UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2011~~2012



Commission File Number	Exact name of registrants as specified in their charters, address of principal executive offices and registrants' telephone number	IRS Employer Identification Number
1-8841	NEXTERA ENERGY, INC.	59-2449419
2-27612	FLORIDA POWER & LIGHT COMPANY 700 Universe Boulevard Juno Beach, Florida 33408 (561) 694-4000	59-0247775

State or other jurisdiction of incorporation or organization: Florida



		Name of exchange on which registered
Securities registered pursuant to Section 12(b) of the Act:
NextEra Energy, Inc.:	Common Stock, $0.01 Par Value	New York Stock Exchange
Florida Power & Light Company: None

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act of 1933.

NextEra Energy, Inc. Yes þ No o Florida Power & Light Company Yes þ No o

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.

NextEra Energy, Inc. Yes o No þ Florida Power & Light Company Yes o No þ

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days.

NextEra Energy, Inc. Yes þ No o Florida Power & Light Company Yes þ No o

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).

NextEra Energy, Inc. Yes þ No o Florida Power & Light Company Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrants are a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Securities Exchange Act of 1934.



NextEra Energy, Inc.	Large Accelerated Filer þ	Accelerated Filer o	Non-Accelerated Filer o	Smaller Reporting Company o
Florida Power & Light Company	Large Accelerated Filer o	Accelerated Filer o	Non-Accelerated Filer þ	Smaller Reporting Company o

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ¨ No þ

Aggregate market value of the voting and non-voting common equity of NextEra Energy, Inc. held by non-affiliates as of June 3029, ~~2011~~2012 (based on the closing market price on the Composite Tape on June 3029, ~~2011~~2012) was $2428,~~179~~982,~~141~~338,~~166~~359.

There was no voting or non-voting common equity of Florida Power & Light Company held by non-affiliates as of June 3029, ~~2011~~2012.

The number of shares outstanding of NextEra Energy, Inc. common stock, as of the latest practicable date: Common Stock, $0.01 par value, outstanding as of January 31, ~~2012~~2013: ~~416~~ 423,~~208~~867,~~761~~308 shares.

As of January 31, ~~2012~~2013, there were issued and outstanding 1,000 shares of Florida Power & Light Company common stock, without par value, all of which were held, beneficially and of record, by NextEra Energy, Inc.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of NextEra Energy, Inc.'s Proxy Statement for the ~~2012~~2013 Annual Meeting of Shareholders are incorporated by reference in Part III hereof.

________________________

This combined Form 10-K represents separate filings by NextEra Energy, Inc. and Florida Power & Light Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Florida Power & Light Company makes no representations as to the information relating to NextEra Energy, Inc.'s other operations.

Florida Power & Light Company meets the conditions set forth in General Instruction I.(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format.

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DEFINITIONS

Acronyms and defined terms used in the text include the following:

Term	Meaning
AFUDC	allowance for funds used during construction
AFUDC - debt	debt component of allowance for funds used during construction
AFUDC - equity	equity component of allowance for funds used during construction
AOCI	accumulated other comprehensive income
capacity clause	capacity cost recovery clause, as established by the FPSC
CFTC	U.S. Commodity Futures Trading Commission
CO2	carbon dioxide
DOE	U.S. Department of Energy
Duane Arnold	Duane Arnold Energy Center
EPA	U.S. Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FPL	Florida Power & Light Company
FPL FiberNet	~~Fiber~~fiber-optic telecommunications business
FPSC	Florida Public Service Commission
fuel clause	fuel and purchased power cost recovery clause, as established by the FPSC
GAAP	generally accepted accounting principles in the U.S.
GHG	greenhouse gas(es)
ISO	independent system operator
ITCs	investment tax credits
kw	kilowatt
kwh	kilowatt-hour(s)
Lone Star	Lone Star Transmission, LLC
Management's Discussion	Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
mortgage	mortgage and deed of trust dated as of January 1, 1944, from FPL to Deutsche Bank Trust Company Americas, as supplemented and amended
mw	megawatt(s)
mwh	megawatt-hour(s)
NEE	NextEra Energy, Inc.
NEECH	NextEra Energy Capital Holdings, Inc.
NEER	NextEra Energy Resources, LLC
NEET	NextEra Energy Transmission, LLC
NERC	North American Electric Reliability Corporation
NHT	New Hampshire Transmission, LLC
Note __	Note __ to consolidated financial statements
NOx	nitrogen oxide
NRC	U.S. Nuclear Regulatory Commission
O&M expenses	other operations and maintenance expenses in the consolidated statements of income
OCI	other comprehensive income
OTC	over-the-counter
OTTI	other than temporary impairment
PJM	PJM Interconnection, L.L.C.
PMI	NextEra Energy Power Marketing, LLC
Point Beach	Point Beach Nuclear Power Plant
PTCs	production tax credits
PUCT	Public Utility Commission of Texas
PURPA	Public Utility Regulatory Policies Act of 1978, as amended
PV	photovoltaic
regulatory ROE	return on common equity as determined for regulatory purposes
RFP	request for proposal
ROE	return on common equity
regulatory ROE	return on common equity as determined for regulatory purposes
RPS	renewable portfolio standards
RTO	regional transmission organization
Seabrook	Seabrook Station
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
U.S.	United States of America
WCEC	FPL's West County Energy Center in western Palm Beach County, Florida

NEE, FPL, NEECH and NEER each has subsidiaries and affiliates with names that may include NextEra Energy, FPL, NextEra Energy Resources, FPL Group Capital, FPL Energy, FPLE and similar references. For convenience and simplicity, in this report the terms NEE, FPL, NEECH and NEER are sometimes used as abbreviated references to specific subsidiaries, affiliates or groups of subsidiaries or affiliates. The precise meaning depends on the context.

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TABLE OF CONTENTS

		Page No.
Definitions		2
Forward-Looking Statements		3
	PART I
Item 1.	Business	4
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	36
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39
	PART II
Item 5.	Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	3940
Item 6.	Selected Financial Data	41
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	4142
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	6770
Item 8.	Financial Statements and Supplementary Data	6871
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	~~120~~127
Item 9A.	Controls and Procedures	~~120~~127
Item 9B.	Other Information	~~120~~127
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	~~121~~128
Item 11.	Executive Compensation	~~121~~128
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~121~~128
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~121~~128
Item 14.	Principal Accounting Fees and Services	~~122~~129
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	~~123~~130
Signatures		~~131~~139

FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, strategies, future events or performance (often, but not always, through the use of words or phrases such as will, will ~~likely~~ result, are expected to, will continue, is anticipated, aim, believe, could, should, would, estimated, may, plan, potential, future, projection, goals, target, outlook, predict and intend or words of similar meaning) are not statements of historical facts and may be forward- looking. Forward-looking statements involve estimates, assumptions and uncertainties. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, important factors included in Part I, Item 1A. Risk Factors (in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements) that could have a significant impact on NEE's and/or FPL's operations and financial results, and could cause NEE's and/or FPL's actual results to differ materially from those contained or implied in forward-looking statements made by or on behalf of NEE and/or FPL in this combined Form 10-K, in presentations, on their respective websites, in response to questions or otherwise.

Any forward-looking statement speaks only as of the date on which such statement is made, and NEE and FPL undertake no obligation to update any forward-looking statement to reflect events or circumstances, including, but not limited to, unanticipated events, after the date on which such statement is made, unless otherwise required by law. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement.

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PART I

Item 1. Business

OVERVIEW

NextEra Energy, Inc. (hereafter, NEE) is one of the largest electric power companies in North America, with over 4142,000 mw of generating capacity in 2426 states in the U.S. and 34 provinces in Canada, and employing approximately 14,800 people as of December 31, ~~2011~~2012. NEE provides retail and wholesale electric services to ~~more~~nearly ~~than~~5 4 million customers and owns generation, transmission and distribution facilities to support its services. It also purchases electric power for resale to its customers and provides risk management services related to power and gas consumption for a limited number of customers. NEE is the largest generator in ~~the~~North ~~U.S.~~America of renewable energy from the wind and sun. NEE owns and ~~owned~~operates approximately 1817% of the installed base of U.S. wind power production capacity asand operates approximately 14% of ~~December~~the ~~31,~~installed ~~2011~~base of U. ~~NEE~~S. ~~also~~utility-scale ~~produces~~solar ~~electricity~~power ~~from~~production ~~solar~~capacity ~~facilities~~as of December 31, ~~and~~2012. NEE also owns and operates one of the largest fleets of nuclear power stations in the U.S., with eight reactors at five sites located in four states, representing approximately 6% of U.S. nuclear power electric generating capacity as of December 31, ~~2011~~2012. NEE's business strategy has emphasized the development, acquisition and operation of renewables, nuclear and natural gas-fired generation facilities in response to long-term federal policy trends supportive of zero and low air emissions sources of power. NEE's generation fleet has significantly lower rates of emissions of CO2, SO2 and NOx than the average rates of the U.S. electric power industry with approximately 9397% of its ~~2011~~2012 generation, measured by mwh produced, coming from renewables, nuclear and natural gas-fired facilities. Certain environmental attributes of NEE's electric generating facilities, such as renewable energy credits, emissions reductions, offsets, allowances and the avoided emission of GHG pollutants, have been or likely will be sold or transferred to third parties, who are solely entitled to the reporting rights and ownership of the environmental attributes.

NEE was incorporated in 1984 under the laws of Florida and conducts its operations principally through two wholly-owned subsidiaries, Florida Power & Light Company (hereafter, FPL) and NextEra Energy Resources, LLC (hereafter, NEER). NextEra Energy Capital Holdings, Inc. (hereafter, NEECH), another wholly-owned subsidiary of NEE, owns and provides funding for NEER's and NEE's other operating subsidiaries, other than FPL and its subsidiaries. NEE's two principal businesses also constitute NEE's reportable segments for financial reporting purposes~~, as illustrated below:~~.

FPL is a rate-regulated electric utility engaged primarily in the generation, transmission, distribution and sale of electric energy in Florida. FPL is the largest electric utility in the state of Florida and one of the largest electric utilities in the U.S. based on ~~generation~~retail mwh sales. FPL is vertically integrated, with approximately 24,~~500~~100 mw of generating capacity as of December 31, ~~2011~~2012. FPL's investments in its infrastructure since 2001, such as modernizing less efficient generating plants ~~and upgrading its transmission and distribution systems, have allowed FPL~~ to produce more energy with less fuel and fewer air emissions, and upgrading its transmission and distribution systems to deliver service reliability that ~~was~~is ~~among~~ the best of the Florida investor-owned utilities, have provided significant benefits to FPL's customers, all while providing residential and commercial bills that were among the lowest in Florida and below the national average based on a rate per kwh as of July ~~2011~~2012. With 85approximately 95% of its power generation coming from natural gas, nuclear and solar, FPL is also one of the cleanest electric utilities in the nation. Based on ~~2011~~2012 information, FPL's emissions rates for CO2, SO2 and NOx were 3629%, 8491% and 7267% lower, respectively, than the average rates of the U.S. electric power industry.

NEER is one of the largest wholesale generators of electric power in the U.S., with ~~approximately~~over 1618,~~600~~100 mw of generating capacity across 2224 states and 34 Canadian provinces as of December 31, ~~2011~~2012. NEER produces the majority of its electricity from clean and renewable sources, including wind, ~~solar~~ and ~~hydro~~solar. NEER also provides full energy and capacity requirements services, ~~owns~~engages ain ~~retail~~power ~~electricity~~and ~~provider~~gas ~~serving~~marketing ~~customers~~and intrading 13activities, ~~states~~participates ~~and~~in ~~the~~natural ~~District~~gas ofproduction ~~Columbia~~ and ~~engages~~pipeline ininfrastructure ~~power~~development and ~~gas~~owns ~~marketing~~a ~~and~~retail ~~trading~~electricity ~~activities~~provider.

NEECH's other business activities are primarily conducted through FPL FiberNet and Lone Star. FPL FiberNet delivers wholesale and enterprise telecommunications services in Florida and certain areas of the South Central U.S. Lone Star, a rate-regulated transmission service provider in Texas, is constructing transmission lines and other associated facilities in Texas.

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~~NEE~~NEECH's ~~seeks~~other tobusiness ~~create~~activities ~~value~~are inprimarily ~~its~~conducted ~~two~~through ~~principal~~NEET ~~businesses by meeting its customers' needs more economically~~ and ~~more~~FPL ~~reliably~~FiberNet. NEET ~~than~~conducts its ~~competitors,~~operations asprincipally ~~described~~through intwo ~~more~~wholly-owned ~~detail~~subsidiaries, inLone ~~the~~Star, ~~following~~a ~~sections. NEE's~~rate-regulated ~~strategy~~transmission ~~has~~service ~~resulted~~provider in ~~profitable~~Texas, ~~growth over sustained periods at both FPL~~ and ~~NEER. Management~~NHT, ~~seeks~~a torate-regulated ~~grow~~transmission ~~each~~owner ~~business~~ in aNew ~~manner~~Hampshire. FPL ~~consistent~~FiberNet ~~with~~delivers ~~the~~wholesale ~~varying opportunities open to it~~ and ~~does~~enterprise ~~not~~telecommunications ~~maintain~~services ~~any~~in ~~specific~~Florida ~~goal~~and ascertain toareas ~~the relative size~~ of the ~~two~~South ~~businesses. However,~~Central ~~management believes that the diversification and balance represented by FPL and NEER is a valuable characteristic of the enterprise~~U.S.

NEE seeks to create value in its two principal businesses by meeting its customers' needs more economically and more reliably than its competitors, as described in more detail in the following sections. NEE's strategy has resulted in profitable growth over sustained periods at both FPL and NEER. Management seeks to grow each business in a manner consistent with the varying opportunities open to it and does not maintain any specific goal as to the relative size of the two businesses. However, management believes that the diversification and balance represented by FPL and NEER is a valuable characteristic of the enterprise. FPL and NEER, as well as other NEE subsidiaries, share common support functions with the objective of lowering costs and creating efficiencies for their businesses.

NEE'S OPERATING SUBSIDIARIES

I. FPL

FPL was incorporated under the laws of Florida in 1925, and is a wholly-owned subsidiary of NEE. FPL is a rate-regulated electric utility and is the largest electric utility in the state of Florida and one of the largest electric utilities in the U.S. based on ~~generation~~retail mwh sales. FPL, with 24,~~460~~057 mw of generating capacity at December 31, ~~2011~~2012, supplies electric service throughout most of the east and lower west coasts of Florida, serving ~~nearly~~more than 8.9 million people through approximately 4.6 million customer accounts. At December 31, ~~2011~~2012, FPL's service territory and plant locations are as follows (see Item 2 - Generating Facilities):

FRANCHISE AGREEMENTS AND COMPETITION

FPL's service to its retail customers is provided primarily under franchise agreements negotiated with municipalities or counties. ~~Municipalities~~Alternatively, municipalities and counties may form their own utility companies to provide service to their residents. In a few cases, ~~the~~an FPL franchise agreement provides the municipality or county the right to buy the distribution assets serving local residents at the end of the agreement. However, during the term of a franchise agreement, which is typically 30- years, the municipality or county agrees not to form its own utility, and FPL has the right to offer electric service to residents. FPL currently holds ~~178~~177 franchise agreements with various municipalities and counties in Florida with varying expiration dates through 2042. ~~Four~~Two of these franchise agreements expire in 2013, seven expire in 2014 and ~~174~~168 expire during the period ~~2014~~2015 through 2042. These franchise agreements cover approximately 8386% of FPL's retail customer base in Florida. Negotiations are ongoing to renew the franchise agreements that expire in 2013 and 2014. FPL considers its franchises to be adequate for the conduct of its business. FPL also provides service to 1112 other municipalities and to 22 unincorporated areas within its service area without franchise agreements pursuant to the general obligation to serve as a public utility, relying upon Florida law for access to public rights of way.

Because any retail customer may elect to provide his/her own services, FPL effectively must compete for an individual customer's business. As a practical matter, few customers provide their own service at the present time since FPL's cost of service is generally substantially lower than the cost of self-generation for the vast majority of customers. Changing technology and economic conditions could alter the favorable relative cost position that FPL currently enjoys; however, FPL seeks as a matter of strategy to ensure that it delivers superior value, in the form of high reliability, low bills and excellent customer service.

FPL also faces competition from other suppliers of electrical energy to wholesale customers and from alternative energy sources and self-generation for other customer groups, primarily industrial customers. In 2011, 2010 and 2009, operating revenues from wholesale and industrial customers combined represented approximately 3%, 3% and 4%, respectively, of FPL's total operating revenues.

