2013 Integrated Resource Plan

Transcription

eg
t
In
0
2
R
d
e
t
a
r
rc
u
eso
6
1
la
P
e
m
u
nS
m
ar
y
rt
o
p
e
R
Alabama Power Company
2016 Integrated Resource Plan
Summary Report
EXECUTIVE SUMMARY…………….....………………………………………………………….
1
I.
INTRODUCTION..…………………………….………………………….………………….
7
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..……………………………………………………….….….….
10
10
11
15
16
17
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..………………………………………………………….…….…
19
19
24
25
26
29
39
IV.
CONCLUSION..………………….……………………………………………………………
42
APPENDIX 1 - 2016 Integrated Resource Plan - Existing Supply-Side Resources
Figure A1-1: Alabama Power Existing Generating Resources…………….……
A1-1
i
Alabama Power Company 2016 IRP
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 2015.
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, 2015.
The CPP, which calls for the establishment of significant restrictions relating to carbon dioxide
(“CO2”) emissions from electric generating units, stands to significantly impact the Company’s
1
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
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. 32382 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 § 40-18-1(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. 32382, 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, 2016. 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, 2017. 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
term (i.e., greater than three years) target planning reserve margin should be increased from the
15.00 percent target to 16.25 percent while the short-term (i.e., less than three years) target
planning reserve margin should be increased from 13.50 percent to 14.75 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 14.74 and 13.26 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
Updated
Reserve
Reserve
Margin Study
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 15.00
and 13.50 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
16.25 percent long-term System planning reserve margin target and a short-term System
planning reserve margin target of 14.75 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
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
measured course in meeting customer demand in a dynamic regulatory environment, while also
maintaining rates below the national average.
6
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 2013-2015, the Company had a
service reliability of 99.98 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
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
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
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 CO2 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
iiThe 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
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, 2016. 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
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 2012. 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 2017.
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 (“SO2”), which established a new one-hour
standard, became effective in 2010. 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 SO2 in December 2017 and December 2020, which could result in
nonattainment designations for areas within the Company’s service territory. Implementation of
the revised SO2 standard could require additional reductions in SO2 emissions and increased
compliance and operational costs.
12
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 SO2 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 2017. 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 2017. The EPA
proposes to finalize this rulemaking by summer 2016.
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 2064. 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
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, 2016.
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
FIGURE II-B-1: APC Generating Capacity by Fuel Type
Pre-MATS
13.5%
13.1%
Post-MATS
14.3%
Coal
55.6%
17.8%
Gas
13.8%
Hydro
Nuclear
26.4%
Coal
45.5%
Gas
Hydro
Nuclear
The ultimate impacts on the Company of the eight-hour ozone, fine particulate matter and SO2
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 2014. 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
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
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, 2015. 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 CO2 emissions from
fossil fuel-fired electric generating units. One of the final actions contains specific emission
17
standards governing CO2 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 CO2 emission rates or emission reduction goals for existing units.
The EPA’s final guidelines require state plans to meet interim CO2 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 21st international climate change conference took place in late 2015. 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
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
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
MARGINAL COST
SUPPLY-SIDE
EVALUATIONS
. Identification of
Possible DSOs
. Screening & Analysis
. Market Program Design
. 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
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
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
15.00 percent. By virtue of load diversity across the Southern Company electric system, a
minimum long-term target reserve margin of 15.00 percent can be met if each Operating
