a management tool that facilitates the Company s ability to provide reliable and cost-effective electric service to customers, while accounting for the risks and uncertainties inherent in planning for resources sufficient to meet expected customer demand. The 2016 IRP was developed and finalized at the end of In this 2016 IRP Summary Report (which overviews the complex and data intensive IRP process), the Company continues to recognize evolving market and regulatory conditions, so as to position the Company to respond to future developments, all for the benefit of customers. As a product of the Company s exhaustive planning process, the 2016 IRP represents a comprehensive plan and serves as the basis on which the Company can confidently manage its reliable and diverse portfolio of supply-side and demand-side resources and offer electricity service at rates below the national average. In this respect, the 2016 IRP continues the Company s commitment to providing customers a diverse supply-side generating portfolio. Resource diversity, which for Alabama Power includes nuclear, natural gas, coal, oil, hydroelectric, wind, and biomass resources, provides significant benefit to customers as it enables the Company to adapt more readily to changing economic and regulatory conditions. In fact, the Company considers it vital to maintain a diverse supply-side generating portfolio, given the inherent uncertainty of the future and the potential for rapid changes in the economic and regulatory landscape impacting energy supply. The 2016 IRP provides flexibility for the benefit of customers. As the Alabama Public Service Commission ( APSC or Commission ) is well aware, one of the key issues facing the Company at this time is the U.S. Environmental Protection Agency s ( EPA ) Clean Power Plan ( CPP ), which was published in final form on October 23, The CPP, which calls for the establishment of significant restrictions relating to carbon dioxide ( CO 2 ) emissions from electric generating units, stands to significantly impact the Company s 1

4 customers, as well as the customers of other electricity suppliers in Alabama, if the rule is implemented in its current form. At this time, however, there is much uncertainty with the CPP. On February 9, 2016, the U.S. Supreme Court granted a stay of the CPP, pending disposition of petitions for its review with the U.S. Court of Appeals for the District of Columbia Circuit ( D.C. Circuit ). The stay will remain in effect through the resolution of the litigation, whether resolved in the D.C. Circuit or the Supreme Court. In view of this judicial activity, the Company must consider the potential for the rule to be overturned or substantially modified, as well as the possibility of its being upheld. Compounding this uncertainty is the fact that the CPP does not apply directly to electric generating units, but instead must be implemented through the development of a State Implementation Plan ( SIP ) by the Alabama Department of Environmental Management ( ADEM ). While SIPs were due September 6, 2016, even prior to the Supreme Court s stay, ADEM had indicated its intent to request a two-year extension. Many state plan pathways are available under the CPP. Given these possibilities, and accounting for the extensive analysis and coordination that must take place before the SIP is completed by ADEM and submitted to EPA for approval, the Company does not at this time have a CPP compliance plan or otherwise definitively know the compliance implications for it and its customers. Thus, the 2016 IRP does not reflect CPP compliance impacts. While the Company has not yet developed a CPP compliance plan, this IRP reflects a continuation of the Company s efforts to have the system in a position to reasonably adapt to a carbon constrained future. Since the 2013 IRP, the Company has removed the Barry 3 and Gorgas 6-7 coal units from service. As part of its MATS compliance strategy, it also has transitioned Greene County 1-2, Gaston 1-4, Barry 1-2 and Gadsden 1-2 from coal operation to operation on natural gas. The remainder of the Company s coal-fired generating units continues to provide substantial economic benefit for customers. Consistent with the 2013 IRP, the Company continues to explore adding to its generation mix renewable resources that are projected to bring benefits to customers. This strategy is evidenced by the Company s procurement and development of over 400 MW of renewable energy over the previous six years. Under these projects, the Company has rights to the environmental attributes, 2