The FPSC promotes cost competitiveness in the building of new steam generating capacity by requiring investor-owned electric utilities, including FPL, to issue a request for proposal (RFP) except when the FPSC determines that an exception from the RFP process is in the public interest. The RFP process allows independent power producers and others to bid to supply the new generating capacity. If a bidder has the most cost-effective alternative, meets other criteria such as financial viability and

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~~demonstrates~~Because ~~adequate~~any ~~expertise~~retail ~~and~~customer ~~experience~~may inelect ~~building~~to ~~and~~provide his/orher ~~operating~~own ~~generating~~electric ~~capacity~~services, ofFPL ~~the~~effectively ~~type~~must ~~proposed,~~compete ~~the~~for ~~investor-owned~~an ~~electric~~individual ~~utility~~customer's ~~would~~business. As ~~seek~~a topractical ~~negotiate~~matter, afew ~~purchased~~customers ~~power~~provide ~~agreement~~their ~~with~~own service at the ~~selected~~present ~~bidder~~time ~~and~~since ~~request~~FPL's ~~that~~cost ~~the~~of ~~FPSC~~service ~~approve~~is ~~the~~generally ~~terms~~substantially oflower than the ~~purchased~~cost ~~power~~of ~~agreement~~self-generation ~~and,~~for ifthe ~~appropriate,~~vast ~~provide~~majority ~~the~~of ~~required~~customers. Changing ~~authorization~~technology ~~for~~and ~~the~~economic ~~construction~~conditions ofcould alter the ~~bidder's~~favorable ~~generating~~relative ~~capacity. New~~cost ~~nuclear~~position ~~power~~that ~~plants~~FPL ~~are~~currently ~~exempt~~enjoys; ~~from~~however, ~~the~~FPL ~~RFP~~seeks ~~requirement. See~~as ~~FPL~~a ~~Sources~~matter of ~~Generation~~strategy -to ~~Nuclear~~ensure ~~Operations~~that ~~below~~it ~~regarding~~delivers ~~FPL's~~superior ~~planned~~value, ~~two~~in ~~additional~~the ~~nuclear~~form ~~units~~of athigh ~~Turkey~~reliability, ~~Point~~low bills and excellent customer service.

FPL also faces competition from other suppliers of electrical energy to wholesale customers and from alternative energy sources and self-generation for other customer groups, primarily industrial customers. In each of 2012, 2011 and 2010, operating revenues from wholesale and industrial customers combined represented approximately 3% of FPL's total operating revenues.

The FPSC promotes cost competitiveness in the building of new steam and solar generating capacity by requiring investor-owned electric utilities, including FPL, to issue an RFP except when the FPSC determines that an exception from the RFP process is in the public interest. The RFP process allows independent power producers and others to bid to supply the new generating capacity. If a bidder has the most cost-effective alternative, meets other criteria such as financial viability and demonstrates adequate expertise and experience in building and/or operating generating capacity of the type proposed, the investor-owned electric utility would seek to negotiate a purchased power agreement with the selected bidder and request that the FPSC approve the terms of the purchased power agreement and, if appropriate, provide the required authorization for the construction of the bidder's generating capacity.

New nuclear power plants are exempt from the RFP requirement. See FPL Sources of Generation - Nuclear Operations below regarding FPL's planned two additional nuclear units at Turkey Point.

CUSTOMERS AND REVENUE

FPL's primary source of operating revenues is from its retail customer base; it also serves a limited number of wholesale customers within Florida. The percentage of FPL's operating revenues and customer accounts by customer class were as follows:

For both retail and wholesale customers, the prices (or rates) that FPL may charge are controlled by regulation, by the FPSC in the case of retail customers, and by the FERC in the case of wholesale customers. In general, under U.S. and Florida law, regulated rates are intended to cover the cost of providing service, including an appropriate rate of return on capital employed. However, the regulatory bodies have authority to determine the relevant cost of providing service and the appropriate rate of return on capital employed and there can be no guarantee that FPL will be able to earn any particular rate of return or recover all ~~or any portion~~ of its costs through regulated rates. See the discussion of regulation at FPL Regulation ~~- FPL Rate Regulation~~ below.

As noted above, FPL seeks to maintain attractive rates for its customers. A common benchmark used in the electric power industry for comparing rates across companies is the cost per 1,000 kwh of consumption per month for a residential customer. FPL's 2011 average cost per 1,000 kwh of monthly residential usage was the lowest of the 55 electric utilities within Florida as indicated below:

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FPL seeks to maintain attractive rates for its customers. Since rates are largely cost-based, maintaining low rates requires a strategy focused on developing and maintaining a low cost position. A common benchmark used in the electric power industry for comparing rates across companies is the cost per 1,000 kwh of consumption per month for a residential customer. FPL's 2012 average cost per 1,000 kwh of monthly residential usage was the lowest of the 55 electric utilities within Florida as indicated below:

TRANSMISSION AND DISTRIBUTION

FPL provides service to its customers through an integrated transmission and distribution system that links ~~all~~ its generation facilities to ~~all~~ its customers. FPL also maintains interconnection facilities with neighboring utilities and wholesale power providers, enabling it to buy and sell wholesale electricity outside its service territory and to enhance the reliability of its own network and support the reliability of neighboring networks. FPL's transmission system carries high voltage electricity from its generating facilities to substations where the electricity is stepped down to lower voltage levels and is sent through the distribution system to its customers.

A key element of FPL's strategy is to provide highly reliable service to its customers. The transmission and distribution system is susceptible to interruptions or outages from a wide variety of sources including weather, animal interference, traffic accidents, equipment failure and many others, and FPL seeks to reduce or eliminate outages where economically practical and to restore service rapidly inwhen ~~the~~outages ~~event of an outage~~occur. A common industry benchmark for transmission and distribution system reliability is the system average interruption duration index (SAIDI), which represents the number of minutes the average customer is without power during a time period. ~~During~~ For the five years ~~ended 2010~~2007-2011, FPL's ~~had~~average ~~the~~annual ~~best~~SAIDI ~~average~~was ~~SAIDI~~the best of the ~~Florida~~ investor-owned utilities in Florida.

FPL SYSTEM CAPABILITY AND LOAD

At December 31, ~~2011~~2012, FPL's resources for serving load consisted of 26,~~538~~020 mw, of which 24,~~460~~057 mw were from FPL-owned facilities (see Item 2 - Generating Facilities) and 21,~~078~~963 mw were available through purchased power agreements (see FPL Sources of Generation - Purchased Power below). Occasionally, unusually cold temperatures during the winter months result in significant increases in electricity usage for short periods of time. However, customer usage and operating revenues are typically higher during the summer months, largely due to the prevalent use of air conditioning in FPL's service territory. The highest peak load FPL has served to date was 24,346 mw, which occurred on January 11, 2010. FPL had adequate resources available at the time of this peak to meet customer demand.

FPL's projected reserve margin for the summer of ~~2012~~2013 is approximately 28%. This reserve margin is expected to be achieved through the combination of available output from FPL's active generating units, purchased power agreements and the capability to reduce peak demand through the implementation of demand side management programs, including load management which was estimated at December 31, ~~2011~~2012 to be capable of reducing demand by 1,~~817~~865 mw, and energy efficiency and conservation programs. See FPL Sources of Generation - Fossil Operations and Nuclear Operations below regarding generation projects currently under construction.

FPL SOURCES OF GENERATION

FPL relies upon a ~~diverse~~ mix of fuel sources for its generating facilities, along with purchased power, in order to maintain the flexibility to achieve a more economical fuel mix by responding to market and industry developments. See descriptions of fossil, nuclear and solar operations below and a listing of FPL's generating facilities in Item 2 - Generating Facilities.

FPL's 2011 fuel mix based on mwh produced, including purchased power, was as follows:

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FPL's 2012 fuel mix based on mwh produced, including purchased power, was as follows:

During 2012, nuclear generation was lower than in 2011 as a result of outages related to a generation uprate project at FPL's nuclear units.

Fossil Operations (Natural Gas, Coal and Oil)

At December 31, ~~2011~~2012, FPL owned and operated 7873 units that used fossil fuels such as natural gas and/or oil, and had a joint ownership interest in three coal units, which combined provided 2120,~~455~~696 mw of generating capacity for FPL. These fossil units are out of service from time to time for routine maintenance or on standby during periods of reduced electricity demand.

FPL's natural gas plants require natural gas transportation, supply and storage. FPL has firm transportation contracts in place with ~~four~~five different transportation suppliers with expiration dates ranging from 2015 to 2036 that together are expected to satisfy substantially all of the currently anticipated needs for natural gas transportation atthrough ~~existing units~~2016. To the extent desirable, FPL also purchases interruptible natural gas transportation service from these natural gas transportation suppliers based on pipeline availability. FPL has several short- and medium-term natural gas supply contracts to provide a portion of FPL's anticipated needs for natural gas. The remainder of FPL's natural gas requirements is purchased in the spot market. FPL has an agreement for the storage of natural gas that expires in ~~2013~~2014. See Note 1413 - Contracts. With respect to its oil plants, FPL obtains its fuel requirements in the spot market.

~~St.~~In ~~Johns~~December ~~River~~2012, ~~Power~~FPL ~~Park~~issued ~~(SJRPP)~~an ~~Units~~RFP ~~Nos. 1~~for ~~and~~an 2,approximately in700-mile ~~which~~natural ~~FPL~~gas ~~has~~pipeline athat ~~joint~~will ~~ownership~~help ~~interest,~~FPL ~~has~~identify aand ~~coal~~evaluate ~~supply~~options ~~and~~for new natural gas transportation ~~contract~~infrastructure ~~for~~in ~~all~~Florida ofto meet the ~~2012~~growing ~~fuel~~need ~~needs~~for ~~and~~natural agas ~~portion~~power. The proposed pipeline will be composed of ~~the~~two ~~2013~~segments and ~~2014~~be ~~fuel~~operational ~~needs~~beginning ~~for~~in ~~those units~~2017. ~~All~~The ofupstream ~~the~~segment ~~transportation~~will ~~requirements~~originate at an existing hub in western Alabama and end at a ~~portion~~new ofhub to be built in Central Florida that will allow the ~~coal~~new ~~supply~~pipeline ~~needs~~to ~~for~~interconnect ~~Scherer~~with ~~Unit~~peninsular NoFlorida's two existing natural gas pipelines. 4, The downstream segment will originate at the ~~other~~new ~~coal~~Central ~~unit~~Florida hub and end in ~~which~~Martin County, Florida at FPL's ~~has~~Martin power plant. FPL plans to propose a ~~joint~~self-build ~~ownership~~option ~~interest~~for the downstream segment of the pipeline, ~~are~~which, ~~covered~~if byselected, ais ~~series~~expected ofto ~~annual~~be built, owned and ~~long~~operated by a FERC-~~term~~regulated ~~contracts~~affiliate. The ~~remaining~~bids ~~fuel~~are ~~requirements~~due ~~for~~in ~~these~~April ~~units~~2013 ~~will~~with the winning proposal(s) expected to be ~~obtained~~selected inby the ~~spot~~end ~~market~~of June 2013. ~~See~~The ~~Note 14 - Contracts~~pipeline will be subject to regulatory approvals.

~~Modernization Projects~~St. ~~FPL~~ isJohns inRiver ~~the~~Power ~~process~~Park of(SJRPP) ~~modernizing~~Units ~~its~~Nos. 1 ~~Cape Canaveral~~ and ~~Riviera~~2, ~~Beach~~in ~~power~~which ~~plants~~FPL tohas ~~high-efficiency~~a ~~natural~~joint ~~gas-fired~~ownership ~~units~~interest, ~~and~~has ~~expects~~a ~~the~~coal ~~units~~supply toand betransportation ~~placed~~contract infor ~~service~~a byportion ~~June~~of the 2013 and by 2014, ~~respectively. Each~~fuel ~~modernized~~needs ~~plant~~for isthose ~~expected to provide approximately 1,200 mw of capacity~~units. InAll ~~November~~of ~~2011,~~the ~~FPL~~transportation ~~filed~~requirements and a ~~need~~portion ~~petition~~of ~~with~~ the ~~FPSC~~coal tosupply ~~modernize~~needs ~~its~~for ~~Port~~Scherer ~~Everglades~~Unit ~~power~~No. 4, ~~plant~~the toother acoal ~~high-efficiency natural gas-fired~~ unit~~. The~~ ~~modernized~~in ~~Port~~which ~~Everglades~~FPL ~~unit~~has isa ~~expected~~joint toownership ~~provide approximately 1~~interest,~~280~~ mware ofcovered ~~capacity,~~by bea inseries ~~service~~of inannual ~~2016~~ and ~~cost~~long-term ~~approximately $1~~contracts.~~2 billion.~~ The ~~modernization~~remaining offuel ~~the~~requirements ~~Port~~for ~~Everglades~~these ~~plant~~units iswill ~~contingent~~be ~~upon,~~obtained ~~among~~in ~~other~~the ~~things,~~spot ~~FPSC approval~~market. An See ~~FPSC decision regarding the modernization of the Port Everglades plant is expected in late March 2012~~Note 13 - Contracts.

~~Nuclear~~Modernization ~~Operations~~Projects. FPL is in the process of modernizing its Cape Canaveral, Riviera Beach and Port Everglades power plants to high-efficiency natural gas-fired units that will provide approximately 1,200 mw, 1,200 mw and 1,280 mw of capacity, respectively, and be placed in service by June 2013, June 2014 and mid-2016, respectively. In May 2012, the Florida Industrial Power Users Group appealed the FPSC's order approving the Port Everglades modernization, which appeal will be heard by the Florida Supreme Court.

At December 31, 2011, FPL owned, or had undivided interests in, and operated the following four nuclear units with a total net generating capacity of 2,970 mw.

Facility	mw	Operating LicenseExpiration Dates
St. Lucie Unit No. 1	839	2036
St. Lucie Unit No. 2	745	2043
Turkey Point Unit No. 3	693	2032
Turkey Point Unit No. 4	693	2033

FPL has several contracts for the supply of uranium and the conversion, enrichment and fabrication of nuclear fuel with expiration dates ranging from March 2012 through 2022. See Note 14 - Contracts. NRC regulations require FPL to submit a plan for decontamination and decommissioning five years before the projected end of plant operation. FPL's current plans, under the applicable operating licenses, provide for prompt dismantlement of Turkey Point Units Nos. 3 and 4 with decommissioning activities commencing in 2032 and 2033, respectively. Current plans provide for St. Lucie Unit No. 1 to be mothballed beginning in 2036 with decommissioning activities to be integrated with the prompt dismantlement of St. Lucie Unit No. 2 commencing in 2043. See Management's Discussion - Critical Accounting Policies and Estimates - Nuclear Decommissioning and Fossil/Solar Dismantlement.

Projects to Add Additional Capacity. FPL is in the process of adding approximately 450 mw to 490 mw of capacity at its existing nuclear units at St. Lucie and Turkey Point, which is expected to result in significant fuel cost savings compared to other sources of generation over the lives of the units. The additional capacity is projected to be placed in service by 2013; approximately 31 mw were placed in service in May 2011 at St. Lucie Unit No. 2. As part of the conditions of certification by the FDEP for the Turkey Point project, FPL was required to implement a monitoring plan in and around the Turkey Point cooling canals due to concerns over potential saltwater intrusion beyond FPL's property. Monitoring under the plan includes collection of data prior to and after the additional capacity is placed in service. Data for the first year has been collected and provided to the FDEP. The ultimate results of the monitoring plan are uncertain, and the financial and operational impacts on FPL, if any, cannot be determined at this time. In 2008, the FPSC approved FPL's need petition for two additional nuclear units at its Turkey Point site. The two units combined are expected to add approximately 2,200 mw of capacity and have projected in-service dates between 2022 and 2023. Additional approvals from other regulatory agencies will be required later in the development process.

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~~for~~Nuclear 2012 are all expanded scope outages related to the addition of capacity at the existing nuclear units which are expected to require the unit to be removed from service for between 110 and 160 days. The following table summarizes each unit's current or next scheduled refueling outage:Operations

Facility		Beginning of Current or NextScheduled Refueling Outage
St. Lucie Unit No. 1		November 2011
St. Lucie Unit No. 2		August 2012
Turkey Point Unit No. 3		February 2012
Turkey Point Unit No. 4		November 2012

At December 31, 2012, FPL owned, or had undivided interests in, and operated the following four nuclear units with a total net generating capacity of 3,326 mw.



Facility	mw	Operating License Expiration Dates
St. Lucie Unit No. 1	981	2036
St. Lucie Unit No. 2	843	2043
Turkey Point Unit No. 3	809	2032
Turkey Point Unit No. 4	693	2033

FPL has several contracts for the supply of uranium and the conversion, enrichment and fabrication of nuclear fuel with expiration dates ranging from June 2013 through 2023. See Note 13 - Contracts. NRC regulations require FPL to submit a plan for decontamination and decommissioning five years before the projected end of plant operation. FPL's current plans, under the applicable operating licenses, provide for prompt dismantlement of Turkey Point Units Nos. 3 and 4 with decommissioning activities commencing in 2032 and 2033, respectively. Current plans provide for St. Lucie Unit No. 1 to be mothballed beginning in 2036 with decommissioning activities to be integrated with the prompt dismantlement of St. Lucie Unit No. 2 commencing in 2043.