Company maintains a minimum long-term reserve margin of at least 13.50 percent. In other
words, by participating in the Southern Company pool, Alabama Power can maintain a long-term
reserve margin of 13.50 percent but realize a level of reliability equivalent to a long-term reserve
margin of 15.00 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
16.25 percent, which equates to a long-term diversified planning reserve margin target for
Alabama Power of 14.74 percent. Absent further adjustments prompted by the various factors
22
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
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 2016-2035.
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
nonetheless reflects economic growth in Alabama and continued employment recovery from the
Great Recession.
As discussed previously, although the Company’s most recent peak demand forecast is slightly
higher in the winter season, the 2016 IRP is still based on the Company’s summer peak because
the System is still projected to peak in the summer season throughout the planning horizon. The
Company will continue to assess the winter/summer peak comparison and any implications it
may have to the coordinated planning process in the future.
III.C.
FUEL FORECAST
Both short-term (current year plus two) and long-term (year four and beyond) fuel and allowance
price forecasts are developed for use in the Company’s planning activities, business case
analyses, and decision making. Short-term forecasts are updated monthly as part of the
Company’s fuel budgeting process and marginal pricing dispatch procedures. The long-term
forecasts are developed each year for use in the Company’s planning activities. Charles River
Associates (“CRA”), the Company’s scenario modeling consultant, produces the long-term fuel
price forecasts for natural gas and coal.
The development of the long-term forecasts is a highly collaborative effort between CRA, SCS,
and the retail operating companies. CRA’s MRN-NEEM national, multi-sector, energy-economy
model, with support from other CRA models, was used to generate integrated results for natural
gas and coal prices, in five-year increments, for the period 2020 through 2055. The integrated
modeling approach makes it possible to develop forecasts for natural gas, petroleum, and coal
prices that are internally consistent with one another and with other variables and feedbacks
involving economic growth, electricity consumption, and output across many sectors and
regions. The integrated approach takes a set of assumptions about market fundamentals and then
solves for the prices that make the quantity supplied equal to the quantity demanded in all
markets. In addition, the integrated approach simulates interactions among different markets and
thereby reveals how such things as environmental regulations and natural gas supply outlooks
shape the disposition of economic output across sectors, as well as the competition between coal
and natural gas as a generation fuel.
25
The modeling process began with the calibration of the MRN-NEEM model to the most recent
Energy Information Agency (“EIA”) Annual Energy Outlook (“AEO”), in this case the AEO
2015 Reference case. The AEO 2015 Reference case assumes a continuation of only those
environmental policies in place (finalized, but not necessarily implemented) at the time of the
forecast, while the CRA analysis assumes that other proposed rules that the EPA has yet to
finalize (or has finalized since EIA performed its Reference case forecast) will come into effect.
As a result, the CRA forecasts anticipate a larger decrease in coal plant fleet size, which tends to
raise natural gas prices relative to EIA projections.
III.D.
RESERVE MARGIN
Because electric utility customers expect and depend on a high level of service reliability, a retail
electric utility should have an economically balanced margin of generating capacity in excess of
the peak load. To have this reserve capacity available when it is needed, a utility must plan much
further beyond the upcoming season because the processes to procure additional capacity, such
as building a new unit or completing a PPA, can take several years. The purpose of a Reserve
Margin is to determine an appropriate amount of reserve capacity that should be targeted for the
System at any point in the future.
Four primary reasons for having this reserve capacity are:
1)
Weather: The System’s load forecasts are based on average weather conditions
over the past 20 years. If the weather is hotter than normal during warm seasons or
colder than normal during cold seasons, the load will be higher. Drought conditions
and temperature-related impacts on unit outputs can also significantly affect the
System’s load and capacity balance.
2)
Economic Growth Uncertainty: It is impossible to project exactly how many new
customers a utility will have or how much power existing customers will use from
season to season. Based on historical projections and actual economic growth, peak
demand may grow more than expected during the period required to procure new
resources.
26
3)
Unit Performance: By their very nature, machines can be expected to fail from
time to time. While the System has a proven history of very low forced outage rates,
there have been occasions when higher than average levels of capacity on the
System have been in a concurrent forced outage condition.
4)
Market Availability Risk: The ability to obtain resources from the wholesale
power market when needed to address a short-term System resource adequacy issue