5 including the renewable energy certificates ( RECs ), associated with the energy. Alabama Power can retire some, or all, of these environmental attributes on behalf of its retail electric customers or it can sell the environmental attributes, either bundled with energy or separately, to third parties. The Company s renewable resource strategy also now reflects recent action by the APSC. On September 16, 2015, the APSC issued a certificate of convenience and necessity in Docket No authorizing the Company to develop or procure up to 500 MW of capacity and energy from renewable energy and environmentally-specialized generating resources. Under the certificate, Alabama Power is not required to develop or procure the entire 500 MW block of resources. Rather, projects must satisfy certain specified eligibility criteria. First, the project must involve a renewable energy resource (such as those identified in Alabama Code (30)) or an environmentally specialized generating resource (such as combined heat and power), and be no larger than 80 MW (measured in alternating current (AC) terms). Second, the project must meet certain economic benefits criteria, namely, that it is expected to result in a positive economic benefit for all of Alabama Power s customers. Further, total projects submitted and approved under the 500 MW certificate authority in any one given calendar year cannot exceed 160 MW without prior authorization from the Commission. In addition, any unexercised authority under the certificate expires after six years. Pursuant to the certificate authority in Docket No , the APSC has since approved three solar projects. Specifically, on December 14, 2015, the APSC authorized Alabama Power to construct and own two solar facilities at army installations served by the Company, which are expected to go into commercial operation on or before December 31, Additionally, on June 9, 2016, the APSC approved a power purchase agreement ( PPA ) for the output of a solar facility near the town of LaFayette in Chambers County, which is expected to go into commercial operation on or before December 31, These solar projects will be reflected in subsequent IRPs. Alabama Power will receive all energy and associated RECs generated by these projects, which it may use to serve its customers with solar energy or sell to third parties for the benefit of customers. The Company will continue to consider and evaluate other projects that would satisfy the criteria set forth in the Commission s certificate order. Recently, a new Reserve Margin Study was completed for the Southern Company electric system ( System ). The detailed analysis reflected in that study supported the conclusion that the long- 3

6 term (i.e., greater than three years) target planning reserve margin should be increased from the percent target to percent while the short-term (i.e., less than three years) target planning reserve margin should be increased from percent to percent. This was the result of a number of factors, including the predicted effects of extreme cold weather events, customer demand trends, and the penetration of intermittent renewable resources on the System. Due to the benefits of load diversity, coordinated planning and operations, and the ability to share resources, the Southern Company retail operating companies can together achieve these System targets by each utilizing diversified reserve margins that are lower than the target margins for the System. Using the current diversity factor, the Company s diversified targets corresponding to the new long-term and short term System targets are and percent, respectively. Figure ES-1 compares the previous planning reserve margin targets to those predicated on the new Reserve Margin Study. FIGURE ES-1: Planning Reserve Margin Target Comparison Previous Reserve Margin Study Updated Reserve Margin Study System Long-Term Planning Reserve Margin Target 15.00% 16.25% System Short-Term Planning Reserve Margin Target 13.50% 14.75% Diversified Long-Term Planning Reserve Margin Target 13.47% 14.74% Diversified Short-Term Planning Reserve Margin Target 11.99% 13.26% Since the 2016 IRP was developed and finalized prior to the completion of the new Reserve Margin Study, the analysis underlying this 2016 IRP was predicated on the then existing and percent System target planning reserve margins. Consistent with the results of the new Reserve Margin Study, Alabama Power has begun utilizing, for internal planning purposes, a percent long-term System planning reserve margin target and a short-term System planning reserve margin target of percent. Absent further adjustments prompted by the various factors impacting the system reserve margin, the newly revised reserve margin targets will be reflected in future IRPs. 4

7 Demand-side management ( DSM ) represents an important ingredient in meeting customers needs in a reliable and cost-effective manner. However, due to lower avoided costs driven primarily by natural gas prices and the slow pace of economic recovery in the state, the introduction of new cost-effective DSM programs is more challenging. Nevertheless, the Company believes there is value in continuing to identify and offer viable DSM programs, including the potential benefits that such programs may bring for purposes of compliance with present and future environmental requirements. Based on the load forecast developed by the Company for the 2016 IRP, Alabama Power s customer electrical requirements can be met reliably with the Company s current supply-side and demand-side resources until 2035, at which time there is an indicated need to add intermediate generating capacity to reliably meet projected demand. Although the Company currently does not foresee the addition of any new, reliability-driven generating capacity until 2035, the Company will continue to employ a strategy of identifying renewable resources and demand-side options that are projected to bring benefits to customers. If and when such resources are identified, the Company will seek authorization from the APSC for procurement or development rights related to same. A number of factors could influence the timing of the Company s next capacity need and cause it to accelerate from 2035, perhaps significantly. The most impactful of these would be the retirement of existing generation in response to new environmental rules and requirements. Other influencing factors include movement to a higher long-term planning reserve margin, the addition of new customers, faster customer demand growth, and changes in demand-side management programs. Future IRPs can be expected to appropriately reflect the impacts of all such events and developments. The 2016 IRP is in furtherance of Alabama Power s goal of providing customers with short- and long-term electric service, reliably and in an economically efficient manner, through a diverse portfolio of supply-side and demand-side resources. The Company has developed a costeffective and balanced resource strategy while maintaining environmental compliance flexibility for the benefit of customers. As a result, the Company is well-positioned to serve increases in customer demand over the 20-year planning horizon. The Company believes the plan charts a 5