Projects to Add Additional Capacity. FPL is in the final stages of a generation uprate project which is expected to add at least 510 mw of capacity at its existing nuclear units at St. Lucie and Turkey Point, which are expected to result in significant fuel cost savings compared to other sources of generation over the lives of the units. As of December 31, 2012, approximately 395 mw of the additional capacity were in service; the remaining amount of additional capacity is projected to be placed in service in the spring of 2013. As part of the conditions of certification by the FDEP for the Turkey Point units, FPL was required to implement a monitoring plan in and around the Turkey Point cooling canals due to concerns over potential saltwater intrusion beyond FPL's property. Monitoring under the plan includes collection of data prior to and after the additional capacity is placed in service. Data for the first two years has been collected and provided to the FDEP. The ultimate results of the monitoring plan are uncertain, and the financial and operational impacts on FPL, if any, cannot be determined at this time. In 2008, the FPSC approved FPL's need petition for two additional nuclear units at its Turkey Point site. The two units combined are expected to add approximately 2,200 mw of capacity and have projected in-service dates between 2022 and 2023. Additional approvals from other regulatory agencies will be required later in the development process. Additionally, the issuance of a combined operating license by the NRC may be delayed due to required revisions to the NRC's Waste Confidence Rule concerning the storage of spent nuclear fuel after reactor operation, which revisions are not expected to be finalized before late 2014.

Nuclear Unit Scheduled Refueling Outages. FPL's nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, including inspections, repairs and certain other modifications. Scheduled nuclear refueling outages typically require the unit to be removed from service for variable lengths of time. The duration is longer for expanded scope outages, one of which is expected to be completed in the spring of 2013 at Turkey Point Unit No. 4. The following table summarizes each unit's current or next scheduled refueling outage:



Facility		Beginning of Current or Next Scheduled Refueling Outage
St. Lucie Unit No. 1		September 2013
St. Lucie Unit No. 2		March 2014
Turkey Point Unit No. 3		January 2014
Turkey Point Unit No. 4		November 2012

Disposition of Spent Nuclear Fuel. FPL's nuclear facilities use both on-site storage pools and dry storage casks to store spent nuclear fuel generated by these facilities, which are expected to allow FPL to store spent nuclear fuel at these facilities through license expiration.

Under the Nuclear Waste Policy Act of 1982, as amended (Nuclear Waste Policy Act), the DOE is responsible for the development of a repository for the disposal of spent nuclear fuel and high-level radioactive waste. As required by the Nuclear Waste Policy Act, FPL is a party to contracts with the DOE to provide for disposal of spent nuclear fuel from its nuclear units.

The DOE was required to construct permanent disposal facilities and take title to and provide transportation and disposal for spent nuclear fuel by January 31, 1998 for a specified fee based on current generation from nuclear power plants. The DOE did not meet its statutory obligation for disposal of spent nuclear fuel under the Nuclear Waste Policy Act. In 2009, FPL and certain nuclear plant joint owners entered into a settlement agreement (spent fuel settlement agreement) with the U.S. government agreeing to dismiss with prejudice lawsuits filed against the U.S. government seeking damages caused by the DOE's failure to dispose of spent nuclear fuel from FPL's nuclear plants. The spent fuel settlement agreement permits FPL to make annual filings to recover certain spent fuel storage costs incurred by FPL which are payable by the U.S. government on an annual basis. In a separate lawsuit filed in 2011, FPL joined the Nuclear Energy Institute and several other nuclear plant owners and operators in petitioning the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) to challenge the DOE's decision to continue to collect the nuclear waste fee, which petition is pending. FPL will continue to pay fees to the U.S. government's nuclear waste fund pending the D.C. Circuit's decision on the fee suspension petition.

In March 2010, the DOE filed a motion with the NRC to withdraw its license application for a nuclear waste repository at Yucca Mountain. The DOE's withdrawal motion has been challenged and is being litigated before the NRC and the D.C. Circuit. In light of the Obama Administration's decision not to proceed with the Yucca Mountain repository project, the DOE established a Blue Ribbon Commission on America's Nuclear Future (BRC) to conduct a comprehensive review of policies for managing the back end of the nuclear fuel cycle and to provide recommendations for developing a safe, long-term solution to managing spent nuclear fuel and high-level radioactive waste. In January 2012, the BRC issued its report and recommendations which include a consent-based approach, working with all affected units of government, to siting future nuclear waste management facilities, creation of a new organization, independent of the DOE, dedicated solely to assuring the safe storage and ultimate disposal of spent nuclear fuel and high-level radioactive waste, providing access to the U.S. government's nuclear waste fund for the purpose of nuclear waste storage and disposal and initiating prompt efforts to develop geologic disposal facilities, consolidated interim storage facilities and transportation to those facilities. The BRC's recommendations are not expected to result in any immediate change to the nuclear waste management and disposal situation.

Recent Nuclear Developments. As a result of the impact of the March 2011 earthquake and tsunami on nuclear facilities in Japan, the NRC established a task force to conduct a comprehensive review of processes and regulations relating to nuclear facilities in the U.S. to determine whether the NRC should make additional improvements to its regulatory system and to make recommendations to the NRC for its policy direction. In July 2011, the NRC task force released its recommendations to the NRC and, since then, the NRC staff presented certain conclusions based on their review of the task force recommendations, which conclusions have been approved by the NRC. The NRC staff's report concluded that none of the findings addressed by the task force recommendations rise to the level of an imminent hazard to public health and safety. However, since the recommendations can contribute to safety improvements, the NRC staff proposed the following actions: 1) issue orders within approximately six months to require each nuclear site to purchase portable equipment and revise procedures to address multi-unit events, provide reliable spent fuel pool instrumentation and enhance containment venting capabilities for boiling water reactors (FPL's nuclear units do not use boiling water reactors); 2) request each site to re-evaluate its seismic and flood protection designs in light of current requirements and identify any areas for improvement; and 3) issue new regulations requiring enhancements relating to extended periods of loss of alternating current power, emergency preparedness and spent fuel pool cooling capabilities. The NRC is reviewing the timeline for implementation of all of the actions, but has indicated that all actions should be completed by the end of 2016. FPL is currently reviewing the NRC's directions relating to the NRC staff's recommendations and assessing the potential financial and operational impacts on its nuclear units.

The lessons learned from the events in Japan and the results of the NRC's review of the NRC staff's recommendations may, among other things, result in changes in or new licensing and safety-related requirements for U.S. nuclear facilities. Changes in or new requirements could, among other things, impact the capacity additions (uprates) at FPL's existing nuclear units at St. Lucie and

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~~Turkey~~The ~~Point,~~DOE ~~and~~was ~~future~~required ~~licensing~~to ~~and~~construct ~~operations~~permanent ofdisposal ~~U.S. nuclear~~ facilities, ~~including~~and ~~FPL's~~take ~~existing~~title ~~nuclear~~to ~~facilities~~ and ~~the~~provide ~~NRC~~transportation ~~approval~~and ofdisposal ~~two~~for ~~additional~~spent nuclear ~~units~~fuel atby ~~FPL's~~January 31, ~~Turkey~~1998 ~~Point~~for ~~site,~~a ~~and~~specified ~~could,~~fee ~~among~~based ~~other~~on ~~things,~~current ~~result~~generation infrom ~~increased~~nuclear ~~cost~~power ~~and~~plants. The ~~capital~~DOE ~~expenditures~~did ~~associated~~not ~~with~~meet ~~the~~its ~~operation~~statutory ~~and~~obligation ~~maintenance~~for disposal of ~~FPL's~~spent nuclear ~~units. While~~fuel under the ~~NRC~~Nuclear ~~continues~~Waste ~~its~~Policy ~~review~~Act. In 2009, FPL ~~continues~~and tocertain ~~work~~of ~~with~~FPL's ~~industry~~nuclear ~~organizations~~plant tojoint ~~understand~~owners ~~the~~entered ~~events~~into ina ~~Japan~~settlement ~~and~~agreement ~~apply~~(spent ~~lessons~~fuel ~~learned,~~settlement ~~which~~agreement) ~~may~~with ~~result~~the inU.S. ~~FPL~~government ~~proactively~~agreeing ~~making~~to ~~certain~~dismiss ~~modifications~~with toprejudice ~~its~~lawsuits ~~nuclear~~filed ~~facilities~~against ~~to,~~the ~~among~~U.S. ~~other~~government ~~things,~~seeking ~~improve~~damages ~~operational~~caused ~~and~~by ~~safety~~the ~~systems~~DOE's ~~prior~~failure to ~~any~~dispose ~~potential~~of ~~requirements~~spent ~~being~~nuclear ~~imposed~~fuel byfrom ~~the~~FPL's ~~NRC~~nuclear plants. ~~Any~~The ~~modifications~~spent ~~could,~~fuel ~~among~~settlement ~~other~~agreement ~~things,~~permits ~~result~~FPL into ~~increased~~make ~~cost~~annual ~~and~~filings ~~capital~~to ~~expenditures~~recover ~~associated~~certain ~~with~~spent ~~the~~fuel ~~operation~~storage ~~and~~costs ~~maintenance~~incurred ofby FPL's ~~nuclear~~which ~~units. Third~~are ~~parties~~reimbursable ~~have~~by ~~requested that~~ the ~~NRC~~U.S. ~~suspend~~government ~~the~~on ~~approval~~an ofannual ~~nuclear~~basis. In ~~uprates,~~a ~~nuclear~~separate ~~license~~lawsuit ~~extensions~~filed ~~and~~in ~~new licenses~~2011, ~~including~~FPL ~~approval~~joined ofthe ~~licenses~~Nuclear ~~for~~Energy ~~two~~Institute ~~additional~~and ~~nuclear~~several ~~units~~other atnuclear ~~FPL's~~plant ~~Turkey~~owners ~~Point~~and ~~site. Another~~operators ~~third~~(Petitioners) ~~party~~in ~~request~~petitioning ~~was filed with~~ the ~~NRC~~U.S. ~~seeking~~Court ~~immediate suspension~~ of ~~the~~Appeals ~~NRC operating licenses~~ for ~~all~~the ~~boiling~~District ~~water~~of ~~reactors~~Columbia ~~that~~(D.C. ~~use~~Circuit) ato ~~certain~~challenge ~~primary~~the ~~containment~~DOE's ~~system~~decision ~~pending~~to ~~completion~~continue ofto collect the ~~NRC~~nuclear ~~review~~waste fee. ~~The~~In ~~NRC~~June ~~denied~~2012, the ~~request~~D.C. ~~for~~Circuit ~~immediate~~held ~~action~~that ~~related to~~ the ~~suspension~~DOE's offee ~~operating~~adequacy ~~licenses~~determination ~~for~~was ~~boiling~~legally ~~water~~defective ~~reactors,~~but ~~and,~~remanded ~~since~~ the ~~nuclear~~case ~~events~~to inthe ~~Japan,~~DOE ~~has continued~~ to ~~grant~~revise ~~approvals~~its ~~for~~determination ~~nuclear~~while ~~uprates~~retaining ~~and~~jurisdiction ~~license~~over ~~extensions~~the matter. ~~However~~In January 2013, itthe isDOE ~~uncertain~~issued atits ~~this~~revised ~~time~~fee ~~how~~adequacy ~~and~~determination ~~when~~concluding that the ~~NRC~~nuclear ~~will~~waste ~~respond~~fee towas adequate, at which time the ~~other~~Petitioners ~~items~~filed ina ~~these~~motion ~~requests~~to orreopen ~~other~~the ~~requests~~case itwith ~~may~~the ~~receive,~~D.C. orCircuit. FPL ~~take~~will ~~action~~continue ~~with~~to ~~regard~~pay fees to the ~~timing~~U.S. ~~for~~government's ~~implementation~~nuclear ofwaste ~~all~~fund ofpending ~~the~~further ~~NRC~~action ~~staff's~~by ~~recommendations~~the D.C. Circuit.

In March 2010, the DOE filed a motion with the NRC to withdraw its license application for a nuclear waste repository at Yucca Mountain. The DOE's withdrawal motion has been challenged and is being litigated before the NRC and the D.C. Circuit. In light of the government's decision not to proceed with the Yucca Mountain repository project, the DOE established a Blue Ribbon Commission on America's Nuclear Future (BRC) to conduct a comprehensive review of policies for managing the back end of the nuclear fuel cycle and to provide recommendations for developing a safe, long-term solution to managing spent nuclear fuel and high-level radioactive waste. In January 2012, the BRC issued its report and recommendations which includes a consent-based approach, working with all affected units of government, to site future nuclear waste management facilities; creation of a new organization, independent of the DOE, dedicated solely to assuring the safe storage and ultimate disposal of spent nuclear fuel and high-level radioactive waste; providing access to the U.S. government's nuclear waste fund for the purpose of nuclear waste storage and disposal; and initiating prompt efforts to develop geologic disposal facilities, consolidated interim storage facilities and transportation to those facilities. In January 2013, the DOE issued a strategy document for implementing the BRC recommendations. The strategy document outlines, among other things, long-term plans for a new management organization to handle spent fuel storage and disposal activities, development of new interim storage facilities and several possible funding reforms, including accessing the nuclear waste fund for funding these activities. Each of these steps will require new federal legislation.

Nuclear Regulatory Developments. As a result of the impact of the 2011 earthquake and tsunami on nuclear facilities in Japan, the NRC conducted a comprehensive review of processes and regulations relating to nuclear facilities in the U.S. to determine whether it should make additional improvements to its regulatory system and policies. In March 2012, based on the review, the NRC established, among other things, the following actions which: 1) require each nuclear site to purchase portable equipment and revise procedures to address multi-unit events, provide reliable spent fuel pool instrumentation and enhance containment venting capabilities for boiling water reactors (FPL's nuclear units do not use boiling water reactors; see NEER - Generation and Other Operations - Nuclear Facilities - Nuclear Regulatory Developments); 2) request each site to re-evaluate its seismic and flood protection designs in light of current requirements and identify any areas for improvement; and 3) require enhancements relating to extended periods of loss of alternating current power, emergency preparedness and spent fuel pool cooling capabilities. The NRC also prescribed a timeline for implementation of the actions with completion by the end of 2016. FPL is currently reviewing various orders and requests for information being issued by the NRC and assessing the potential financial and operational impacts on its nuclear units, which could be significant. FPL's preliminary estimate of the cost to complete the actions described above is included in estimated capital expenditures. See Note 13 - Commitments.

The lessons learned from the events in Japan and the results of the NRC's actions will, among other things, result in new licensing and safety-related requirements for U.S. nuclear facilities. Any new requirements could, among other things, impact future licensing and operations of U.S. nuclear facilities, including FPL's existing nuclear facilities and the NRC approval of two additional nuclear units at FPL's Turkey Point site, and could, among other things, result in increased cost and capital expenditures associated with the operation and maintenance of FPL's nuclear units. Third parties have requested that the NRC, among other things, suspend the approval of nuclear license extensions and new licenses, including approval of licenses for two additional nuclear units at FPL's Turkey Point site. It is uncertain how and when the NRC will respond to the requests or other requests it may receive.

Solar Operations

Solar generation can be provided primarily through two conventions,: utility-owned and customer-owned. In utility-owned solar generation, the energy generated goes directly to the transmission grid, whereas, customer-owned solar generation goes directly to the location it is serving. There are two principal solar technologies used for utility-scale projects: photovoltaic and thermal. FPL placed its first utility-scale solar generating facility into service in 2009, ~~and~~a ~~placed~~25 ~~two~~mw ~~additional~~ solar ~~generating~~PV ~~facilities~~facility in ~~service~~DeSoto inCounty, ~~2010. FPL's~~Florida, ~~three~~and ~~solar~~placed ~~generating~~two ~~facilities~~additional ~~consist of a 25 mw~~ solar PVgenerating ~~facility~~facilities in ~~DeSoto~~service ~~County,~~in ~~Florida~~2010, a 10 mw solar PV facility in Brevard County, Florida and a 75 mw solar thermal facility in Martin County, Florida.

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Purchased Power

In addition to owning generation facilities, FPL also purchases electricity from other utilities to meet customer demand through long- and short-term purchased power agreements. As of December 31, ~~2011~~2012, FPL's long-term purchased power agreements provided for the purchase of approximately 21,~~190~~963 mw of power with expiration dates ranging from ~~May~~2015 ~~2012~~ through ~~2034~~2032. See Note 1413 - Contracts. FPL also procures short-term capacity for both economic and reliability purposes.