is subject to uncertainty. In general, having access to resources in neighboring
regions does enhance a region’s reliability due to load and resource diversity.
However, the amount, cost, and deliverability of those resources are subject to the
external region’s resource-adequacy situation and transmission capability at any
given time. While a region can expect support from its neighbors, that region must
carry adequate reserves to handle situations where access to resources outside the
region is limited.
While each of these four factors on its own creates a need for capacity reserves, a confluence of
all these risk factors would pose considerable risk. A very high reserve level would be required
to meet customers’ load demands, plus operating reserve requirements, in order to prepare for a
simultaneous occurrence of all such events. However, maintaining such high levels of capacity
reserves would come at significant expense and would address a scenario with a very low
probability. The more appropriate approach to setting the optimum target reserve margin is to
minimize the combined expected costs of maintaining reserve capacity, production costs, and
customer costs associated with service interruptions, adjusting for value at risk.
In order to understand and quantify the overlap of the four contributing factors to the need for
reserve margins, the Strategic Energy and Risk Valuation Model (“SERVM”) is utilized.
SERVM is a system dispatch model that evaluates the ability of the System’s capacity resources
to meet load obligations every hour in a year for thousands of combinations of weather, load
forecast deviations, and unit performance issues. The model quantifies, in dollar cost, two
components of reliability-related costs:
1. Production costs, including sales and purchases
27
2. Customer cost of outages (i.e., the cost of expected unserved energy, or “EUE”)
The analysis is performed on a range of planning reserve margins. With lower reserve margin
levels, the reliability costs are high and vary widely, but the cost of carrying reserves is low. At
higher reserve margin levels, the reliability costs are low, but the cost of carrying reserves is
high. The objective of this analysis is to determine the target reserve margin where the sum of
these costs (i.e., those related to reliability and those related to carrying reserves) is minimized
(i.e., the minimum cost point).
The cost considerations that the analysis seeks to minimize reflect very different risk
characteristics. The trade-off between relatively static capacity costs and highly volatile
reliability costs is difficult to measure. The approach taken to account for this inherent difference
is to evaluate the risk using the risk metric Value at Risk (“VaR”), at confidence levels between
85 percent and 95 percent. Value at Risk was calculated by subtracting the average cost from
each specific scenario’s cost. For a number of mild weather or slow load growth scenarios, the
total cost was lower than average. For the extreme cases, the scenario cost was much higher than
average. The 85 percent confidence VaR represents the total cost in the 85 percent case, minus
the average cost. The risk tradeoff can be seen in the flatness of the total cost “U” curve near the
optimum reserve margin point; a reserve margin a few percentage points higher than the
optimum reserve margin would not cost much more on average and would eliminate a number of
expensive scenarios, thereby lowering risk.
A minimum long-term System target planning reserve margin guideline of 15.00 percent was
used in the 2016 IRP. As noted previously, peak load diversity enables the System to meet that
15.00 percent target guideline if each Operating Company maintains a reserve margin of at least
13.50 percent. These planning reserves protect against a shortfall in capacity and a loss of load
due to unforeseen future events, such as greater than expected load growth or unusual weather.
Based on the load forecast and target reserve margins utilized in the 2016 IRP, the Company has
sufficient resources to provide an appropriate level of reserves to meet customers’ electrical
needs until 2033. Beginning in 2033, the Company’s reserve margin is projected to fall below its
diversified target planning reserve margin guideline (13.50 percent). The projected capacity
28
deficit below target in 2033, combined with sufficient Southern system reserves, is not large
enough to result in a resource addition for Alabama Power. By 2035, however, Alabama Power
is projected to have a need for new intermediate resources to maintain its target planning reserve
margin guideline. 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.
As discussed earlier, a new Reserve Margin Study was completed after the 2016 IRP was
finalized and demonstrates that the System planning reserve margin targets of 15.00 percent
(long-term) and 13.50 percent (short-term) no longer provide the appropriate balance between
the cost of reliability and cost of additional resources. A number of factors drove this change,
including the predicted effects of extreme cold weather events, customer demand trends, and the
penetration of intermittent renewable resources on the System. The updated study supports an
increase in these System planning reserve targets. Informed by the study, the Company has
begun utilizing, for planning purposes, a 16.25 percent long-term System planning reserve
margin target and a 14.75 percent short-term System reserve margin target, which equate to
diversified (individual retail operating company) planning reserve margin targets of 14.74 and