8 measured course in meeting customer demand in a dynamic regulatory environment, while also maintaining rates below the national average. 6

9 I. INTRODUCTION Alabama Power is an investor-owned electric utility, organized and existing under the laws of the State of Alabama, and is a subsidiary of the Southern Company. Alabama Power is primarily engaged in generating, transmitting and distributing electricity to the public in a large section of Alabama, and its retail rates and services are regulated by the APSC. The Company has approximately 1.46 million customers, of which approximately 86 percent (1.25 million) are residential; 13.5 percent (198,000) are commercial; and 0.5 percent (6,800) are industrial and other. Alabama Power has approximately 1.56 million transmission and distribution poles, and approximately 84,000 miles of wire. The Company strives to maintain cost-effective and reliable service to its customers. For the years , the Company had a service reliability of percent. Alabama Power has a diverse mix of, both owned and contracted, supply-side and demand-side resource options, including hydroelectric, natural gas, nuclear, coal, oil, renewable i, combined heat and power, DSM programs and other resources. As of December 31, 2015, Alabama Power operated 78 Company-owned generating units (20 fossil steam, 41 hydroelectric, 2 nuclear, 5 combined cycle, and 10 combustion turbine) with a generating capability of approximately 12,300 MW, as recognized in the 2016 IRP. Of the energy delivered from Company-owned units for year 2015, 54.6 percent was sourced from coalfired resources, 23.2 percent from nuclear, 6.1 percent from hydroelectric, and 16.1 percent from gas and oil. Additionally, the Company has contractual rights to the output of other resources totaling over 1,000 MW of IRP recognized capacity. A detailed list of the Company s existing supply-side resources is shown in Appendix 1 in Figure A1-1. The purpose of this document is to summarize the results of Alabama Power s 2016 IRP and to describe the process used in its development. The IRP serves as the foundation for certain decisions affecting the Company s portfolio of generating resources. Like those IRPs preceding it, the 2016 IRP facilitates the Company s ability to provide reliable and cost-effective electric i As mentioned previously, and applicable to all references of renewable projects in the 2016 Integrated Resource Plan Summary Report, the Company has rights to the environmental attributes, including the renewable energy certificates ( RECs ), associated with the energy from these projects. Alabama Power can retire some, or all, of these environmental attributes on behalf of its retail electric customers or it can sell the environmental attributes, either bundled with energy or separately, to third parties. 7