FPL ENERGY MARKETING AND TRADING

FPL's Energy Marketing & Trading division (EMT) buys and sells wholesale energy commodities, such as natural gas, oil and electricity. EMT procures natural gas and oil for FPL's use in power generation and sells excess natural gas, oil and electricity. EMT also uses derivative instruments (primarily swaps, options and forwards) to manage the commodity price risk inherent in the purchase and sale of fuel and electricity. Substantially all of the results of EMT's activities are passed through to customers in the fuel or capacity clauses. See FPL Regulation - FPL Rate Regulation below, Management's Discussion - Energy Marketing and Trading and Market Risk Sensitivity and Note 3.

FPL REGULATION

FPL's operations are subject to regulation by a number of federal, state and other organizations, including, but not limited to, the following:

• ~~The~~the FPSC, which has jurisdiction over retail rates, service territory, issuances of securities, planning, siting and construction of facilities, among other things.;

• ~~The~~the FERC, which oversees the acquisition and disposition of facilities, transmission services and wholesale purchases and sales of electric energy, among other things.;

• ~~The~~the NERC, which, through its regional entities, establishes and enforces mandatory reliability standards, subject to approval by the FERC, to ensure the reliability of the U.S. electric transmission and generation system and to prevent major system blackouts.;

• ~~The~~the NRC, which has jurisdiction over the operation of FPL's nuclear power plants through the issuance of operating licenses, rules, regulations and orders. ~~See~~(see FPL Sources of Generation - Nuclear Operations above.); and

• ~~The~~the EPA, which has the responsibility to maintain and enforce national standards under a variety of environmental laws. The EPA also works with industries and all levels of government, including federal and state governments, in a wide variety of voluntary pollution prevention programs and energy conservation efforts.

FPL Rate Regulation

The FPSC sets rates at a level that is intended to allow FPL the opportunity to collect from retail customers total revenues (revenue requirements) equal to FPL's cost of providing service, including a reasonable rate of return on invested capital. To accomplish this, the FPSC uses various ratemaking mechanisms, including, among other things, base rates and cost recovery clauses.

10Base Rates. In general, the basic costs of providing electric service, other than fuel and certain other costs, are recovered through base rates, which are designed to recover the costs of constructing, operating and maintaining the utility system. These basic costs include O&M expenses, depreciation and taxes, as well as a return on FPL's investment in assets used and useful in providing electric service (rate base). At the time base rates are determined, the allowed rate of return on rate base approximates the FPSC's determination of FPL's estimated weighted-average cost of capital, which includes its costs for outstanding debt and an allowed ROE. The FPSC monitors FPL's actual regulatory ROE through a surveillance report that is filed monthly by FPL with the FPSC. The FPSC does not provide assurance that any ROE will be achieved. Base rates are determined in rate proceedings or through negotiated settlements of those proceedings. Proceedings can occur at the initiative of FPL or upon action by the FPSC. Base rates remain in effect until new base rates are approved by the FPSC.

~~Table~~Rates Effective January 2013 - December 2016 - In January 2013, the FPSC issued a final order approving a stipulation and settlement between FPL and several intervenors in FPL's base rate proceeding (2012 rate agreement). Key elements of ~~Contents~~the 2012 rate agreement, which is effective from January 2013 through December 2016, include, among other things, the following:

~~Base~~• ~~Rates. In~~New ~~general,~~retail ~~the basic costs of providing electric service, other than fuel and certain other costs, are recovered through~~ base rates, ~~which are designed to recover the costs of constructing, operating~~ and ~~maintaining~~charges ~~the~~were ~~utility~~established ~~system. These~~in ~~basic~~January ~~costs~~2013 ~~include~~resulting ~~O&M expenses, depreciation and taxes, as well as a return on FPL's investment~~ in ~~assets~~an ~~used~~increase ~~and useful~~ in ~~providing~~retail ~~electric service (rate~~ base~~). At~~ ~~the~~revenues ~~time base rates are determined, the allowed rate~~ of ~~return~~$350 million on ~~rate base approximates the FPSC's determination of FPL's estimated weighted-average cost of capital, which includes its costs for outstanding debt and~~ an ~~allowed~~annualized ~~ROE~~basis. The FPSC monitors FPL's actual regulatory ROE through a surveillance report that is filed monthly by FPL with the FPSC. The FPSC does not provide assurance that any ROE will be achieved. Base rates are determined in rate proceedings or through negotiated settlements of those proceedings, which occur at the initiative of FPL, the FPSC, the State of Florida Office of Public Counsel or a substantially affected party. Base rates remain in effect until new base rates are approved by the FPSC.

~~Effective~~• ~~March 1, 2010, pursuant to an FPSC final order (FPSC rate order) new retail base rates for~~ FPL's ~~were~~allowed ~~established, resulting in an increase in retail base revenues of approximately $75 million on an annualized basis. The FPSC rate order also established a~~ regulatory ROE ofwill be 10.050%, with a range of plus or minus 100 basis points. ~~and~~If anFPL's ~~adjusted~~earned regulatory ~~equity~~ROE ~~ratio~~falls ofbelow 599.150%~~. It~~, ~~also~~FPL ~~shifted~~may ~~certain~~seek ~~costs from~~ retail base ~~rates~~rate ~~to the capacity clause~~relief. ~~(See~~ ~~Cost~~If ~~Recovery~~the ~~Clauses~~earned ~~below~~regulatory ~~for~~ROE ~~additional~~rises ~~information~~above ~~regarding the capacity clause~~11.~~) In addition~~50%, ~~the~~any ~~FPSC~~party ~~rate order directed FPL~~ to ~~reduce depreciation expense (surplus depreciation credit) over~~ the ~~2010~~2012 torate ~~2013~~agreement ~~period~~other ~~related~~than toFPL amay ~~depreciation~~seek ~~reserve surplus. In February 2011, the FPSC issued~~ a ~~final~~review ~~order approving a stipulation and settlement agreement between FPL, the State~~ of ~~Florida Office of Public Counsel, the Florida Attorney General's Office and all other principal parties in~~ FPL's ~~2009~~retail ~~rate case regarding FPL's~~ base rates ~~(2010 rate agreement), which enables FPL to earn a regulatory ROE of up to 11% per year over the term of the 2010 rate agreement~~. ~~Key elements of the 2010 rate agreement, which is effective through December 31, 2012, are as follows:~~

• ~~Subject~~Retail tobase ~~the~~rates ~~provisions~~will ofbe increased by the ~~2010~~annualized ~~rate~~base ~~agreement~~revenue requirements for FPL's three modernization projects (Cape Canaveral, ~~retail~~Riviera ~~base~~Beach ~~rates~~and ~~are~~Port ~~effectively~~Everglades) ~~frozen~~as ~~through~~each of the ~~end~~modernized ofpower ~~2012~~plants becomes operational (which is expected by June 2013, June 2014 and mid-2016, respectively).

• Incremental cost recovery through FPL's capacity clause for the new combined-cycle natural gas unit at WCEC (WCEC Unit No. 3), which was placed in service in May 2011, is permitted up to the amount of the projected annual fuel savings for customers during the term of the 2010 rate agreement.

• Future storm restoration costs would be recoverable on an accelerated basis beginning 60 days from the filing of a cost recovery petition, but capped at an amount that produces a surcharge of no more than $4 for every 1,000 kwh of usage on residential bills during the first 12 months of cost recovery. Any additional costs would be eligible for recovery in subsequent years. If storm restoration costs exceed $800 million in any given calendar year, FPL may request an increase to the $4 surcharge to recover the amount above $800 million.

• If FPL's earned regulatory ROE falls below 9%, FPL may seek retail base rate relief. If FPL's earned regulatory ROE rises above 11%, any party to the 2010 rate agreement may seek a reduction in FPL's retail base rates. In determining the regulatory ROE for all purposes under the 2010 rate agreement, earnings will be calculated on an actual, non-weather-adjusted basis.

• FPL can vary the amount of surplus depreciation credit taken in any calendar year up to a cap in 2010 of $267 million, a cap in subsequent years of $267 million plus the amount of any unused portion from prior years, and a total cap of $776 million (surplus depreciation credit cap) over the course of the 2010 rate agreement, provided that in any year of the 2010 rate agreement FPL must use at least enough surplus depreciation credit to maintain a 9% earned regulatory ROE but may not use any amount of surplus depreciation credit that would result in an earned regulatory ROE in excess of 11%.

In January 2012, FPL notified the FPSC of its intent to initiate a base rate proceeding in 2012. See Recent Regulatory Developments below.

Cost Recovery Clauses. Cost recovery clauses, which are designed to permit full recovery of certain costs and provide a return on certain assets allowed to be recovered through the various clauses, include substantially all fuel, purchased power and interchange expenses, conservation and certain environmental-related expenses, certain revenue taxes and franchise fees. Beginning in 2009, pre-construction costs and carrying charges on construction costs for FPL's planned two additional nuclear units at Turkey Point and carrying charges on construction costs for FPL's approximately 450 mw to 490 mw of additional capacity at St. Lucie and Turkey Point are also recoverable through a cost recovery clause. Also beginning in 2009, costs incurred for FPL's three solar generating facilities are recoverable through a cost recovery clause. Cost recovery clause costs are recovered through levelized monthly charges per kwh or kw, depending on the customer's rate class. These cost recovery clause charges are calculated at least annually based on estimated costs and estimated customer usage for the following year, plus or minus a true-up adjustment to reflect the estimated over or under recovery of costs in the current year. An adjustment to the levelized charges may be approved during the course of a year to reflect revised estimates.

Fuel costs are recovered from customers through the fuel clause, the most significant of the cost recovery clauses. FPL uses a risk management fuel procurement program which has been approved by the FPSC. The FPSC reviews the program activities and results for prudence annually as part of its review of fuel costs. The program is intended to manage fuel price volatility by locking in fuel prices for a portion of FPL's fuel requirements. See FPL Energy Marketing and Trading above, Management's Discussion - FPL: Results of Operations, Note 1 - Regulation and Note 3.

Capacity payments to other utilities and generating companies for purchased power are recovered from customers through the capacity clause. In accordance with the FPSC's nuclear cost recovery rule, FPL also recovers pre-construction costs and carrying charges (equal to a pretax AFUDC rate) on construction costs for new nuclear capacity through the capacity clause. As property related to the new nuclear capacity goes into service, construction costs and a return on investment are recovered through base rate increases effective beginning the following January. See FPL Sources of Generation - Nuclear Operations above. In

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~~accordance~~• ~~with~~Cost ~~the 2010 rate agreement, cost~~ recovery ~~for~~of WCEC Unit No. 3, which was placed in service in May 2011, iswill ~~permitted~~continue up to ~~the~~occur ~~amount~~through of the ~~projected~~capacity ~~annual~~clause; ~~fuel~~however, ~~savings~~such ~~for~~recovery ~~customers~~will ~~during~~not ~~the~~be ~~term~~limited ofto the ~~2010~~projected ~~rate~~annual ~~agreement~~fuel ~~through~~cost ~~FPL's~~savings ~~capacity~~as ~~clause~~was ~~and~~the iscase ~~reported~~in asthe ~~retail~~previous ~~base~~rate ~~revenues~~agreement discussed below.

•

Subject to certain conditions, FPL must amortize, over the term of the 2012 rate agreement, a depreciation reserve surplus remaining at the end of 2012 under the 2010 FPSC rate order discussed below (approximately $224 million) and may amortize a portion of FPL's fossil dismantlement reserve up to a maximum of $176 million (collectively, the reserve), provided that in any year of the 2012 rate agreement, FPL must amortize at least enough reserve to maintain a 9.50% earned regulatory ROE but may not amortize any reserve that would result in an earned regulatory ROE in excess of 11.50%.

•

Future storm restoration costs would be recoverable on an interim basis beginning 60 days from the filing of a cost recovery petition, but capped at an amount that could produce a surcharge of no more than $4 for every 1,000 kwh of usage on residential bills during the first 12 months of cost recovery. Any additional costs would be eligible for recovery in subsequent years. If storm restoration costs exceed $800 million in any given calendar year, FPL may request an increase to the $4 surcharge to recover the amount above $800 million.

On February 7, 2013, the Office of Public Counsel filed a notice of appeal to the Florida Supreme Court of the FPSC's final order regarding the 2012 rate agreement.

Rates Effective March 2010 - December 2012 - Effective March 1, 2010, pursuant to an FPSC final order (2010 FPSC rate order), new retail base rates for FPL were established, resulting in an increase in retail base revenues of approximately $75 million on an annualized basis. The 2010 FPSC rate order, among other things, also established a regulatory ROE of 10.0% with a range of plus or minus 100 basis points. In February 2011, the FPSC issued a final order approving a stipulation and settlement agreement between FPL and principal parties in FPL's 2009 rate case (2010 rate agreement). The 2010 rate agreement, which was effective through December 31, 2012, provided for, among other things, a reduction in depreciation expense (surplus depreciation credit) in any calendar year up to a cap in 2010 of $267 million, a cap in subsequent years of $267 million plus the amount of any unused portion from prior years, and a total cap of $776 million over the course of the 2010 rate agreement, provided that in any year of the 2010 rate agreement FPL was required to use enough surplus depreciation credit to maintain an earned regulatory ROE within the range of 9.0% - 11.0%. The 2010 rate agreement also permitted incremental cost recovery through FPL's capacity clause for WCEC Unit No. 3 up to the amount of the projected annual fuel savings for customers. See Cost Recovery Clauses below for additional information regarding the capacity clause.

Capacity payments to other utilities and generating companies for purchased power are recovered from customers through the capacity clause. In accordance with the FPSC's nuclear cost recovery rule, FPL also recovers pre-construction costs and carrying charges (equal to a fixed pretax AFUDC rate) on construction costs for new nuclear capacity through the capacity clause. As property related to the new nuclear capacity goes into service, construction costs and a return on investment are recovered through base rate increases effective beginning the following January. See FPL Sources of Generation - Nuclear Operations above. In accordance with the 2012 and 2010 rate agreements, cost recovery for WCEC Unit No. 3 is permitted during the term of the agreements through FPL's capacity clause and is reported as retail base revenues.

Costs associated with implementing energy conservation programs are recovered from customers through the energy conservation cost recovery clause. Certain costs of complying with federal, state and local environmental regulations enacted after April 1993 and costs associated with FPL's three solar facilities are recovered through the environmental compliance cost recovery clause (environmental clause).

The FPSC has the authority to disallow recovery of costs that it considers excessive or imprudently incurred. These costs may include, among others, fuel and O&M expenses, the cost of replacing power lost when fossil and nuclear units are unavailable, storm restoration costs and costs associated with the construction or acquisition of new facilities.

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FERC

The Federal Power Act gives the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, electric utilities must maintain tariffs and rate schedules on file with the FERC which govern the rates, terms and conditions for the provision of FERC-jurisdictional wholesale power and transmission services. The Federal Power Act also gives the FERC authority to certify and oversee a national electric reliability organization with authority to develop mandatory reliability standards applicable to all users, owners and operators of bulk-power systems. The FERC also approves reliability standards and makes them enforceable. See NERC below. Electric utilities ~~also~~ are subject to accounting, record-keeping and reporting requirements administered by the FERC. The FERC also places certain limitations on transactions between electric utilities and their affiliates.

NERC

The NERC has been certified by the FERC as the national electric reliability organization. The NERC ensures the reliability and security of the North American bulk power system. The NERC's regional entities establish requirements, approved by the FERC, for reliable operation and maintenance of power generation facilities and transmission systems. FPL is subject to these reliability requirements and incurs costs to ensure compliance with continually heightened requirements, and can incur significant penalties for failing to comply with them. Each NERC region reports seasonally and annually on the status of generation and transmission in each region.

FPL Environmental Regulation

FPL is subject to environmental laws and regulations, and is affected by some of the emerging issues, described in the NEE Environmental Matters section below. FPL expects to seek recovery through the environmental clause for compliance costs associated with any new environmental laws and regulations.

During 2011, FPL spent approximately $117 million on capital additions related to environmental matters, primarily to comply with existing environmental laws and regulations. FPL's capital expenditures related to environmental matters are estimated to total approximately $325 million for 2012 through 2014, including $118 million in 2012.

Recent Regulatory Developments

In January 2012, FPL filed a formal notification with the FPSC indicating its intent to initiate a base rate proceeding. The notification stated that, based on preliminary estimates, FPL expects to request a base rate increase of approximately $525 million effective January 2013 and an additional base rate increase of approximately $170 million annually commencing when the modernized Cape Canaveral plant becomes operational, which is expected to occur in June 2013. FPL expects to propose an allowed regulatory ROE of 11.25% with a 0.25% ROE adder, which is included in the base rate increase FPL expects to request, if FPL maintains the lowest typical residential customer bill among all the electric utilities in Florida. FPL expects to file its formal request to initiate a base rate proceeding before the end of the first quarter of 2012 with a final FPSC decision expected in the fourth quarter of 2012 in time for new rates to be effective January 1, 2013.