13.26 percent, respectively. Absent further adjustments prompted by the various factors
impacting the system reserve margin, the newly revised reserve margin targets will be reflected
in the Company’s future IRPs. Holding all other elements in the 2016 IRP constant, the
application of the revised long-term target planning reserve margin would result in Alabama
Power’s reserve margin falling below its diversified target a couple of years earlier than 2033.
III.E.
RESOURCE OPTIONS
The process that led to the development of the 2016 IRP included consideration of demand-side
and supply-side options. Detailed analyses were performed on viable options to ensure that costeffective resource alternatives were identified to meet projected load growth and satisfy the
appropriate reliability criteria.
29
The Company will add supply-side and/or demand-side, active or passive, resources to maintain
the Company’s minimum long-term target planning reserve margin guideline. An active DSM
program is one that is dispatchable or controllable (“activated”) by the Company at the time of
need. In contrast, a passive DSM is an alternative adopted by customers that becomes embedded
in their electric energy use pattern and requirement. The effects of passive DSM additions are
captured in the load forecast in the form of peak load reduction megawatts.
A list of technology options is shown in Figure III-E-1. Assumptions for cost, performance,
design maturity, regulatory approval, and other parameters for uncommitted resource options
continue to change. The following list represents, but is not all-inclusive of, resource option
technologies that may be selected in the future:
30
Figure III-E-1: Alabama Power Candidate Technologies
COAL-FUELED
Subcritical Pulverized Coal
Supercritical Pulverized Coal
Ultrasupercritical Pulverized Coal
Advanced Ultrasupercritical Pulverized Coal
Atmospheric Fluidized Bed Combustion
Pressurized Fluidized Bed Combustion
Topping Pressurized Fluidized Bed Combustion
Oxygen-Blown IGCC
Air-Blown IGCC
Non-Integrated Coal Gasification Combined Cycle
Integrated Gasification Fuel Cell Combined Cycle
Magnetohydrodynamics
RENEWABLES
Solar Thermal Parabolic Trough
Solar PV
Wind Power
Tall Tower Large Rotor Wind Power
Offshore Wind Power
Municipal Solid Waste
Dedicated Biomass
Co-fired Biomass or Wood Waste
Landfill gas
LIQUID/GAS FUELED
CT (Conventional/ Advanced)
CC Conventional/ Advanced
Phosphoric Acid Fuel Cells Geothermal
MCFC & SOFC Solar Stirling Dish
Fuel Cell CC Solar Central Receiver Technology
Reciprocating Engine Compact Linear Fresnel Reflector
Microturbines Ocean Energy and Hydrokinetic Generation
Ocean Thermal Generation
ENERGY STORAGE
Direct-fired Supercritical CO2 cycle
Pumped Storage Hydroelectric
Underground Pumped Storage Hydroelectric
Compressed Air Energy Storage- Gen I
Compressed Air Energy Storage- Gen II
Advanced Lead/Acid Battery
Flow Batteries
Lithium Ion based Batteries
Flywheel Energy Storage
NUCLEAR
Advanced LWR Evolutionary
Advanced LWR Passive
Advanced LWR Modular
Generation IV
Small Modular Reactor
Further studies and analysis will be undertaken at the appropriate time to determine the actual
amount, technology and other features of needed resource additions.
The resources identified for the 2016 IRP are summarized below:
Purchased Power
Long-term purchase power contracts are evaluated and compared to other generation options so
that the most cost-effective and reliable generation resources are selected to meet customers'
electrical needs. This process, for example, resulted in the selection of the Harris PPA and the
31
Calhoun Power PPA for certification by the APSC. Alabama Power will continue to evaluate
purchase power options as a part of its IRP process, with the goal being to provide customers
with reliable energy at the lowest practical cost. This evaluation includes consideration of an
appropriate balance of Company-owned/controlled assets, as opposed to PPAs that provides a
contractual right to power from assets controlled by third parties. Relevant in this regard is the
practice of rating agencies to treat long term PPA obligations as a debt equivalent, which
adversely impacts the Company’s capital structure for ratings purposes and, thus, represents a
cost to the Company. Short-term power purchases are used when appropriate to meet short-term
capacity needs.
Renewable Resources
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,
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 Commission issued to the Company a certificate of convenience and
necessity in Docket No. 32382 authorizing the development or procurement of up to 500 MW of
capacity and energy from renewable energy and environmentally-specialized generating
resources. In accordance with the certificate, Alabama Power is not required to develop or
procure the entirety of the 500 MW. Rather, projects presented to the Commission for approval
must satisfy certain eligibility criteria.
First, the project must involve a renewable energy
resource (such as those identified in Alabama Code § 40-18-1(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. The APSC will consider projects up to 160 MW of the
32
certificated amount annually; any proposal in excess of that annual threshold requires prior
authorization. In addition, any unexercised authority under the certificate expires after six years.
Consistent with the certificate authority, the APSC subsequently approved two projects on
December 14, 2015. 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, 2016. 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, 2017. 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.