10 service to its customers, while accounting for the risks and uncertainties inherent in planning for electricity supply to meet expected demand. At the most basic level, the IRP yields an indicative annual schedule of supply-side and demand-side resource additions that are integrated to accomplish the aforementioned objectives, consistent with the Company s duties and obligations to the public as a regulated public utility. The Company s IRP is performed through a coordinated process utilized across the Southern Company retail operating companies, with the assistance of their agent Southern Company Services, Inc. ( SCS ). The process used by Alabama Power to develop the IRP comports with the provisions of the Public Utility Regulatory Policies Act of 1978, as amended, which contemplates the use of appropriate integrated resource planning by electric utilities. In addition to Alabama Power, the Southern Company is the parent of Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company, (collectively, the Operating Companies ), as well as certain service and special-purpose subsidiaries. Together with the other Operating Companies, Alabama Power participates in a pooled operation of generating resources on the System for coordinating system operations and joint dispatch of their generating units. There are well-recognized advantages and economies gained from such pooled operations. In order to maximize these benefits, the retail Operating Companies engage in the coordinated planning of additional resources. Although Alabama Power participates in this coordinated planning process, the Company remains the final decisionmaker on any resource additions that it may require. Additionally, the System is represented on the Southeastern Electric Reliability Council ( SERC ), a group of electric utilities (and other electric-related utilities) coordinating operations and other measures to maintain a high level of reliability for the electric system in the Southeastern United States. Likewise, Alabama Power and the other retail Operating Companies, along with nine other transmission owners, are sponsors of the Southeastern Regional Transmission Planning process ( SERTP ), which provides an open, coordinated, and transparent transmission planning process for much of the Southeast in accordance with the requirements of the Federal Energy Regulatory Commission ( FERC ). In order to anticipate future energy requirements and electrical demands of the customers it serves, Alabama Power develops a load forecast that comprises a 20-year projection of the 8

11 expected growth in customer requirements. Alabama Power then develops an IRP that reflects, using the best information reasonably available to the Company, the indicated optimal mix of supply-side and demand-side resources to meet this projected load growth in customer peak demand in a reliable and cost-effective manner. The 2016 IRP is predicated on the Company s summer peak demand because the System is projected to achieve peak customer demand in the summer. Alabama Power has traditionally been considered summer peaking, meaning its annual peak demand falls during the summer months; however, its customer demands have been growing in the winter months. Indeed, in recent years, with colder weather, Alabama Power s winter peak demand has exceeded the summer peak demand. The Company s most recent load forecast projects dual peak demands, both in the winter and summer, where the winter peak demand is slightly higher than the summer peak demand. The Company s load forecast is discussed further in the Section III.B. The IRP is developed on a formal basis every three years and reviewed with the APSC staff. This review keeps the APSC informed as to the timing of resource additions, while also helping to ensure that the process yields results that are consistent with the Company s ultimate goals of minimizing rates and providing the desired level of service reliability. These goals are important because they allow the Company to be competitive with other energy providers and promote economic development within the State of Alabama. 9

12 II. ENVIRONMENTAL STATUTES AND REGULATIONS ii II.A. General The Company s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning and Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these and other environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2015, the Company had invested approximately $3.9 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $349 million, $355 million, and $184 million for 2015, 2014, and 2013, respectively. The Company expects that capital expenditures to comply with environmental statutes and regulations will total approximately $851 million from 2016 through 2018, with annual totals of approximately $319 million, $263 million, and $269 million for 2016, 2017, and 2018, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA s final rules and guidelines or subsequently approved state plans that would limit CO 2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. The Company also anticipates costs associated with closure in place and ground water monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule ( CCR Rule ), which are not reflected in the capital expenditures above, as these costs are associated with the Company s asset retirement obligation ( ARO ) liabilities. The Company s ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the ii The information in this section is drawn from the combined annual report on Form 10-K of The Southern Company and the Operating Companies for the year ended December 31, 2015, as filed with the Securities and Exchange Commission. Any material difference between the information contained therein and this section is unintended and the annual report should be referenced as the controlling discussion. 10

13 final requirements of new or revised environmental regulations, including the environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the Company s fuel mix. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company s operations, the full impact of any such changes is not known. Many of the Company s commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. II.B. Air Quality Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Additional controls to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements may become necessary in the future, depending on further actions taken by EPA. In 2012, the EPA finalized the Mercury and Air Toxics Standards ( MATS ) rule, which imposed stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. The compliance deadline set by the final MATS rule was April 16, 2015, with provisions for extensions to April 16, The implementation strategy for the MATS rule includes emission controls, retirements, and fuel conversions to achieve compliance by the deadlines applicable to each Company unit. On June 29, 2015, the Supreme Court issued a decision finding that, in developing the MATS rule, the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units. On December 15, 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur to respond to the Supreme Court s decision. The EPA s supplemental 11