FPL EMPLOYEES

FPL had approximately 9,~~800~~700 employees at December 31, ~~2011~~2012. Approximately 3132% of the employees are represented by the International Brotherhood of Electrical Workers (IBEW) under a collective bargaining agreement with FPL that expires October 31, 2014.

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II. NEER

NEER was formed in 1998 to aggregate NEE's competitive energy businesses. It is a limited liability company organized under the laws of Delaware and is a wholly-owned subsidiary of NEECH. Through its subsidiaries, NEER currently owns, develops, constructs, manages and operates electric generating facilities in wholesale energy markets primarily in the U.S., as well as in Canada and Spain. See Note 1514. NEER is one of the largest wholesale generators of electric power in the U.S., with 1618,~~607~~122 mw of generating capacity across 2224 states and 34 Canadian provinces as of December 31, ~~2011~~2012. NEER produces the majority of its electricity from clean and renewable sources as described more fully below. NEER is the largest owner of wind and utility-scale solar energy projects in ~~the~~North UAmerica.~~S. and one of the largest owners and developers of wind projects in Canada.~~ Since 2002, NEER has more than doubled its generating capacity, primarily through the development of new wind projects and acquisition of nuclear projects.

~~In addition,~~ NEER ~~provides~~engages ~~full~~in ~~energy~~power and ~~capacity~~gas ~~requirements~~marketing ~~services~~and ~~primarily~~trading toactivities, ~~distribution~~including ~~utilities~~entering ininto ~~certain~~financial ~~markets,~~and ~~offers~~physical ~~customized~~contracts, ~~power~~to ~~and~~hedge ~~gas~~the ~~and~~production ~~related~~from ~~risk~~its ~~management~~generating ~~services~~assets tothat ~~wholesale~~is ~~customers~~not ~~and~~sold ~~engages~~under inlong-term power ~~and~~supply ~~gas~~agreements. These ~~marketing~~activities ~~and~~include ~~trading~~providing ~~activities. NEER~~full ~~also~~energy ~~owns~~and acapacity ~~retail~~requirements ~~electricity~~services ~~provider~~primarily ~~serving~~to ~~customers~~distribution utilities in 13certain ~~states~~markets and ~~the~~offering ~~District~~customized ofpower ~~Columbia~~and gas and ~~engages~~related inrisk ~~limited~~management ~~development~~services ofto ~~natural~~wholesale ~~gas~~customers. NEER ~~reserves,~~also asparticipates ~~well~~in asnatural ~~pipeline~~gas ~~infrastructure,~~production through non-operating ownership interests and pipeline infrastructure development, hereafter referred to as the gas infrastructure business, and owns a retail electricity provider serving customers in 13 states and the District of Columbia.

MARKETS AND COMPETITION

Electricity markets in the U.S. are regional and diverse in character. All are extensively regulated, and competition in these markets is shaped and constrained by regulation. The nature of the products offered varies based on the specifics of regulation in each region~~, and the degree of control participants have over pricing also varies~~. Generally, in addition to the natural constraints on pricing freedom presented by competition, NEER may also face specific constraints in the form of price caps, or maximum allowed prices, for certain products. NEER's ability to sell the output of its generation facilities is also constrained by available transmission capacity, which can vary from time to time and can have a significant impact on pricing.

The degree and nature of competition that NEER faces is different in wholesale markets and in retail markets. ~~The~~Approximately ~~majority~~90% of NEER's revenue, ~~roughly 90%,~~ is derived from wholesale markets.

Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. NEER competes on the basis of the location of its plants and ownership of multiple plants in various regions, which increases the reliability of its energy supply. Wholesale power generation is a regional business that is currently highly fragmented relative to other commodity industries and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies NEER competes with depending on the market. In wholesale markets, customers' needs are met through a variety of means, including long-term bilateral contracts, standardized bilateral products such as full requirements service and customized supply and risk management services.13

InTable ~~general, U.S. electricity markets encompass three classes~~ of product: energy, capacity and ancillary services. Energy services relate to the physical delivery of power; capacity services relate to the availability of mw capacity of a power generation asset; and ancillary services are other services related to power generation assets, for example, load-following services, which require the supplier of energy to vary the quantity delivered based on the load demand needs of the customer. The exact nature of these classes of product is defined in part by regulation. Not all regions have a capacity product class, and the specific definitions of ancillary services vary from region to region.Contents

~~RTOs~~Wholesale ~~and~~power ~~ISOs~~generation ~~exist~~is in a ~~number~~capital-intensive, commodity-driven business with numerous industry participants. NEER primarily competes on the basis of ~~regions~~price, ~~within~~but ~~which~~believes the green attributes of NEER's ~~operates~~generating toassets, ~~coordinate~~its ~~generation~~creditworthiness and ~~transmission~~its ~~across~~ability ~~wide~~to ~~geographic~~offer ~~areas. NEER~~and ~~also~~manage ~~has~~customized ~~operations~~risk ~~that~~solutions ~~fall~~to ~~within~~wholesale ~~the~~customers ~~Western~~are ~~Electricity~~competitive ~~Coordinating~~advantages. Wholesale ~~Council~~power ~~reliability~~generation ~~region~~is a regional business that ~~are~~is ~~not~~currently ~~under~~highly ~~the~~fragmented ~~jurisdiction~~relative ofto anmany ~~established~~other ~~RTO~~commodity orindustries ~~ISO~~and diverse in terms of industry structure. ~~Although~~As ~~each~~such, ~~RTO~~there ~~and~~is ~~ISO~~a ~~may~~wide ~~have~~variation ~~differing~~in ~~objectives~~terms ~~and~~of ~~structures~~the capabilities, ~~some~~resources, ~~benefits~~nature ofand ~~these~~identity ~~entities~~of ~~include~~the ~~regional~~companies ~~planning,~~NEER ~~managing~~competes ~~transmission~~with ~~congestion,~~depending ~~developing~~on ~~larger~~the market. In wholesale markets, ~~for~~customers' ~~energy~~needs ~~and~~are ~~capacity,~~met ~~maintaining~~through ~~reliability~~a ~~and~~variety ~~facilitating~~of ~~competition~~means, ~~among~~including ~~wholesale~~long-term ~~electricity~~bilateral ~~providers. NEER~~contracts, ~~has~~standardized ~~operations~~bilateral ~~that~~products ~~fall~~such ~~within~~as ~~the~~full ~~following~~requirements ~~RTOs~~service and ~~ISOs:~~customized supply and risk management services.

In general, U.S. electricity markets encompass three classes of product: energy, capacity and ancillary services. Energy services relate to the physical delivery of power; capacity services relate to the availability of mw capacity of a power generation asset; and ancillary services are other services related to power generation assets, such as load regulation and spinning and non-spinning reserves. The exact nature of these classes of product is defined in part by regional tariffs. Not all regions have a capacity product class, and the specific definitions of ancillary services vary from region to region.

RTOs and ISOs exist in a number of regions within which NEER operates to coordinate generation and transmission across wide geographic areas and to run markets. NEER also has operations that fall within the Western Electricity Coordinating Council reliability region that are not under the jurisdiction of an established RTO or ISO. Although each RTO and ISO may have differing objectives and structures, some benefits of these entities include regional planning, managing transmission congestion, developing larger wholesale markets for energy and capacity, maintaining reliability and facilitating competition among wholesale electricity providers. NEER has operations that fall within the following RTOs and ISOs:


•	Alberta Electric System Operator


•	California Independent System Operator


•	ERCOT

• Independent Electricity System Operator (in Ontario)

• ISO New England (ISO-NE)


•	Midwest Independent Transmission System Operator (MISO)


•	New York Independent System Operator (NYISO)


•	PJM


•	Southwest Power Pool

13NEER competes in different regions to different degrees, but in general it seeks to enter into long-term bilateral contracts for the full output of its generating facilities, and approximately 58% of NEER's generating capacity is fully committed under long-term contracts. Where long-term contracts are not in effect, NEER sells the output of its facilities into daily spot markets. In such cases, NEER will frequently enter into shorter term bilateral contracts, typically but not always of one to three years duration, to hedge the price risk associated with selling into a daily spot market. Such bilateral contracts, which may be hedges either for physical delivery or for financial (pricing) offset, may only protect a portion of the revenue that NEER expects to derive from the associated generation facility and may not qualify for hedge accounting under GAAP. Contracts that serve the economic purpose of hedging some portion of the expected revenue of a generation facility but are not recorded as hedges under GAAP are referred to as “non-qualifying hedges” for adjusted earnings purposes. See Management's Discussion - Overview.

~~Table~~The NEER wind generation portfolio produces renewable energy credits (RECs) which are typically sold along with the energy from the plants under long-term contracts. A small portion of ~~Contents~~the wind portfolio generation is sold under short-term contracts and the RECs and other environmental attributes may be sold separately.

NEER competes in different regions to different degrees, but in general it seeks to enter into long-term bilateral contracts for the full output of its generating facilities, and approximately 55% of NEER's generating capacity is fully committed under long-term contracts. In some regions long-term contracts are not practical and NEER sells the output of its facilities into daily spot markets. In such cases, NEER will frequently enter into shorter term bilateral contracts, typically but not always of one to three years duration, to hedge the price risk associated with selling into a daily spot market. Such bilateral contracts, which may be hedges either for physical delivery or for financial (pricing) offset, may only protect a portion of the revenue that NEER expects to derive from the associated generation facility and may not qualify for hedge accounting under GAAP. Contracts that serve the economic purpose of hedging some portion of the expected revenue of a generation facility but are not recorded as hedges under GAAP are referred to as “non-qualifying hedges” for adjusted earnings purposes. See Management's Discussion - Overview.

While the majority of NEER's revenue is derived from the output of its generating facilities, NEER is also an active competitor in several regions in the wholesale full requirements business and in providing structured and customized power and gas products and services to a variety of customers. In the full requirements service, the supplier agrees to meet the customer's needs for a full range of products for every hour of the day for a fixed period of time, thereby assuming the risk of fluctuations in the customer's volume requirements.

The deregulated retail energy business is typically a highly competitive business. In general, competition in the retail energy business is on the basis of price, service, brand image, product offerings and market perceptions of creditworthiness. Electricity is sold pursuant to a variety of product types, including fixed, indexed and renewable products, and customers elect terms of service typically ranging from one month to five years. Retail energy rates are market-based, and not subject to traditional cost-of-service regulation by public service commissions. Non-affiliated transmission and distribution service companies provide, on a non-discriminatory basis, the wires and metering services necessary to ~~access~~deliver service to customers. Subsidiaries of NEER compete in certain states for retail customers, which can be divided into two principal segments: residential and commercial and industrial (C&I). Residential customers largely require only energy services, which may be purchased on a month-to-month basis or under a multi-year contract. Large C&I customers share many of the same characteristics as wholesale utility customers and may require similarly customized and structured products.

In general, competitive retail electric providers are exposed to both volume and price risk: customers' volumes will vary, and competitive retail providers are committed to supplying the customer's full needs at all times and are therefore responsible for purchases in wholesale markets to meet those needs; and wholesale prices will fluctuate in ways that do not necessarily match the retail prices committed to the customer.

Expanded competition in a frequently changing regulatory environment presents both opportunities and risks for NEER. Opportunities exist for the selective acquisition of generation assets and for the construction and operation of efficient facilities that can sell power in competitive markets. NEER seeks to reduce its market risk by having a diversified portfolio by fuel type and location, as well as by contracting for the future sale of a significant amount of the electricity output of its facilities.

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GENERATION AND OTHER OPERATIONS

The vast majority of NEER's revenue is derived from selling the products (energy, capacity, RECs and ancillary services) produced by its own generating facilities. ~~To a limited extent~~However, NEER ~~also~~may ~~meets~~combine ~~its customers' needs through~~ purchases of relevant products in wholesale markets ~~and may combine purchases~~ with ~~sales~~products ~~from~~produced by its own ~~assets~~generating facilities in order to meet particular customers' needs.

At December 31, ~~2011~~2012, the locations of NEER's generation facilities in North America are as follows:

At December 31, ~~2011~~2012, NEER managed or participated in the management of essentially all of its generation projects in which it has an ownership interest.

NEER categorizes its portfolio in a number of different ways for different business purposes. See a listing of NEER's generating facilities in Item 2 - Generating Facilities. The following combination of the presence/absence of long-term contracts, fuel/technology and region is a common presentation that NEE has used in communicating its business:

Contracted, Merchant and Other Operations

NEER's portfolio of operations based on the presence/absence of long-term contracts and other operations is described below.

Contracted Assets. Contracted assets are projects with long-term power sales agreements for substantially all of their output and certain wind assets where long-term power contracts are expected to be executed. At December 31, 2011, NEER had 9,647 mw of contracted assets, substantially all of which have long-term power contracts. Essentially all of the output of these contracted assets were under power sales agreements, with a weighted-average remaining contract life of approximately 16 years, and have firm fuel and transportation agreements with expiration dates ranging from March 2012 through 2022. See Note 14 - Contracts. Approximately 6,860 mw of this capacity is wind generation and 1,621 mw of this capacity is nuclear generation. The remaining 1,166 mw use a variety of fuels and technologies such as natural gas, oil and solar.

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~~gas requirements. See Note 14 - Contracts. Derivative instruments (primarily swaps~~Contracted, ~~options,~~Merchant ~~futures~~ and ~~forwards)~~Other are used to lock in pricing and manage the commodity price risk inherent in power sales and fuel purchases. Managing market risk through these instruments introduces other types of risk, primarily counterparty, credit and operational risks. Operations

~~Other.~~ NEER's portfolio of operations ~~also~~based ~~include~~on the ~~gas~~presence/absence ~~infrastructure~~of ~~and~~long-term ~~customer~~contracts ~~supply~~ and ~~proprietary~~other ~~power~~operations ~~and~~is ~~gas~~described ~~trading businesses. See NEER Customer Supply and Proprietary Power and Gas Trading~~ below.

Contracted Assets. Contracted assets are projects with long-term power sales agreements for substantially all of their output and certain wind assets where long-term power contracts are expected to be executed. At December 31, 2012, NEER had 11,039 mw of contracted assets, substantially all of which have long-term power contracts. Essentially all of the output of these contracted assets were under power sales agreements, with a weighted-average remaining contract life of approximately 15 years, and have firm fuel and transportation agreements with expiration dates ranging from March 2013 through 2022. See Note 13 - Contracts. Approximately 8,213 mw of this capacity is wind generation and 1,621 mw of this capacity is nuclear generation. The remaining 1,205 mw use a variety of fuels and technologies such as natural gas, oil and solar.

Merchant Assets. Merchant assets are projects that do not have long-term power sales agreements to sell their output, or, in the case of certain wind assets, are not expected to have long-term power contracts, and therefore require active marketing and hedging. At December 31, 2012, NEER's portfolio of merchant assets consists of 7,083 mw of owned wind, nuclear, natural gas, oil, solar and hydro generating facilities (see NEER Fuel/Technology Mix - Other Assets below), including 846 mw of peak generating facilities. Approximately 60% (based on net mw capacity) of the natural gas-fueled merchant assets have natural gas transportation agreements to provide for fluctuating natural gas requirements. See Note 13 - Contracts. Derivative instruments (primarily swaps, options, futures and forwards) are generally used to lock in pricing and manage the commodity price risk inherent in power sales and fuel purchases. Managing market risk through these instruments introduces other types of risk, primarily counterparty, credit and operational risks.

Other. NEER's operations also include the gas infrastructure business and the customer supply and proprietary power and gas trading businesses. At December 31, 2012, the gas infrastructure business had non-operating investments located in shale formations primarily in Texas, Oklahoma, Wyoming, North Dakota and Louisiana. Also, see NEER Customer Supply and Proprietary Power and Gas Trading below.

NEER Fuel/Technology Mix

NEER's generating ~~capacity~~output is produced using a variety of fuel sources as further described below.

Wind Facilities

At December 31, ~~2011~~2012, NEER had ownership interests in wind generating facilities with a total capacity of 810,~~569~~057 mw (net ownership). NEER operates substantially all of these wind facilities, which are located in 1719 states and Canada. During 2012, NEER added ~~379~~approximately 1,520 mw of new wind generation inand ~~2011,~~sold ~~including~~a ~~128~~wind mwfacility ~~related~~with to30 ~~the~~mw ~~repowering~~ of ~~two~~generating ~~California~~capacity. NEER ~~wind~~is ~~facilities,~~currently ~~and~~committed ~~expects~~ to add approximately ~~1,150~~775 mw of new wind generation during the period 2013 to 12015,~~500~~ mwprimarily in Canada. See Policy Incentives for Renewable Energy Projects for additional discussion of ~~new~~NEER's expectations regarding wind ~~generation~~development inand ~~2012~~construction.