Given the authorization in Docket No. 32382, the Company has removed the 25 MW of generic
renewable resources identified in the 2013 IRP. Additional renewable resources will be added to
its plan as they are identified, either through the exercise of the authority under that certificate or
through another vehicle.
Cogeneration/Combined Heat and Power (“CHP”)
Currently, the Alabama Power system includes more than 500 MW of Company-owned CHP
generation. Cogeneration and CHP have been options for the Company for many years.
During the 1990s, when the Company needed to add new generation to reliably meet the load
obligations of its customers, Alabama Power was able to develop new generation resources near
certain customer facilities. These new generating facilities provided cost-effective capacity and
energy to all of its customers, while also satisfying the steam needs of the specific customers at
those locations. More recently, the Company has used a program authorized by the APSC to
certify two PPAs for rights to capacity and energy from two customer-owned CHP facilities.
The Company’s success in identifying CHP projects that are expected to bring benefits to all
customers is attributable in large part to the APSC’s recognition that resource and capacity
33
additions do not follow a one-size-fits-all approach. This is particularly so with CHPs, where a
good working arrangement between all parties is essential for these projects to be developed, and
where an adaptive regulatory process is critical to the project’s success.
Future Generation
Based on the load forecast utilized in the 2016 IRP, increases in customer electrical demand can
be met with the Company’s existing generation and demand-side resources until 2035.
Beginning in 2035, the 2016 IRP indicates that additional intermediate generation capacity will
be required to meet forecasted increases in customer electrical demand throughout the remainder
of the planning horizon. As noted previously, 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.
Demand-Side Management Programs
Alabama Power is committed to both economic growth and environmental stewardship within
the state. In concert with customer needs and desires, Alabama Power works to ensure that it
continues to have the reliable and cost-effective energy needed to promote the interests of the
region. In doing so, Alabama Power continues to be an industry leader in cost-effective demand
side management programs. The Company implements DSM measures and programs that are
designed to reduce customers’ energy bills, improve their competitiveness, assist with system
load shape management (thereby reducing costs and the need for future capital investment), and
help customers use energy as efficiently as possible. Today, Alabama Power has programs in
place that have resulted in over 1,900 MW, in total, of demand reduction. This is equivalent to
the electrical demand of over 475,000 average residential homes in the Company’s service
territory. All customer segments (industrial, commercial, and residential) are potential
participants in these programs.
34
Changes in technology and other influencing factors can, along with education, provide
opportunities for the Company to work more with customers to help them manage and control
their energy use, making it more efficient and economical. In managing its DSM programs,
Alabama Power must be mindful of the effect they can have on electricity prices. Accordingly,
the Company pursues those programs that are expected to benefit all of its customers, thereby
avoiding the situation where some customers are effectively being caused to subsidize the
benefits realized by others.
The economic health of all customers is not only important to Alabama Power; it is also
important to the state and its future economic vitality. Just as important is Alabama Power’s
commitment to responsible environmental policies. Therefore, future DSM programs can be
expected to continue to balance these considerations in a cost-effective manner – encouraging
customers’ wise and efficient use of energy, while maintaining an economically vibrant and
productive region.
Alabama Power currently has customers participating in more than 20 DSM programs in the
residential, commercial and industrial sectors, as well as programs managed through the
Company’s Distribution Operations. The 2016 IRP includes approximately 1,613 MW of
existing active demand-side programs that have allowed the deferral of 1,375 MW of supply-side
resource capacity. The difference between the nominal values shown for the demand-side
programs and the associated supply-side resource capacity deferrals is due to the lower
availability of capacity equivalence under DSM program, as compared to a supply-side resource.
As noted earlier, DSM programs that are subject to the direct control of the Company (e.g., nonresidential interruptible load) are called “active DSM”. The DSM programs dependent on
customer behavior or energy usage patterns (e.g., equipment SEER efficiency increases,
insulation/infiltration upgrades) are called “passive DSM.” The passive DSM programs serve to
reduce expected peak load and consequently are embedded in the Company’s load forecast.
Existing passive DSM programs are estimated to have resulted in a peak load reduction of 294
MW. Therefore, the total amount of existing DSM programs reflected in the 2016 IRP is 1,613
MW, plus 294 MW, for a total of 1,907 MW.
35
Active DSM Programs
The Company’s active DSM programs are described below.