14 finding in response to the Supreme Court s decision, which the EPA finalized on April 15, 2016, did not have any impact on the MATS rule compliance requirements and deadlines. The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard ( NAAQS ). In 2008, the EPA adopted a revised eight-hour ozone NAAQS, and published its final area designations in All areas within the Company s service territory have achieved attainment of the 2008 standard. On October 26, 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States will recommend area designations by October 2016, and the EPA is expected to finalize them by October The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the Company s service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS, and the EPA has officially redesignated former nonattainment areas within the service territory as attainment for these standards. In 2012, the EPA issued a final rule that increases the stringency of the annual fine particulate matter standard. The EPA completed final designations for the 2012 annual standard for Alabama in March 2015, and no new nonattainment areas were designated within the Company s service territory. Final revisions to the NAAQS for sulfur dioxide ( SO 2 ), which established a new one-hour standard, became effective in No areas within the Company s service territory have been designated as nonattainment under this rule; however, the EPA has not completed the designation process. The EPA has finalized a data requirements rule to support additional designation decisions for SO 2 in December 2017 and December 2020, which could result in nonattainment designations for areas within the Company s service territory. Implementation of the revised SO 2 standard could require additional reductions in SO 2 emissions and increased compliance and operational costs. 12

15 In February 2014, the EPA proposed to delete from the Alabama State Implementation Plan ( SIP ) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units. This action by the EPA was in response to a 2013 ruling by the U.S. Court of Appeals for the Eleventh Circuit that vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA s latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. The Company believes this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for affected units. The Company s service territory is subject to the requirements of the Cross State Air Pollution Rule ( CSAPR ). CSAPR is an emissions trading program that limits SO 2 and nitrogen oxide emissions from power plants in 28 states in two phases, with Phase I having begun in 2015 and Phase II beginning in On July 28, 2015, the D.C. Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, but rejected all other pending challenges to the rule. The court s decision leaves the emissions trading program in place and remands the rule to the EPA for further action. As noted earlier, all areas in Alabama have achieved attainment with the 2008 ozone standard. On December 3, 2015, the EPA published a proposed revision to CSAPR to address interstate transport of emissions for downwind areas that are struggling to meet the 2008 ozone NAAQS. The EPA s proposed revision would revise existing ozone-season emission budgets for nitrogen oxide for certain states, including Alabama, beginning in The EPA proposes to finalize this rulemaking by summer The EPA finalized regional haze regulations in 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by The rule involves the application of best available retrofit technology ( BART ) to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. In July 2013, ADEM submitted to the EPA a required regional haze mid-course review, concluding that no changes to the Alabama SIP are necessary to maintain reasonable progress toward visibility goals. What constitutes BART has been the subject of litigation and is still an unresolved issue 13

16 for some Company operated units and therefore, the ultimate impact to Alabama Power and its customers from BART is not known. In 2012, the EPA published proposed revisions to the New Source Performance Standard ( NSPS ) for Stationary Combustion Turbines ( CT ). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs (including CTs at combined cycle units) during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed. On June 12, 2015, the EPA published a final rule requiring certain states (including Alabama) to revise or remove the provisions of their SIPs relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction ( SSM ) by no later than November 22, The Company has developed and continuously updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. As part of this strategy, the Company has developed a compliance plan for the MATS rule that includes reliance on existing emission control technologies, the construction of baghouses to provide an additional level of control on the emissions of mercury and particulates from certain generating units, the use of additives or other injection technology, the use of existing or additional natural gas capability, and unit retirements. Additionally, certain transmission system upgrades were required. The Company s compliance strategy reduced its coal-fired resources by 1,595 MW. Of the 1,595 MW reduction in coal-fired resources, 920 MW were fuel switched to natural gas and 675 MW were retired or placed on inactive reserve. These decisions resulted in a transformation of the Company s generating fleet, as shown in Figure II-B-1. 14

17 FIGURE II-B-1: APC Generating Capacity by Fuel Type Pre-MATS Post-MATS 13.5% Coal 14.3% Coal 13.1% 17.8% 55.6% Gas Hydro Nuclear 13.8% 26.4% 45.5% Gas Hydro Nuclear The ultimate impacts on the Company of the eight-hour ozone, fine particulate matter and SO 2 NAAQS, the Alabama opacity rule, CSAPR, regional haze regulations, the MATS rule, the NSPS for CTs, and the SSM rule will depend on the specific provisions of the proposed and final rules, the resolution of pending and future legal challenges, and the development and implementation of rules at the state level. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. II.C. Water Quality The EPA s final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities became effective in October The effect of this final rule will depend on the results of additional studies and implementation of the rule by regulators based on site-specific factors, as well as on the outcome of ongoing legal challenges. National Pollutant Discharge Elimination System permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule. 15