Natural Gas Facilities

At December 31, ~~2011~~2012, NEER had 3,991 mw of natural gas assets. NEER owns and operates 1,004 mw of natural gas-fired generation from contracted assets located throughout the Northeast. During 2011, subsidiaries of NEER sold their ownership interests in a portfolio of natural gas-fired generating assets totaling approximately 2,700 mw of capacity located in California, Virginia, Alabama, South Carolina and Rhode Island. See Management's Discussion - Overview and Note 4 - Nonrecurring Fair Value Measurements.

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Nuclear Facilities

At December 31, ~~2011~~2012, NEER owned, or had undivided interests in, and operated the following four nuclear units with a total net generating capacity of 2,721 mw.



Facility	Location	mw	Portfolio Category	Operating License Expiration Dates
Seabrook	New Hampshire	1,100	Merchant	2030	^(a)
Duane Arnold	Iowa	431	Contracted^(b)	2034
Point Beach Unit No. 1	Wisconsin	595	Contracted^(c)	2030
Point Beach Unit No. 2	Wisconsin	595	Contracted^(c)	2033

~~__________________~~______________________

(a) In 2010, NEER filed an application with the NRC to renew Seabrook's operating license for an additional 20 years, which license renewal may be delayed due to required revisions to the NRC's Waste Confidence Rule which are not expected to be finalized before late 2014.

(b) NEER sells substantially all of its share of the output of Duane Arnold under a long-term contract expiring in February 2014. Upon expiration of that contract, NEER will sell all of its share of the output of Duane Arnold under a long-term contract expiring in February 2025.


(c)	NEER sells all of the output of Point Beach Units Nos. 1 and 2 under long-term contracts through the current operating license terms.

16NEER's nuclear facilities have several contracts for the supply of uranium and conversion, enrichment and fabrication of nuclear fuel with expiration dates ranging from March 2013 through 2022. See Note 13 - Contracts. NEER is responsible for all nuclear unit operations and the ultimate decommissioning of the nuclear units, the cost of which is shared on a pro-rata basis by the joint owners for the jointly-owned units. NRC regulations require plant owners to submit a plan for decontamination and decommissioning five years before the projected end of plant operation.

~~Table~~Nuclear Unit Scheduled Refueling Outages. NEER's nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, including inspections, repairs and certain other modifications. Scheduled nuclear refueling outages typically require the unit to be removed from service for variable lengths of ~~Contents~~time. The following table summarizes the next scheduled refueling outages:

NEER's nuclear facilities have several contracts for the supply of uranium and conversion, enrichment and fabrication of nuclear fuel with expiration dates ranging from March 2012 through 2022. See Note 14 - Contracts. NEER is responsible for all nuclear unit operations and the ultimate decommissioning of the nuclear units, the cost of which is shared on a pro-rata basis by the joint owners for the jointly owned units. NRC regulations require plant owners to submit a plan for decontamination and decommissioning five years before the projected end of plant operation. See estimated decommissioning cost data in Management's Discussion - Critical Accounting Policies and Estimates - Nuclear Decommissioning and Fossil/Solar Dismantlement.



Facility		Next Scheduled Refueling Outage
Seabrook		April 2014
Duane Arnold		October 2014
Point Beach Unit No. 1		March 2013
Point Beach Unit No. 2		March 2014

Nuclear Unit Scheduled Refueling Outages. NEER's nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, including inspections, repairs and certain other modifications. Scheduled nuclear refueling outages typically require the unit to be removed from service for variable lengths of time. The duration is longer for expanded scope outages, one of which is scheduled at Duane Arnold in 2012 and is expected to last approximately 60 days. The following table summarizes the next scheduled refueling outages:

Facility		Next ScheduledRefueling Outage
Seabrook		October 2012
Duane Arnold		October 2012
Point Beach Unit No. 1		April 2013
Point Beach Unit No. 2		November 2012

Disposition of Spent Nuclear Fuel. NEER's nuclear facilities use both on-site storage pools and dry storage casks to store spent nuclear fuel generated by these facilities, which are expected to allow NEER to store spent nuclear fuel at these facilities through license expiration.

As owners and operators of nuclear facilities, certain subsidiaries of NEER are subject to the Nuclear Waste Policy Act and are parties to the spent fuel settlement agreement and legal actions described in I.FPL - FPL Sources of Generation - Nuclear Operations. Similar to FPL, these subsidiaries will continue to pay fees to the U.S. government's nuclear waste fund pending further action by the D.C. Circuit~~'s decision on the fee suspension petition~~.

~~Recent~~ Nuclear Regulatory Developments. For discussion of ~~current~~ developments regarding the impact of the 2011 earthquake and tsunami in Japan as it relates to U.S. nuclear facilities, see I.FPL - FPL Sources of Generation - Nuclear Operations. NEER's nuclear facilities are subject to the same ~~potential~~ NRC actions as described for FPL. Duane Arnold is NEER's only boiling water reactor unit. NEER is currently reviewing the ~~NRC's~~various ~~directions~~orders ~~relating~~and torequests ~~the~~for ~~NRC~~information ~~staff's~~being ~~recommendations~~issued by the NRC and assessing the potential financial and operational impact on its nuclear units, which could be significant. NEER's preliminary estimate of the cost to complete the NRC actions established in March 2012 is included in estimated capital expenditures. See Note 13 - Commitments.

Solar Facilities

NEER is one of the largest owners of utility-scale solar energy projects in the U.S., principally through a 310 mw facility in California's Mojave Desert, of which 148 mw is owned by NEER as of December 31, 2011. NEER is in the process of constructing solar thermal facilities with generating capacity of 99.8 mw in Spain (Spain solar project) and 250 mw in California (Genesis solar project), which are expected to be completed in 2013 and 2014, respectively. In addition, a 550 mw solar PV project in California (Desert Sunlight solar project), in which NEER has a 50% equity investment, has commenced construction and commercial operation is expected to be phased in during 2013 through 2015. During 2011, NEER added approximately 5 mw of new solar generation.

Other Assets

At December 31, 2011, NEER had 1,168 mw of generation assets from a variety of other fuel technologies, including oil and hydropower, with facilities located throughout the Northeast.

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Solar Facilities

NEER is one of the largest owners of utility-scale solar energy projects in North America, principally through a 310 mw facility in California's Mojave Desert, of which 148 mw is owned by NEER as of December 31, 2012. NEER and its affiliates are in the process of constructing solar thermal facilities with generating capacity of 99.8 mw in Spain (Spain solar projects) (see Note 13 - Commitments for recent changes in law that could negatively affect the Spain solar projects) and 250 mw in California (Genesis solar project), which are expected to be completed in 2013 and 2014, respectively. In addition, a 550 mw solar PV project in California (Desert Sunlight solar project), in which NEER has a 50% equity investment, has commenced construction and commercial operation is expected to be phased in during 2013 through 2015. During 2012, NEER acquired 40 mw of new solar generation in Canada.

Other Assets

At December 31, 2012, NEER had 1,155 mw of generation assets from a variety of other fuel technologies, including oil and hydropower, with facilities located throughout the Northeast. In late 2012, a subsidiary of NEER entered into an agreement to sell its ownership interest in a portfolio of hydropower generation plants and related assets with a total generating capacity of 351 mw located in Maine and New Hampshire. Upon the anticipated closing in the first quarter of 2013, NEER will have no further investments in hydropower assets.

Policy Incentives for Renewable Energy Projects

In its development and operation of U.S. wind generation facilities, NEER depends heavily on the federal PTC, which currently provides an income tax credit for the production of electricity from utility-scale wind turbines for the first ten years of commercial operation. This incentive was created under the Energy Policy Act of 1992 and was set to expire such that it would not apply to wind projects that achieve commercial operation after December 31, 2012. Under the American Taxpayer Relief Act of 2012 (Taxpayer Relief Act), the PTC was extended for wind projects whose construction begins by December 31, 2013. Alternatively, wind project developers can choose to receive a 30% ITC, in lieu of the PTC, with the same requirement that construction of the wind project begin by December 31, 2013. For qualifying wind projects where construction began before the end of 2011 and the projects were placed in service in 2012, wind project developers could elect to receive an equivalent cash payment from the U.S. Department of Treasury for the value of the 30% ITC. NEER's expectations for wind development and construction in 2013 and beyond will depend, in part, on rules to be established under the Taxpayer Relief Act.

Solar project developers are also eligible to receive a 30% ITC for new solar projects that achieve commercial operations before 2017. Solar project developers can elect to receive an equivalent cash payment from the U.S. Department of Treasury for the value of the 30% ITC for qualifying solar projects where construction began before the end of 2011 and the projects are placed in service before 2017.

Other countries, including Canada and Spain, provide for incentives like feed-in-tariffs for renewable energy projects. The feed-in-tariffs promote renewable energy investments by offering long-term contracts to renewable energy producers, typically based on the cost of generation of each technology.

NEER Generation by Geographic Region

NEER's generating capacity spans various geographic regions in North America, thereby reducing overall volatility related to varying market conditions and seasonality on a portfolio basis. NEER's generating facilities at December 31, ~~2011~~2012 are categorized by geographic region (~~See~~see Item 2 - Generating Facilities) in terms of mw of capacity as follows:

NEER's power generation in terms of mwh produced for the year ended December 31, 2011 by fuel type is as follows:

NEER CUSTOMER SUPPLY AND PROPRIETARY POWER AND GAS TRADING

PMI, a subsidiary of NEER, buys and sells wholesale energy commodities, such as electricity, natural gas and oil. PMI sells the output from NEER's plants that has not been sold under long-term contracts and procures the non-nuclear fuel for use by NEER's generation fleet. Its primary role is to manage the commodity risk of NEER's portfolio. PMI uses derivative instruments such as swaps, options, futures and forwards to manage the risk associated with fluctuating commodity prices and to optimize the value of NEER's power generation assets.

PMI also provides a wide range of electricity and gas commodity products as well as marketing and trading services to electric and gas utilities, municipalities, cooperatives and other load-serving entities, as well as to owners of electric generation facilities. PMI's customer supply business includes providing full energy and capacity requirements and mid-marketing services that include sales and purchases of wholesale commodities-related products and the operations of a retail electricity provider, which during 2011, served approximately 2,200 mw of peak load to approximately 201,800 customers across the ERCOT, New England Power Pool (NEPOOL), PJM, NYISO and MISO markets.

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NEER's power generation in terms of mwh produced for the year ended December 31, 2012 by fuel type is as follows:

NEER CUSTOMER SUPPLY AND PROPRIETARY POWER AND GAS TRADING

PMI, a subsidiary of NEER, buys and sells wholesale energy commodities, such as electricity, natural gas and oil. PMI sells the output from NEER's plants that is not sold under long-term contracts and procures the non-nuclear fuel for use by NEER's generation fleet. Its primary role is to manage the commodity risk of NEER's portfolio. PMI uses derivative instruments such as swaps, options, futures and forwards to manage the risk associated with fluctuating commodity prices and to optimize the value of NEER's power generation assets.

PMI also provides a wide range of electricity and gas commodity products as well as marketing and trading services to electric and gas utilities, municipalities, cooperatives and other load-serving entities, as well as to owners of electric generation facilities. PMI's customer supply business includes providing full energy and capacity requirements and mid-market services that include sales and purchases of wholesale commodities-related products and the operations of a retail electricity provider, which during 2012, served approximately 2,950 mw of peak load to approximately 209,100 customers across the ERCOT, New England Power Pool (NEPOOL), PJM, NYISO and MISO markets.

The results of PMI's activities are included in NEER's operating results. See Management's Discussion - Energy Marketing and Trading and Market Risk Sensitivity, Note 1 - Energy Trading and Note 3.

NEER REGULATION

~~Each~~The ~~of the~~ energy markets in which NEER operates isare subject to domestic and foreign regulation, including local, state and federal regulation, and other specific rules.

At December 31, ~~2011~~2012, NEER had ownership interests in operating independent power projects located in the U.S. that have received exempt wholesale generator status as defined under the Public Utility Holding Company Act of 2005, which represent approximately 9596% of NEER's net generating capacity. Exempt wholesale generators own or operate a facility exclusively to sell electricity to wholesale customers. They are barred from selling electricity directly to retail customers. NEER's exempt wholesale generators produce electricity from wind, hydro, fossil fuels and nuclear facilities. Essentially all of the remaining 54% of NEER's net generating capacity has qualifying facility status under the PURPA. NEER's qualifying facilities generate electricity primarily from wind, solar and fossil fuels. Qualifying facility status exempts the projects from, among other things, many of the provisions of the Federal Power Act, as well as state laws and regulations relating to rates and financial or organizational regulation of electric utilities. While projects with qualifying facility and/or exempt wholesale generator status are exempt from various restrictions, each project must still comply with other federal, state and local laws, including, but not limited to, those regarding siting, construction, operation, licensing, pollution abatement and other environmental laws.

Additionally, most of the NEER facilities located in the U.S. are subject to FERC regulations and market rules, the NERC's mandatory reliability standards and the EPA's environmental laws, and its nuclear facilities are also subject to the jurisdiction of the NRC. See FPL - FPL Regulation for additional discussion of FERC, NERC, NRC, and EPA regulations. With the exception of facilities located in ERCOT, the FERC has jurisdiction over various aspects of NEER's business in the U.S., including the oversight and investigation of competitive wholesale energy markets, regulation of the transmission and sale of natural gas, regulation of hydro projects and oversight of environmental matters related to natural gas and hydro projects and major electricity policy initiatives. The PUCT has jurisdiction, including the regulation of rates and services, oversight of competitive markets, and enforcement of statutes and rules, over NEER facilities located in ERCOT. NEER and its affiliates are also subject to national and provincial or regional regulations in Canada and Spain related to energy operations, energy markets and environmental standards.

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NEER is subject to environmental laws and regulations, and is affected by some of the emerging issues related to renewable energy resources as described in the NEE Environmental Matters section below. In order to better anticipate these potential regulatory changes, NEER continues to actively evaluate and participate in regional market redesigns of existing operating rules for the integration of renewable energy resources and for the purchase and sale of energy commodities.

NEER EMPLOYEES

NEER and its subsidiaries had approximately 4,700 employees at December 31, ~~2011~~2012. ~~Subsidiaries~~Certain subsidiaries of NEER have collective bargaining agreements with ~~various~~the ~~unions~~IBEW, ~~which~~the ~~are~~Utility ~~summarized~~Workers inUnion of America, the ~~table~~Security ~~below~~Police and Fire Professionals of America and the International Union of Operating Engineers, which collectively represent approximately 23% of NEER's employees. The collective bargaining agreements have one- to five-year terms and expire between September 2013 and 2015.

Union	Location	ContractExpiration Date	% of NEER'sEmployees Covered
IBEW	Wisconsin	June 2012 - September 2013(a)	10	%
Utility Workers Union of America	New Hampshire	December 2013	5
IBEW	Iowa	May 2012	3
Security Police and Fire Professionals of America	Iowa	July 2012	2
IBEW	Maine	February 2013	2
IBEW	California	March 2012	-		(b)
Total			22	%

(a) Various employees at Point Beach are represented by the IBEW under four separate contracts with different expiration dates.

(b) Less than 1% of NEER's employees.

In addition, the employees of an operating project in Illinois, constituting less than 1% of NEER's employees, are represented by the International Union of Operating Engineers, which is currently negotiating its first collective bargaining agreement.

III. OTHER NEE OPERATING SUBSIDIARIES

NEE's Corporate and Other segment represents other business activities, primarily ~~FPL~~NEET ~~FiberNet~~ and ~~Lone~~FPL ~~Star~~FiberNet, that are not separately reportable. See Note 1514.

~~FPL FIBERNET~~NEET

~~FPL~~NEET, ~~FiberNet~~a ~~conducts its business through two separate~~ wholly-owned ~~subsidiaries~~subsidiary of NEECH~~. One~~, ~~subsidiary~~is ~~was~~a ~~formed~~limited inliability ~~2000~~company toorganized ~~enhance~~under the ~~value~~laws of ~~NEE's~~Delaware. NEET ~~fiber-optic~~conducts ~~network~~its ~~assets~~business ~~that~~primarily ~~were~~through ~~originally~~two ~~built~~subsidiaries, toLone ~~support~~Star ~~FPL~~and ~~operations~~NHT, and ~~the~~is ~~other~~pursuing ~~was~~opportunities ~~formed in 2011~~ to ~~hold~~develop, ~~fiber-optic~~build ~~network~~and ~~assets~~operate ~~which~~new ~~were~~transmission ~~acquired. Both~~facilities ~~subsidiaries~~throughout ~~are~~North ~~limited liability companies organized under the laws of Delaware~~America. ~~FPL~~ ~~FiberNet leases fiber-optic network capacity and dark fiber to FPL and other customers,~~

19Lone Star

Lone Star is a limited liability company organized under the laws of Delaware. Lone Star, a rate-regulated transmission service provider in Texas, is constructing approximately 330 miles of 345 kilovolt (kv) transmission lines and other associated facilities. Two substations and associated facilities with a total capital investment of approximately $49 million were placed in service in 2012, with the remaining associated facilities and transmission lines expected to be placed in service in March 2013, for a total capital investment of approximately $780 million. Lone Star's transmission lines are part of a transmission grid improvement program that will add approximately 2,300 miles of 345 kv lines to deliver power from the Competitive Renewable Energy Zones in west Texas and the Texas panhandle to the Dallas/Fort Worth area and other population centers in Texas.