Residential Demand Response Programs:
1. Centsable Switch – A cycling program whereby a customer’s HVAC is cycled 67
percent during the months of June-September up to 5 hours per day, subject to a
maximum of 150 hours per year.
2. SmartPower Critical Peak Pricing Program – The customer receives a “smart”
thermostat at no cost and is placed on a time-of-use rate with a critical peak price
(CPP) component working in conjunction with the Company’s AMI infrastructure.
Commercial and Industrial Demand Response Programs:
1. Industrial Interruptible Program – This program, which is currently one of the
largest of its kind in the nation, allows Alabama Power to call for the interruption of
load with 15-30 minutes’ notice. The Company’s right to interrupt is contractually
limited to no more than 200-600 hours per year and no longer than 8 hours per call.
2. Real Time Pricing – Industrial pricing option based on marginal costs plus
applicable adders to recover fixed costs.
3. Standby Generator Program – Under this program, customers enter into a contract
with Alabama Power to switch to their standby generators with no notice for use in
non-emergency circumstances. The Company is limited to calling these contracts for
not more than 200 hours a year (not including maintenance and testing), with no call
exceeding 8 hours. In prior years, the program also included an emergency generator
option, under which the Company could call on participating generators for
emergency purposes not more than 68 hours per year (not including maintenance and
testing).
But on May 1, 2015, the United States Circuit Court of Appeals for the
District of Columbia vacated portions of an EPA rule upon which the emergency
generator option of the Standby Generator program had been predicated.
The
appellate court did stay the effectiveness of the decision, which provided EPA with an
opportunity to evaluate the need for and promulgate a follow-up rulemaking. Despite
receiving this extra time, EPA did not take any subsequent action, and on May 4,
2016 the D.C. Circuit ended the stay. With the regulatory basis for the emergency
36
generator option vacated, that component of the Standby Generator program
terminated.
Transmission and Distribution Energy Efficiency Programs:
1. Distribution Energy Efficiency Program (DEEP) – DEEP operates continuously
using capacitors to reduce voltage drop on distribution feeders. The lower voltage
upstream of distribution feeders lowers the demand and reduces VAR requirements
on the system.
2. Distribution Regulation Optimization Program (DROP) – A conservation voltage
control option that lowers the voltage on distribution feeders to lower the demand and
reduce VAR requirements on the system. The target activation periods under this
program are the summer and winter peaks.
Passive DSM Programs
The Company’s passive DSM programs, which have contributed to load reductions reflected in
the 2016 IRP, are described below.
Residential Energy Efficiency Programs:
1. Superior Solution New Home Program/Energy Star – The Superior Solutions new
home program has two levels of energy efficiency achievements. A Superior
Solutions Gold Home is constructed to meet a HERS, Home Energy Rating System,
rating of 78 or less prior to October 1, 2016 and a HERS rating of 70 after October 1,
2016. A Superior Solutions Platinum Home is required to be constructed to meet a
HERS rating of 65 or below. A typical home built to the 2006 IECC would be given a
HERS rating of 100. Each point of reduction in the HERS index represents a one
percent increase in energy efficiency. ENERGY STAR certified new homes are
designed and built to standards well above most other homes on the market today,
delivering energy efficiency savings of up to 30 percent when compared to typical
new homes.
2. Geothermal Heat Pump – This program promotes geothermal heat pumps, which
are a central heating and cooling system that use the earth to transfer heat to and from
37
the ground by use of a ground heat exchanger and are among the most energy
efficient technologies for heating and cooling.
3. Heat Pump Water Heater Program – This program promotes the installation of
heat pump water heaters which uses energy efficient heat pump technology to transfer
heat from the surrounding environment to the water.
4. High SEER Heat Pump Program – This program promotes high efficiency heat
pumps above the minimum standard SEER. A higher SEER heat pump uses
electricity more efficiently to provide the same level of cooling.
5. Programmable Thermostat Program – This program promotes programmable
thermostats which provide energy savings when programmed properly.
6. Residential Time Advantage Rates – Time Advantage Rates provide pricing signals
by time period to incent customers to shift their usage to lower cost periods.
Residential Customer Value Programs:
1. In-Home Energy Check-Up – This program provides for in-home energy audits
performed by Alabama Power Energy Sales and Efficiency personnel.
2. Online Energy Check-Up – This program makes an on-line energy audit available to
all residential customers.
Commercial Energy Efficiency Programs:
1. Energy Star Cooking – This program promotes Energy Star cooking equipment in
the commercial market.
2. Heat Pump Water Heater Program –This program promotes heat pump water
heaters in the commercial market.
3. High Efficiency Heat Pumps – This program promotes high efficiency heat pumps
in the commercial market.
4. Business Time Advantage Rates – Time Advantage Rates provide pricing signals by
time period to incent customers to shift their usage to lower cost periods.