18 On November 3, 2015, the EPA published a final effluent guidelines rule that imposes stringent technology-based requirements for certain wastestreams from steam electric power plants. The revised technology-based limits and compliance dates will be incorporated into future renewals of National Pollutant Discharge Elimination System permits at affected units and will require the installation and operation of multiple technologies sufficient to ensure compliance with applicable new numeric wastewater compliance limits. Applicability dates between November 1, 2018 and December 31, 2023 will be established by ADEM in permits based on information provided for each applicable wastestream. The ultimate impact of these requirements will depend on pending and any future legal challenges, compliance dates, and the selection of available technology. Engineering and procurement is now underway to convert fly and bottom ash handling to dry or hybrid systems that, in compliance with the rule, will have no discharge of water. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the United States for all Clean Water Act ( CWA ) programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects, which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying its implementation. The ultimate impact of the final rule will depend on the outcome of this and other pending legal challenges as well as the EPA s and the U.S. Army Corps of Engineers field-level implementation of the rule. These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. II.D. Coal Combustion Residuals The Company currently manages CCR at on-site storage units consisting of landfills and surface impoundments ( CCR Units ) at six generating plants. In addition to on-site storage, the Company also sells a portion of its CCR to third parties for beneficial reuse. Individual states 16

19 regulate CCR and the State of Alabama has its own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments. On April 17, 2015, the EPA published the CCR Rule in the Federal Register, which became effective on October 19, The CCR Rule regulates the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Units at active generating power plants. The CCR Rule does not automatically require closure of CCR Units, but includes minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansions of existing units, and active landfills. Failure to meet the minimum criteria can result in the required closure of a CCR Unit. Although the EPA does not require individual states to adopt the final criteria, states have the option to incorporate the federal criteria into their state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. The EPA s final rule continues to exclude from regulation the beneficial use of CCR. Based on initial cost estimates for closure in place and groundwater monitoring primarily related to ash ponds pursuant to the CCR Rule, the Company recorded AROs related to the CCR Rule. The Company expects to continue to periodically update these estimates as further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates (such as the quantities of CCR at each site), and the determination of timing considerations (such as the potential for closing ash ponds prior to the end of their currently anticipated useful life). The Company is currently completing an analysis of the plan of closure for all ash ponds, including the timing of closure and related cost recovery through regulated rates subject to APSC approval. Based on the results of that analysis, the Company may accelerate the timing of some ash pond closures, which could increase its ARO liabilities from the amounts presently recorded. The ultimate impact of the CCR Rule will depend on the Company s ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. II.E. Global Climate Issues On October 23, 2015, the EPA published two final actions that would limit CO 2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission 17

20 standards governing CO 2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan ( CPP ), establishes guidelines for states to develop plans to meet EPA-mandated CO 2 emission rates or emission reduction goals for existing units. The EPA s final guidelines require state plans to meet interim CO 2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adopt or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. On February 9, 2016, the Supreme Court granted a stay of the CPP, pending disposition of petitions for appellate review. The stay will remain in effect through the resolution of the litigation, whether resolved in the D.C. Circuit or the Supreme Court. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. However, the ultimate financial and operational impact of the final rules on the Company will depend upon numerous factors, such as the Company s ongoing review of the final rules; the outcome of legal challenges, including legal challenges filed by the retail Operating Companies; individual state implementation of the EPA s final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required. The United Nations 21 st international climate change conference took place in late The result was the adoption of the Paris Agreement, which establishes a non-binding universal framework for addressing greenhouse gas emissions based on nationally determined contributions. It also sets in place a process for increasing those commitments every five years. The ultimate impact of this agreement will depend on its ratification and implementation by participating countries. 18