Lone Star is subject to regulation by a number of federal, state and other agencies, including, but not limited to, the PUCT, the ERCOT, the NERC and the EPA, as well as certain limited regulations of the FERC. See FPL - FPL Regulation for further discussion of FERC, NERC and EPA regulations and NEE Environmental Matters. The PUCT has jurisdiction over a wide range of Lone Star's business activities, including, among others, rates charged to customers and certain aspects of siting, construction and operation of transmission systems. The PUCT sets rates at a level that allows Lone Star the opportunity to collect from customers total revenues (revenue requirements) equal to Lone Star's cost of providing service, including a reasonable rate of return on invested capital.

In October 2012, the PUCT reached a decision in Lone Star's initial rate case proceeding. In January 2013, the PUCT, during rehearing, approved Lone Star's wholesale transmission service rate reflecting an annual revenue requirement for, among other things, capital investment of approximately $49 million, a regulatory equity ratio of 45%, an allowed regulatory ROE of 9.6% and other operating expenses. The remaining capital investment will be included in Lone Star's rates by means of an interim rate adjustment mechanism. In addition, Lone Star must file a general rate case, with a full 12-month historical test year, within four months of having 12 months of historical operating data, which is expected to occur in mid-2014.

NHT

NHT, a rate-regulated transmission owner in ISO-NE, is a limited liability company organized under the laws of Delaware. NHT owns transmission facilities which connect NEER's Seabrook nuclear facility to the New England transmission grid and interconnect three 345 kv transmission lines in New England. NHT is subject to regulation by a number of federal, state and other agencies, including, but not limited to, the New Hampshire Public Utility Commission, ISO-NE, the FERC, the NERC and the EPA. See FPL - FPL Regulation for further discussion of FERC, NERC and EPA regulations and NEE Environmental Matters. NHT wholesale transmission revenues are provided through an ISO-NE tariff.

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~~primarily telephone, wireless, internet and other telecommunications companies.~~ FPL FiberNet's networks cover most of the metropolitan areas in Florida and several in Texas. FPL FiberNet also has a long-haul network providing bandwidth at wholesale rates. The long-haul network connects major cities in Florida and Texas with additional connectivity to Atlanta, Georgia and the South Central U.S., including Arkansas, Louisiana and Oklahoma. At December 31, 2011, FPL FiberNet's network consisted of approximately 7,800 route miles. FPL FiberNet is subject to regulation by the Federal Communications Commission which has jurisdiction over wire and wireless communication networks and by the public utility commissions in the states in which it provides intrastate telecommunication services.FIBERNET

~~LONE~~FPL ~~STAR~~FiberNet conducts its business through two separate wholly-owned subsidiaries of NEECH. One subsidiary was formed in 2000 to enhance the value of NEE's fiber-optic network assets that were originally built to support FPL operations and the other was formed in 2011 to hold fiber-optic network assets which were acquired. Both subsidiaries are limited liability companies organized under the laws of Delaware. FPL FiberNet leases fiber-optic network capacity and dark fiber to FPL and other customers, primarily telephone, wireless, internet and other telecommunications companies. FPL FiberNet's networks cover most of the metropolitan areas in Florida and several in Texas. FPL FiberNet also has a long-haul network providing bandwidth at wholesale rates. The long-haul network connects major cities in Florida and Texas with additional connectivity to Atlanta, Georgia and the South Central U.S., including Arkansas, Louisiana and Oklahoma. At December 31, 2012, FPL FiberNet's network consisted of approximately 8,600 route miles. FPL FiberNet is subject to regulation by the Federal Communications Commission which has jurisdiction over wire and wireless communication networks and by the public utility commissions in the states in which it provides intrastate telecommunication services.

Lone Star, an indirect wholly-owned subsidiary of NEECH, is constructing approximately 320 miles of 345 kv transmission lines and other associated facilities in Texas. Lone Star, a limited liability company organized under the laws of Delaware, is a rate-regulated transmission service provider in Texas. Two substations and associated facilities with a total capital investment of approximately $60 million are expected to be placed in service in 2012, with the remaining associated facilities and transmission lines expected to be placed in service in the first quarter of 2013, for a total capital investment of approximately $785 million. Lone Star's transmission lines are part of a transmission grid improvement program that will add approximately 2,300 miles of 345 kv lines to deliver power from the Competitive Renewable Energy Zones in west Texas and the Texas panhandle to the Dallas/Fort Worth area and other population centers in Texas. Lone Star will own the transmission lines and associated facilities and operate them after they are placed in service.

Lone Star is subject to regulation by a number of federal, state and other agencies, including, but not limited to, the PUCT, the ERCOT, the NERC and the EPA, as well as certain limited regulations of the FERC. See I. FPL - FPL Regulation for further discussion of FERC, NERC, and EPA regulations and NEE Environmental Matters. The PUCT has jurisdiction over a wide range of Lone Star's business activities, including, among others, rates charged to customers and certain aspects of siting, construction and operation of transmission systems. The PUCT sets rates at a level that allows Lone Star the opportunity to collect from customers total revenues (revenue requirements) equal to Lone Star's cost of providing service, including a reasonable rate of return on invested capital.

In January 2012, Lone Star filed a petition with the PUCT requesting, among other things, interim rates that would take effect when Lone Star's first substation is placed in service and final rates when the transmission lines are energized. The petition also proposes to limit cost recovery to Lone Star's actual capital costs by making a true-up filing within 120 days of energizing the transmission lines. If approved, based on the expected in-service dates, the requested rates would result in annual revenues of approximately $14 million in 2012 and $110 million in 2013. Lone Star's requested rates are based on a proposed regulatory ROE of 11% with a regulatory equity ratio of 52%. Hearings on this rate proceeding are expected during the second quarter of 2012 and a final decision is expected during the third quarter of 2012. The interim rates would be subject to refund pending the final decision on the rate proceeding. The PUCT has the authority to disallow recovery of costs that it considers excessive or imprudently incurred.

NEE ENVIRONMENTAL MATTERS

NEE and FPL are subject to domestic and foreign environmental laws and regulations, including extensive federal, state, and local environmental statutes, rules, and regulations. The U.S. Congress and certain states and regions continue to consider several legislative and regulatory proposals with respect to GHG emissions. The economic and operational impact of climate change legislation on NEE and FPL depends on a variety of factors, including, but not limited to, the allowed emissions, whether emission allowances will be allocated or auctioned, the cost to reduce emissions or buy allowances in the marketplace and the availability of offsets and mitigating factors to moderate the costs of compliance. Based on the most recent reference data available from government sources, NEE is among the lowest emitters, among electric generators, of GHG in the U.S. measured by its rate of emissions expressed as pounds of CO2 per mwh of generation. However, the legislative and regulatory proposals have differing methods of implementation and the impact on FPL's and NEER's generating units and/or the financial impact (either positive or negative) to NEE and FPL could be material, depending on the eventual structure of any ~~legislation enacted or~~ specific implementation rules adopted.

I. Environmental Regulations

The following is a discussion of certain existing and emerging federal and state initiatives and rules, some of which could potentially have a material effect (either positive or negative) on NEE and its subsidiaries. FPL expects to seek recovery through the environmental clause for compliance costs associated with any new environmental laws and regulations.

• ~~Mercury~~Clean ~~and~~Air Interstate Rule (CAIR)/Cross-State Air ~~Toxics~~Pollution ~~Standards~~Rule (~~MATS~~CSAPR). InThe ~~December~~EPA's ~~2011,~~CAIR ~~the~~requires ~~EPA~~SO2 ~~issued~~and aNOx ~~final~~emissions ~~MATS~~reductions ~~rule~~from aselectric ~~required~~generating ~~under~~units in specified Eastern states and the ~~Clean~~District ~~Air~~of ~~Act~~Columbia, ~~which~~where ~~requires~~the ~~coal-fired~~emissions ~~and~~from ~~oil-fired~~electric generating units toare ~~reduce~~deemed ~~emissions~~to ofbe ~~hazardous~~transported ~~air~~to ~~pollutants~~downwind states. ~~The~~NEER ~~MATS~~and ~~rule~~FPL ~~includes~~began acomplying ~~limited~~with ~~use~~the ~~provision~~CAIR ~~which~~on ~~excludes~~January ~~low-capacity~~1, ~~generating~~2009. ~~units~~In ~~from~~July 2011, the ~~requirements~~EPA toissued ~~add~~the ~~pollution~~CSAPR, ~~control~~a ~~equipment,~~final ~~under~~rule which ~~three~~was ~~oil-fired~~to ~~units~~replace atthe ~~FPL~~CAIR ~~and~~beginning ~~four~~in ~~oil-fired~~January ~~units~~2012. atThe ~~NEER~~CSAPR ~~are~~would ~~expected~~limit toemissions ~~qualify.~~of ~~Based~~SO2 onand ~~the~~NOx ~~provisions~~from ofpower ~~the~~plants ~~rule,~~in ~~four~~28 ~~oil-fired~~eastern ~~units~~states and ~~two~~provides ~~coal-fired~~an ~~units~~allocation atmethodology ~~FPL~~for ~~are~~emission inallowances ~~the~~and ~~process~~reduction oflimits ~~adding~~for orSO2, ~~could~~NOx beand ~~required~~seasonal toozone ~~add~~requirements. ~~additional~~In ~~pollution~~August ~~control~~2012, ~~equipment~~the toD.C. ~~meet~~Circuit ~~Maximum~~vacated ~~Achievable~~the ~~Control~~CSAPR ~~Technology~~and ~~standards~~remanded it back to the EPA for further rulemaking. AThe ~~third~~D.C. ~~coal-fired~~Circuit ~~unit~~ordered atthat ~~FPL~~the isCAIR remain in place until such time that the ~~process~~EPA ofpromulgates ~~adding~~a ~~additional~~valid ~~pollution~~replacement. ~~control~~Several ~~equipment~~parties, toincluding ~~meet~~the ~~certain~~EPA, ~~state~~filed ~~compliance~~for ~~requirements~~rehearing, which ~~would~~the ~~also~~D.C. ~~satisfy~~Circuit ~~the~~denied ~~Maximum~~in ~~Achievable~~January ~~Control~~2013. ~~Technology~~Those ~~standards~~parties ~~under~~have ~~the~~until ~~MATS~~April ~~rule.~~2013 ~~Units~~to ~~affected~~seek review by the ~~rule~~U.S. ~~will~~Supreme Court.

20• Clean Water Act Section 316(b). In March 2011, the EPA issued a proposed rule under Section 316(b) of the Clean Water Act to address the location, design, construction and capacity of intake structures at existing power plants with once-through cooling water systems, with a final rule expected by the summer of 2013. The proposed rule is intended to require the Best Technology Available to reduce the impact on aquatic organisms from once-through cooling water intake systems. Under the proposed rule, potentially thirteen of FPL's facilities and five of NEER's facilities may be required to add additional controls and/or make operational changes to comply, the economic and operational impact of which cannot be determined at this time, but could be material. Prior to the passage of a new rule, states are continuing to utilize "Best Professional Judgment" in the application of Section 316(b) compliance requirements.

•

Regulation of GHG Emissions. The EPA continues to evaluate regulatory options under the Clean Air Act for existing fossil fuel-fired power units. The EPA's proposed rule is anticipated in either late 2013 or early 2014 and could be finalized in late 2014. This EPA guidance will direct each state to develop their respective state implementation plan which will set forth the program requirements within that state, and compliance would be expected over several years.


•	Revisions to the National Ambient Air Quality Standards (NAAQS) for Particulate Matter. In December 2012, the EPA proposed a rule revision for particulate matter NAAQS to lower the annual PM2.5 standard, which proposed rule is not expected to have a significant impact on FPL or NEER facilities.

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be• ~~required~~Avian/Bat Regulations and Wind Turbine Siting Guidelines. NEER and FPL are subject to ~~comply~~numerous byenvironmental ~~April~~regulations ~~2015~~and guidelines related to threatened and endangered species and their habitats, ~~with~~as well as avian and bat species, for the siting, construction and ongoing operations of their facilities. The facilities most significantly affected are wind facilities and transmission and distribution lines. The environmental laws include, among others, the Endangered Species Act, the Migratory Bird Treaty Act, and the Bald and Golden Eagle Protection Act which provide for protection of migratory birds, eagles and endangered species of birds and bats and their habitats. Regulations have been adopted under some of these laws that contain provisions that allow the owner/operator of a ~~possible~~facility ~~one~~to ~~year~~apply ~~extension~~for a permit to undertake specific activities including those associated with certain siting decisions, construction activities and operations. In addition to regulations, voluntary wind turbine siting guidelines established by the U.S. Fish and Wildlife Service set forth siting, monitoring and coordination protocols that are designed to support wind development in the U.S. while also protecting both birds and bats and their habitats. These guidelines include provisions for ~~compliance~~specific ifmonitoring ~~required~~and study conditions which need to ~~install~~be ~~pollution~~met ~~control~~in ~~equipment~~order for projects to be in adherence with these voluntary guidelines. Complying with these environmental regulations and adhering to the provisions set forth in the voluntary wind turbine siting guidelines could result in additional costs at existing and new wind generating facilities and transmission and distribution facilities at NEER and FPL.

• Clean Air Interstate Rule (CAIR)/Cross-State Air Pollution Rule (CSAPR). The EPA's CAIR requires SO2 and NOx emissions reductions from electric generating units in specified Eastern states and the District of Columbia, where the emissions from electric generating units are deemed to be transported to downwind states. NEER and FPL began complying with the CAIR on January 1, 2009. In July 2011, the EPA issued the CSAPR, a final rule which was to replace the CAIR beginning in January 2012. The CSAPR would limit emissions of SO2 and NOx from power plants in 28 eastern states and provides an allocation methodology for emission allowances and reduction limits for SO2 and NOx beginning in January 2012 and seasonal ozone requirements beginning in May 2012, with a second phase of reductions beginning in January 2014. FPL would only be affected by the seasonal ozone requirements of the rule while NEER would be affected by the annual SO2 and NOx emissions requirements as well as the seasonal ozone requirements in several states. Several groups have petitioned the EPA to reconsider the CSAPR and in December 2011, the D.C. Circuit issued an order staying implementation of the CSAPR pending resolution of legal challenges to the rule and ordered that the CAIR remain in place while the CSAPR is stayed. The case is scheduled for oral argument in April 2012. The ultimate resolution of the issues surrounding the CSAPR is uncertain at this time.

• Clean Water Act Section 316(b). In March 2011, the EPA issued a proposed rule under Section 316(b) of the Clean Water Act to address the location, design, construction and capacity of intake structures at existing power plants with once-through cooling water systems, with a final rule not expected until the summer of 2012. The proposed rule is intended to require the Best Technology Available to reduce the impact on aquatic organisms from once-through cooling water intake systems. Under the proposed rule, potentially thirteen of FPL's facilities and five of NEER's facilities may be required to add additional controls or make operational changes to comply, the economic and operational impact of which cannot be determined at this time, but could be material. Prior to the passage of a new rule, states are continuing to utilize “Best Professional Judgment” in the application of Section 316(b) compliance requirements.

• Avian/Bat Regulations and Wind Turbine Siting Guidelines. NEER and FPL are subject to numerous environmental regulations and guidelines related to threatened and endangered species and their habitats, as well as avian and bat species, for the siting, construction and ongoing operations of their facilities. The facilities most significantly affected are wind facilities and transmission and distribution lines. The environmental laws include, among others, the Endangered Species Act, the Migratory Bird Treaty Act, and the Bald and Golden Eagle Protection Act which provide for protection of migratory birds, eagles and endangered species of birds and bats and their habitats. Regulations have been adopted under some of these laws that contain provisions that allow the owner/operator of a facility to apply for a permit to undertake specific activities including those associated with certain siting decisions, construction activities and operations. In addition to regulations, voluntary wind turbine siting guidelines, which are expected to be finalized by the U.S. Fish and Wildlife Service by the end of the first quarter of 2012, will set forth siting, monitoring and coordination protocols that are designed to support wind development in the U.S. while also protecting both birds and bats and their habitats. These guidelines will include provisions for specific monitoring and study conditions which will need to be met in order for projects to be in adherence with these voluntary guidelines. Complying with these new environmental regulations and adhering to the provisions set forth in the voluntary wind turbine siting guidelines could result in additional costs at existing and new wind generating facilities and transmission and distribution facilities at NEER and FPL.