38
Commercial and Industrial Customer Value Programs:
1. In-Business Energy Check-Up (Commercial) – This program makes available an inbusiness energy audit performed by Alabama Power Energy Sales and Efficiency
personnel.
2. Smart Energy Use Program (Industrial) – This program provides customers with
an evaluation of their manner (equipment type or technology application) and
practices of energy consumption.
As an electric supplier, Alabama Power’s goal is to maintain high reliability at cost-effective
rates, while providing exceptional customer service. With respect to energy efficiency, the
Company supports reasonable building codes and appliance standards that result in customers
becoming more efficient in their use of electricity. Alabama Power works with its customers to
assist them in becoming as efficient as possible. As part of these efforts, the Company’s energy
efficiency programs are reasonably expected to benefit all customers, enabling them to realize
lower rates than would have been the case had other alternatives been pursued (either supply side
or demand side).
III.F.
SUMMARY OF RESULTS
This section presents a summary of the results of the 2016 integrated resource planning process,
with the output being the 2016 Integrated Resource Plan. Key elements of the plan for the
Company include the following:
•
A significant change to the 2016 IRP is the delay of the next resource addition from 2030 to
2035. In the 2013 IRP, the Company showed a need for new peaking resources in 2030, with
any indicated need for intermediate resources being beyond the 20-year planning horizon. In
the 2016 IRP, the nearest resource need has shifted to 2035 (the last year of the 20-year
planning horizon) and is now shown as an intermediate resource technology. There is no
indicated resource need for baseload resource technology within the 20-year planning study.
It bears noting, however, that due to the relatively low prices projected for natural gas,
intermediate technologies are operating in a manner similar to baseload technologies, while
39
having more favorable capital cost economics for compliance with proposed environmental
rules and requirements.
•
The indicated delay in the need for new reliability-based resources is still largely due to
lower forecasted loads resulting from a slower than anticipated recovery from the effects of
the Great Recession. Even so, and as previously discussed, 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.
•
Since the 2013 IRP, the Company has made some decisions regarding the utilization of its
existing supply-side resources.
o In response to various environmental mandates affecting Company operations, the
Company has proceeded with fuel switching strategies from coal to natural gas at several
coal units, totaling 920 MW. In addition, the Company retired the Barry 3 and the
Gorgas 6-7 coal-fired units, totaling 425 MW. Finally, the Company placed on inactive
reserve the Barry 1-2 coal-fired units, totaling 250 MW. The combined effect of these
actions is to reduce the Company’s coal-fired resources by 1,595 MW. The transition of
the Company’s generating capacity through these decisions has been previously shown in
Figure II-B-1 on page 16.
o As seen in the 2013 IRP, the 2016 IRP reflects certain unit deratings for environmental
measures, specifically baghouses, causing the Company’s coal fleet to be derated a total
of 9 MW between 2015 and the summer of 2016.
o As part of its Power Supply Agreement with Alabama Power, the Alabama Municipal
Electric Authority will bring a 25 MW PPA for combined cycle capacity as a supply
resource, beginning in 2018.
40
•
While there are no major supply-side resource additions to the 2016 IRP as compared to the
2013 IRP, there are some minor additions to the Company’s demand-side resources. Over the
20-year planning window for the 2016 IRP, the Company expects small growth in its MW of
dispatchable DSM resources.
•
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, including: (1) the Resolute Forest Products PPA; (2) the Westervelt PPA; (3) the
Chisholm View PPA; and (4) the Buffalo Dunes PPA. The Company will continue to explore
opportunities to add additional renewable resources to its plan, either through the certificate
authority approved in Docket No. 32382 or another vehicle. Consistent with the certificate
authority, the APSC has approved three solar projects that will be reflected subsequent IRPs.
The two solar projects at army installations are expected to go into commercial operation
before the end of 2016 and the LaFayette solar project is scheduled to go into commercial
operation by the end of 2017.
41
IV. CONCLUSION
Based on the load forecast developed by the Company for the 2016 IRP and other inputs used in
that process, the electrical requirements of Alabama Power’s customers can be met reliably until
2035 with the Company’s existing supply-side and demand-side resources. While the Company
projects falling slightly below its diversified target long-term planning reserve margin in 2033, it
can rely on capacity reserves projected to be available on the System until 2035. Apart from a
relatively small amount of planned and potential renewable resources, the Company does not
currently plan to add any new generating capacity until 2035. The 2016 IRP indicates that
Alabama Power will need to add intermediate capacity resources in 2035 to reliably meet its
customers’ projected demand. As discussed, however, there are a number of factors that could
accelerate the Company’s projected capacity need, perhaps significantly, such as movement to a