21 III. INTEGRATED RESOURCE PLAN III.A. Process Overview The integrated resource planning process is designed to identify the types of resources necessary to serve the long-term expected growth in the energy and demand requirements of Alabama Power s customers. Aided by the IRP, the Company is able to effectively develop a resource strategy that provides for cost-effective, reliable service. The 2016 IRP, which has a 20-year planning horizon, indicates the optimal mix of resources necessary to meet customers future load requirements. Using the best information available at the time of its development, the IRP provides the basis for estimating potential capital expenditures that may be required for future generating capacity additions. The IRP process is heavily dependent on models, data, and inputs that constitute highly confidential and proprietary information of the Company. In the IRP, both supply-side and demand-side options are evaluated and integrated on a consistent basis through the use of marginal cost analysis. This approach ensures that both supply-side and demand-side options are identified for potential selection and deployment when such options represent a viable economic choice. As shown in Figure III-A-1, integrated resource planning is a dynamic process that continuously evaluates existing and potential resource options in an effort to identify the best combination, in terms of reliability and expected total cost for serving customers. 19

22 FIGURE III-A-1: Alabama Power IRP Process PRIOR INTEGRATED RESOURCE PLAN UPDATE MARGINAL COST PROJECTIONS BASED ON LATEST IRP. Revised Fuel Cost. Revised Technology Cost. Regulatory Compliance LOAD FORECAST. End-Use Modeling. Econometric Modeling. Customer Analysis MARGINAL COST DEMAND-SIDE EVALUATIONS. Identification of Possible DSOs. Screening & Analysis. Market Program Design MARGINAL COST SUPPLY-SIDE EVALUATIONS. Modification of Existing Resources. Purchased Power Options RESOURCE MIX ANALYSIS AND BENCHMARK EVALUATIONS. Reliability Requirements. Existing Resources Characteristics Update. Future Generation Options. Cost Effectiveness. Sensitivity Analysis INTEGRATION. Adjustment to Benchmark Plan. Resource Scheduling. Financial Assessment CURRENT INTEGRATED RESOURCE PLAN UPDATE MARGINAL COST PROJECTIONS BASED ON LATEST IRP LOAD FORECAST 20

23 The principal components in the process are as follows: Update Marginal Cost Projections Based on Latest IRP Marginal cost projections are derived using the previous IRP. These projections are then updated to recognize any significant changes in costs such as fuel, technology and regulatory compliance. Load Forecast A forecast of future energy and peak demand requirements for the next 20 years is developed. This forecast incorporates an estimate of future economic conditions and trends in customer energy usage. Marginal Cost Demand-Side Evaluations Demand-side management ( DSM, sometimes also referred to as demand-side options, or DSO ) programs are evaluated on a marginal cost basis. This procedure is used to identify costeffective DSM programs for inclusion in the IRP. Marginal Cost Supply-Side Evaluations Marginal cost evaluations are performed to determine if modifications to existing resources or power purchases from other suppliers are economically viable. Resource Mix Analysis and Benchmark Evaluations This part of the IRP process involves the development of an optimum resource mix. The resource mix is a flexible, iterative analysis that allows for integration of the appropriate combination of resources that will serve the projected load at the lowest expected total cost (both fixed and variable), while maintaining a target reliability guideline. This step includes sensitivity analyses to establish boundaries within which the conclusions of a benchmark plan remain valid. The resource mix analysis incorporates the impacts of existing and projected DSM programs, revised load information, and updated cost information (including fuel, capital, operation and maintenance). It also incorporates the most recent information on the characteristics of existing resources, both supply-side and demand-side. 21

24 The flexibility of the IRP process allows insertion of marginal cost results from the supply-side or demand-side options in any sequence. The result is a benchmark plan from which the most cost-effective combination can be determined in an integration step. In planning future resource additions, consideration is given to uncertainties associated with unforeseen unit outages, abnormal weather and load forecast deviations. In order to minimize the effects of these uncertainties, criteria are established that qualify and quantify an appropriate level of capacity reserves. These reserves are planned to be available so as to account for the potential inability to meet load requirements due to generation shortfalls resulting from uncertainties inherent in the resource planning process. The criteria are called reserve criteria and are specified as margins. The minimum long-term target reserve margin guideline, which is periodically reviewed and re-evaluated, is based on economic analyses, operating experience and system operation input, and seeks to minimize the combined cost of new generating capacity, production costs, and customer-related costs associated with outages. The 2016 IRP utilized a minimum long-term System target planning reserve margin guideline of percent. By virtue of load diversity across the Southern Company electric system, a minimum long-term target reserve margin of percent can be met if each Operating Company maintains a minimum long-term reserve margin of at least percent. In other words, by participating in the Southern Company pool, Alabama Power can maintain a long-term reserve margin of percent but realize a level of reliability equivalent to a long-term reserve margin of percent, thereby avoiding the cost of building or purchasing additional resources associated with the 1.50 percent differential. These capacity savings represent one of the recognized benefits of operating as a pool. As discussed in Section III.D. of this report, an updated Reserve Margin Study indicates the need to increase the System s long-term target planning reserve margin. Due to the timing of the completion of the study, the 2016 IRP does not reflect a higher target planning reserve margin target. However, subsequent to the completion of the new study, the Company has begun utilizing, for planning purposes, an updated long-term System planning reserve margin target of percent, which equates to a long-term diversified planning reserve margin target for Alabama Power of percent. Absent further adjustments prompted by the various factors 22

25 impacting the system reserve margin, the newly revised reserve margin targets will be reflected in future IRPs. Integration Demand-side and supply-side options identified as cost-effective choices for resource additions, but not previously reflected in a benchmark plan, are incorporated into the IRP in the integration phase. This phase consists of determining the Company s best alternative for meeting the resource needs identified in the benchmark plan, coordinating resource additions with those of the other retail Operating Companies, and performing a financial assessment of the plan. The process described above is not necessarily set forth in chronological order. Many evaluations are performed concurrently. Marginal cost evaluations can be performed or updated at several points in the process. Figure III-A-2 describes a typical chronological progression. FIGURE III-A-2: IRP Development Activities Marginal Cost Projection Update Preliminary Fuel Price Workshop Supply-Side Technology Issues Reviewed DSM Screening Analysis Planning Issues Identified Preliminary Planning Assumptions Established Preliminary Fuel Forecasts Technology Panel Review Candidate Unit Assumptions Established DSM Forecast Finalized Load Forecast Finalized Planning Assumptions Reviewed and Finalized Resource Mix Analysis Process Preliminary IRP Review Benchmark Plan Completed Financial Assessment IRP Approval 23

26 III.B. LOAD FORECAST The Company annually produces a short-term and long-term energy and peak demand forecast for territorial customers of Alabama Power, including projections of customer growth, peak demand (MW), and monthly energy consumption (kwh). The 2016 IRP reflects a load forecast for the years Underlying this load forecast are economic data and forecasts supplied by Moody s Analytics. These economics incorporate available benchmarked employment and demographic data as well as other economic indicators for the state, all of which support the development of econometric models for the forecast of the number of customers, the energy sales to the customers and the peak demand required to meet customers needs. End use models are used when possible to incorporate long term effects of appliance saturation and increased efficiency trends on sales. As might be expected, this forecast continues to reflect the ongoing, lingering effects of the worldwide economic recession. Although Alabama Power has traditionally been considered summer peaking, meaning its annual peak demand falls during the summer months, its customer demands have been growing in the winter months. In recent years, with colder weather, Alabama Power s winter peak demand has exceeded the summer peak demand. The 2014 actual winter peak was 12,610 MW prior to the utilization of the Company s interruptible and demand management options. The 2014 winter peak was over 1,200 MW higher than the 2014 summer peak. The Company s most recent load forecast projects dual peak demands, both in the winter and summer, where the winter peak demand is slightly higher than the summer peak demand with projected growth rates which are lower than what was reflected in the 2013 IRP. As such, the 2016 IRP forecast reflects the effects of both a slower economic recovery in the near term and greater levels of appliance and lighting efficiencies. These forecast results are heavily dependent on the economic forecast of employment in Alabama. Another influencing factor is lower demand for commodities produced in Alabama, which has weakened in the wake of lower oil prices and a stronger dollar. It is important to note that, although the current forecast is somewhat lower than the forecast used in the 2013 IRP, it 24