higher long-term planning reserve margin, the addition of new customers, faster customer
demand growth, changes in the Company’s DSM programs, and the retirement of additional coal
units in response to new environmental rules or requirements, such as the CPP or the CCR Rule.
Of these factors, additional unit retirements would be the most impactful. The extent to which
the indicated year of need might shift would depend on the timing and magnitude of these and
other factors, as well as the manner in which a given factor impacts the IRP results.
The 2016 IRP provides customers with short-term and long-term electric service reliability in an
economically efficient manner through a diverse portfolio of resources. The Company has
developed a cost-effective and balanced resource strategy, while maintaining environmental
compliance flexibility for the benefit of customers. In addition, the Company is well-positioned
for increases in customer demand over the 20-year planning horizon. The Company believes its
2016 IRP, as described here, charts a rational course for reliably meeting customer demand in a
dynamic regulatory environment, while maintaining rates at or below the national average.
42
APPENDIX 1
Existing Supply-Side
Resources
A1-0
FIGURE A1-1
Existing Supply-Side Resources
Alabama Power Company Owned & Contracted Resource Summary
Plants
Fossil
9
Nuclear
1
Hydro
14
Ownership Total
24
Contracted Total
N/A
Total Owned & Contracted
Units
35
2
41
78
N/A
Nameplate/
Contract
Capacity
(MW)
8,918
1,720
1,668
12,306
1,421
13,727
IRP
Capacity
(MW)
8,879
1,757
1,716
12,352
985
13,337
Fossil Steam Plants
Plant
Barry
Gadsden
Nameplate
Capacity
(MW)
125
125
IRP
Capacity
(MW)
0
0
In-Service
Year
1954
1954
350
700
60
60
362
757
64
66
1969
1971
1949
1949
1
125
127
1960
2
125
130
1960
3
125
130
1961
4
5
6
7
8
9
10
1
2
1
2
3
4
20
125
880
128
838
1962
1974
156
165
700
150
150
606
606
660
660
6,653
163
172
704
157
153
634
639
687
699
6,608
Unit
1
2
2
Nameplate
Capacity
(MW)
860
860
1,720
IRP
Capacity
(MW)
874
883
1,757
Unit
1
2
3
4
5
1
2
Gaston
Gorgas
Greene County
Miller
Total
Notes
Barry 1 on Inactive Reserve beginning 2016
Barry 2 on Inactive Reserve beginning 2016
Barry 3 retired on August 24, 2015
Ratings reflect 50% Alabama Power operating capacity; 100% owned by
Southern Electric Generating Company (SEGCO)
Gorgas 6 retired on August 24, 2015
Gorgas 7 retired on August 24, 2015
1956
1958
1972
1965
1966
1978
1985
1989
1991
Ratings reflect Alabama Power 60% ownership
Ratings reflect Alabama Power 60% ownership
Ratings reflect Alabama Power 91.8% ownership
Ratings reflect Alabama Power 91.8% ownership
Nuclear Steam Plants
Plant
Farley
Total
In-Service
Year
1975
1979
A1-1
Notes
Alabama Power Company Supply-Side Resource Summary - cont.
Unit
2
3
4
5
6
7
8
9
10
9
Nameplate
Capacity
(MW)
80
80
80
80
80
80
80
80
80
720
Unit
6
7
1
Nameplate
Capacity
(MW)
535
535
123
1
1
5
105
236
1,535
Plant
Unit
Nameplate
Capacity
(MW)
Gaston
A
1
10
10
Plant
Greene County
Total
Plant
Barry
Washington County
Lowndes County
Theodore
Total
Total
Gas-Fired Plants (Combustion Turbines)
IRP
Capacity
In-Service
(MW)
Year
Notes
84
1996
82
1996
81
1995
82
1995
81
1995
80
1995
83
1996
82
1996
85
1996
740
Gas-Fired Plants (Combined Cycles)
IRP
Capacity
In-Service
(MW)
Year
Notes
550
2000
550
2001
100
1999
Co-generation plant
Co-generation plant located at SABIC Innovative Plastics (formerly GE
Plastics)
92
1999
231
2001
Co-generation plant
1,523
Oil-Fired Plants (Combustion Turbines)
IRP
Capacity
In-Service
(MW)
Year
Notes
8
1970
8
Contracted Capacity
Plant
Calhoun Power PPA
Westervelt PPA
Chisholm View PPA
Buffalo Dunes PPA
Other
Total
Contract
Capacity
(MW)
700
8
202
202
IRP
Capacity
(MW)
632
4
20
20
309
1,421
309
985
Start
Year
2003
2012
2013
2014
Notes
Represents net capacity that the Company has rights to through various
contracts
A1-2
Alabama Power Company Supply-Side Resource Summary - cont.
Hydro Electric Plants
Plant
Weiss
Henry
Logan Martin
Lay
Mitchell
Jordan
Bouldin
Martin
Thurlow
Yates
Harris
Smith
Bankhead
Holt
Total
Unit
1
2
3
1
2
3
1
2
3
1
2
3
4
5
6
4
5
6
7
1
2
3
4
1
2
3
1
2
3
4
1
2
3
1
2
1
2
1
2
1
1
41
Nameplate
Capacity
(MW)
29.25
29.25
29.25
24.3
24.3
24.3
45
45
45
29.5
29.5
29.5
29.5
29.5
29.5
20
50
50
50
25
25
25
25
75
75
75
46
41
40
55
34.02
34.02
12.96
23.5
23.5
66
66
78.75
78.75
53.985
46.944
1,668
IRP
Capacity
(MW)(1)
74
70
135
182
166
136
226
186
81
47
132
180
56
45
1,716
In-Service
Year
1962
1961
1961
1966
1966
1966
1964
1964
1964
1968
1968
1967
1967
1967
1967
1949
1985
1985
1985
1928
1928
1928
1928
1967
1967
1967
1926
1926
1926
1952
1930
1930
1930
1928
1928
1983
1983
1961
1962
1963
1968
(1) Summer Net Capacity MW represent the total for the plant
A1-3
Notes
Upper Coosa Group
Upper Coosa Group
Upper Coosa Group
Upper Coosa Group
Upper Coosa Group
Upper Coosa Group
Upper Coosa Group
Upper Coosa Group
Upper Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Lower Coosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Tallapoosa Group
Warrior Group
Warrior Group
Warrior Group
Warrior Group

2013 Integrated Resource Plan

Transcription

Similar documents

what`s for sale? - Alabama Butterbean Festival

Sponsor Flyer.LR - Southeast Alabama Mud Track

Alabama Joint Leadership Development Conference

I`m helping to end MS by participating in the 2016 Jayman BUILT MS

The Board of Directors of Qatar Fuel (WOQOD) is pleased to invite

5 `S` Training Program at ABV-IIITM, Gwalior on 21.07.2016

Tommie Turvey - Alabama Horse Council

Porky Expo Flyer

View how the story appeared on the page (in PDF)

Clemon will exit U.S. bench