• Regulation of GHG Emissions. Pursuant to rules issued by the EPA under the Clean Air Act, new facilities emitting 100,000 tons per year (tpy) or more of GHG and modifications to existing facilities resulting in an increase of GHG emissions of 75,000 tpy or more have to perform a Best Available Control Technology review and, based on that review, may have to reduce emissions by adding additional emissions control equipment or implementing energy efficiency projects. Several petitioners have challenged the EPA's GHG regulations and the case is pending review by the D.C. Circuit, the timing and ultimate outcome of which is uncertain at this time. At FPL, the modernization of the Port Everglades facility, if approved by the FPSC, would be affected by this rule, the impact of which cannot be determined at this time.

II. Other GHG Emissions Reduction Initiatives

NEER's plants operate in certain states and regions that continue to consider and implement regulatory proposals to reduce GHG emissions. RPS, currently in place in approximately 30 states and the District of Columbia, require electricity providers in the state or district to meet a certain percentage of their retail sales with energy from renewable sources. These standards vary, but the majority include requirements to meet 10% to 25% of the electricity providers' retail sales with energy from renewable sources by 2025. NEER's plants operate in 1819 states that have a RPS and NEER believes that these standards will create incremental demand for renewable energy in the future.

Other GHG reduction initiatives including, among others, the Regional Greenhouse Gas Initiative and the California Greenhouse Gas Regulation aim to reduce emissions through a variety of programs and under varying timelines. Based on its clean generating portfolio, NEER expects to continue experiencing a positive impact on earnings as a result of these GHG reduction initiatives. Additionally, these initiatives provide NEER opportunities with regards to wind and solar development as well as favorable energy pricing.

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WEBSITE ACCESS TO SEC FILINGS

NEE and FPL make their SEC filings, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, available free of charge on NEE's internet website, www.nexteraenergy.com, as soon as reasonably practicable after those documents are electronically filed with or furnished to the SEC. The information and materials available on NEE's website (or any of its subsidiaries' websites) are not incorporated by reference into this combined ~~annual report on~~ Form 10-K. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at ~~http://~~www.sec.gov.

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EXECUTIVE OFFICERS OF NEE^(a)

Name	Age	Position	Effective Date
Christopher A. Bennett	53	Executive Vice President & Chief Strategy, Policy & Business Process Improvement Officer of NEE	February 15, 2008(b)
Paul I. Cutler	53	Treasurer of NEETreasurer of FPLAssistant Secretary of NEE	February 19, 2003February 18, 2003December 10, 1997
Paul I. Cutler	52	Treasurer of NEETreasurer of FPLAssistant Secretary of NEE and FPL	February 19, 2003February 18, 2003December 10, 1997
Moray P. Dewhurst	57	Vice Chairman and Chief Financial Officer, and Executive Vice President - Finance of NEEExecutive Vice President, Finance and Chief Financial Officer of FPL	October 5, 2011
Moray P. Dewhurst	56	Vice Chairman and Chief Financial Officer, and Executive Vice President - Finance of NEEExecutive Vice President, Finance and Chief Financial Officer of FPL	October 5, 2011
Shaun J. Francis	41	Executive Vice President, Human Resources and Corporate Services of NEEExecutive Vice President, Human Resources and Corporate Services of FPL	January 1, 2013
Shaun J. Francis	40	Executive Vice President, Human Resources of NEEExecutive Vice President, Human Resources of FPL	August 16, 2010January 31, 2011
Chris N. Froggatt	55	Vice President of NEEController and Chief Accounting Officer of NEE	October 19, 2009February 27, 2010
Chris N. Froggatt	54	Vice President of NEEController and Chief Accounting Officer of NEE	October 19, 2009February 27, 2010
Lewis Hay, III	57	Executive Chairman of NEE	July 1, 2012
Lewis Hay, III	56	Chief Executive Officer of NEEChairman of NEE and FPL	June 11, 2001January 1, 2002
Joseph T. Kelliher	52	Executive Vice President, Federal Regulatory Affairs of NEE	May 18, 2009
Joseph T. Kelliher	51	Executive Vice President, Federal Regulatory Affairs of NEE	May 18, 2009
Manoochehr K. Nazar	58	Executive Vice President, Nuclear Division and Chief Nuclear Officer of NEEExecutive Vice President, Nuclear Division and Chief Nuclear Officer of FPL	January 1, 2010January 15, 2010
Robert L. McGrath	58	Executive Vice President, Engineering, Construction & Corporate Services of NEE and FPL	February 21, 2005(b)
Armando Pimentel, Jr.	50	President and Chief Executive Officer of NEER	October 5, 2011
Manoochehr K. Nazar	57	Executive Vice President, Nuclear Division and Chief Nuclear Officer of NEEExecutive Vice President, Nuclear Division and Chief Nuclear Officer of FPL	January 1, 2010January 15, 2010
James L. Robo	50	President and Chief Executive Officer of NEEChairman and Chief Executive Officer of FPL	July 1, 2012May 2, 2012
Armando J. Olivera	62	Chief Executive Officer of FPL	July 17, 2008
Antonio Rodriguez(b)	70	Executive Vice President, Power Generation Division of NEEExecutive Vice President, Power Generation Division of FPL	January 1, 2007July 1, 1999
Armando Pimentel, Jr.	49	President and Chief Executive Officer of NEER	October 5, 2011
Charles E. Sieving	40	Executive Vice President & General Counsel of NEEExecutive Vice President of FPL	December 1, 2008January 1, 2009
James L. Robo	49	President and Chief Operating Officer of NEE	December 15, 2006
Eric E. Silagy	47	President of FPL	December 16, 2011
Antonio Rodriguez	69	Executive Vice President, Power Generation Division of NEEExecutive Vice President, Power Generation Division of FPL	January 1, 2007(b)July 1, 1999(b)
William L. Yeager	54	Executive Vice President, Engineering, Construction & Integrated Supply Chain of NEE Executive Vice President, Engineering, Construction & Integrated Supply Chain of FPL	January 1, 2013
Charles E. Sieving	39	Executive Vice President & General Counsel of NEEExecutive Vice President of FPL	December 1, 2008January 1, 2009

______________________

(a) Information is as of February 27, ~~2012~~2013. Executive officers are elected annually by, and serve at the pleasure of, their respective boards of directors. Except as noted below, each officer has held his present position for five years or more and his employment history is continuous. Mr. Bennett was vice president, business strategy & policy of NEE from July 2007 to February 2008. From September 1995 to June 2007, Mr. Bennett was vice president of Dean & Company, a management consulting and investment firm. Mr. Dewhurst has been vice chairman of NEE since August 2009 and was chief of staff of NEE from August 2009 to October 2011. From July 2001 to May 2008, Mr. Dewhurst was vice president, finance and chief financial officer of NEE and senior vice president, finance and chief financial officer of FPL. Mr. Francis ~~was~~has ~~general~~been ~~manager~~executive vice president of human resources ~~for a division~~ of ~~General~~NEE ~~Electric~~since ~~Company,~~August GE2010 ~~Transportation,~~and aexecutive ~~supplier~~vice topresident ~~the~~of ~~railroad,~~human ~~marine,~~resources ~~drilling,~~of ~~mining~~FPL ~~and~~since ~~wind~~January ~~power industries from February 2008 to August 2010~~2011. ~~From February 2006 to February 2008,~~ Mr. Francis ~~served~~was as general manager of human resources for a division of General Electric Company, GE ~~Equipment Services~~Transportation, a ~~leader~~supplier into the ~~transportation~~railroad, ~~industry~~marine, ~~including~~drilling, ~~rail~~mining ~~cars,~~and ~~sea~~wind ~~containers,~~power ~~tractor~~industries ~~trailers,~~from ~~and~~February ~~truck~~2008 ~~leasing~~to August 2010. Mr. Froggatt was the vice president and treasurer of Pinnacle West Capital Corporation, a public utility holding company, and its major subsidiary, Arizona Public Service Company (APS), a regulated electric utility, from December 2008 to October 2009. From October 2002 to December 2008, Mr. Froggatt was vice president, controller and chief accounting officer of APS. Mr. Hay was ~~also~~ chief executive officer of ~~FPL~~NEE from ~~January~~June ~~2002~~2001 to ~~July~~June ~~2008~~2012. Mr. ~~Kelliher~~Hay was also chairman of ~~the~~NEE ~~FERC~~ from ~~July~~January ~~2005~~2002 to June 2012 and chairman of FPL from January ~~2009~~2002 to May 2012. From January 2002 to July 2008, Mr. ~~Nazar~~Hay was ~~the~~also chief ~~nuclear~~executive officer of ~~NEE~~FPL. Mr. Kelliher was chairman of the FERC from ~~January~~July ~~2009~~2005 to ~~December~~January 2009. Mr. Nazar was ~~senior~~the ~~vice president and~~ chief nuclear officer of ~~FPL~~NEE from ~~November~~January ~~2007~~2009 to ~~January~~December 2009. From ~~October~~January ~~2003~~2009 to ~~November~~January ~~2007~~2010, Mr. Nazar was the senior vice president &and chief nuclear officer of ~~American~~FPL. ~~Electric Power Company, Inc~~Mr., aNazar ~~public~~was ~~utility~~senior ~~holding~~vice ~~company.~~president ~~Mr.~~and ~~Olivera~~nuclear ~~was~~chief ~~also~~operating ~~president~~officer of FPL from ~~June~~November ~~2003~~2007 to ~~December~~January ~~2011~~2009. Mr. ~~Olivera has announced that he will retire from FPL on May 2, 2012. Mr.~~ Pimentel was chief financial officer of NEE and FPL from May 2008 to October 2011 and executive vice president, finance of NEE and FPL from February 2008 to October 2011. ~~Prior to that,~~ Mr. ~~Pimentel~~Robo was apresident ~~partner~~and ofchief ~~Deloitte~~operating &officer ~~Touche~~of ~~LLP,~~NEE ~~an independent registered public accounting firm,~~ from ~~June~~December ~~1998~~2006 to ~~February~~June ~~2008~~2012. Mr. Sieving was also assistant secretary of NEE from May 2010 to May 2011 and general counsel of FPL from January 2009 to May 2010. Mr. Sieving was executive vice president, general counsel and secretary of PAETEC Holding Corp., a communications services and solutions provider, from February 2007 to November 2008 and was primarily responsible for all legal and regulatory matters. Mr. Silagy was senior vice president, regulatory and state governmental affairs of FPL from May 2010 to December 2011. Mr. Silagy was vice president and chief development officer of FPL from July 2008 to May 2010. From November 2007 to July 2008, Mr. Silagy was vice president, development of FPL. Mr. Yeager was vice president, engineering, construction and integrated supply chain services of NEE and FPL from October 2012 to December 2012. Mr. Yeager was vice president, integrated supply chain of NEE and FPL from May 2011 to October 2012. From January 2005 to May 2011, Mr. Yeager was vice president, engineering and construction of FPL.

(b) NEE title changed from vice president to executive vice president effective May 23, 2008. ~~Where~~and ~~applicable,~~ FPL title changed from senior vice president to executive vice president effective July 17, 2008.

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Item 1A. Risk Factors

Risks Relating to NEE's and FPL's Business

The business, financial condition, results of operations and prospects of NEE and FPL are subject to a variety of risks, many of which are beyond the control of NEE and FPL. The following is a description of important risks that may adversely affect the business, financial condition, results of operations and prospects of NEE and FPL and may cause actual results of NEE and FPL to differ substantially from those that NEE or FPL currently expects or seeks. In that event, the market price for the securities of NEE or FPL could decline. Accordingly, the risks described below should be carefully considered together with the other information set forth in this report and in future reports that NEE and FPL file with the SEC. The risks described below are not the only risks facing NEE and FPL. Additional risks and uncertainties may also materially adversely affect NEE's or FPL's business, financial condition, results of operations and prospects. Each of NEE and FPL has disclosed the material risks known to it to affect its business at this time. However, there may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may in the future adversely affect the performance or financial condition of NEE and FPL.

Regulatory, Legislative and Legal Risks

NEE's and FPL's business, financial condition, results of operations and prospects may be adversely affected by the extensive regulation of their business.

The operations of NEE and FPL are subject to complex and comprehensive federal, state and other regulation. This extensive regulatory framework, portions of which are more specifically identified in the following risk factors, regulates, among other things and to varying degrees, NEE's and FPL's industries, rates and cost structures, operation of nuclear power facilities, construction and operation of generation, transmission and distribution facilities and natural gas and oil production, transmission and fuel storage facilities, acquisition, disposal, depreciation and amortization of facilities and other assets, decommissioning costs and funding, service reliability, wholesale and retail competition, and commodities trading and derivatives transactions. In their business planning and in the management of their operations, NEE and FPL must address the effects of regulation on their business and any inability or failure to do so adequately could have a material adverse effect on their business, financial condition, results of operations and prospects.

NEE's and FPL's business, financial condition, results of operations and prospects could be materially adversely affected if they are unable to recover in a timely manner any significant amount of costs, a return on certain assets or an appropriate return on capital through base rates, cost recovery clauses, other regulatory mechanisms or otherwise.

FPL is a regulated entity subject to the jurisdiction of the FPSC over a wide range of business activities, including, among other items, the retail rates charged to its customers through base rates and cost recovery clauses, the terms and conditions of its services, procurement of electricity for its customers, issuance of securities, and aspects of the siting and operation of its generating plants and transmission and distribution systems for the sale of electric energy. The FPSC has the authority to disallow recovery by FPL of costs that it considers excessive or imprudently incurred and to determine the level of return that FPL is permitted to earn on its investments. The regulatory process, which may be adversely affected by the political, regulatory and economic environment in Florida and elsewhere, limits FPL's ability to increase earnings and does not provide any assurance as to achievement of authorized or other earnings levels. NEE's and FPL's business, financial condition, results of operations and prospects could be materially adversely affected if any material amount of costs, a return on certain assets or an appropriate return on capital cannot be recovered through base rates, cost recovery clauses, other regulatory mechanisms or otherwise. Lone Star, an indirect wholly-owned subsidiary of NEE that is a regulated electric transmission utility subject to the jurisdiction of the PUCT, is subject to similar risks.

Regulatory decisions that are important to NEE and FPL may be materially adversely affected by political, regulatory and economic factors.

The local and national political, regulatory and economic environment has had, and may in the future have, an adverse effect on FPSC decisions with negative consequences for FPL. These decisions may require, for example, FPL to cancel or delay planned development activities, to reduce or delay other planned capital expenditures or to pay for investments or otherwise incur costs that it may not be able to recover through rates, each of which could have a material adverse effect on the business, financial condition, results of operations and prospects of NEE and FPL. Lone Star is subject to similar risks.

FPL's use of derivative instruments could be subject to prudence challenges and, if found imprudent, could result in disallowances of cost recovery for such use by the FPSC.

In the event that the FPSC engages in a prudence review of FPL's use of derivative instruments and finds such use to be imprudent, the FPSC could deny cost recovery for such use by FPL. Such an outcome could have a material adverse effect on FPL's business, financial condition, results of operations and prospects.

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Any ~~reduction~~reductions to, or the elimination of, ~~existing~~governmental ~~government~~incentives that support ~~policies~~renewable energy, including, but not limited to, tax incentives, RPS or feed-in tariffs, ~~and~~or ~~ultimately~~the ~~any~~imposition ~~failure~~of toadditional ~~renew~~taxes or ~~increase~~other ~~these~~assessments ~~existing~~on ~~support~~renewable ~~policies~~energy, could result in, ~~less~~among ~~demand~~other items, the lack of a satisfactory market for ~~generation~~the ~~from~~development of new renewable energy projects, NEER abandoning the development of renewable energy projects, a loss of NEER's investments in renewable energy projects and reduced project returns, any of which could have a material adverse effect on NEE's business, financial condition, results of operations and prospects.

NEER depends heavily on government policies that support renewable energy and enhance the economic feasibility of developing and operating wind and solar energy projects in regions in which NEER operates or plans to develop and operate renewable energy facilities. The federal government, a majority of the 50 U.S. states and portions of Canada and Spain provide incentives, such as tax incentives, RPS or feed-in tariffs, that support the sale of energy from renewable energy facilities ~~owned by NEER~~, such as wind and solar energy facilities. ~~The~~ ~~applicable~~As ~~legislation~~a ~~often~~result ~~grants~~of ~~the~~budgetary ~~relevant~~constraints, ~~state~~political ~~public~~factors ~~utility~~or ~~commission~~otherwise, ~~the~~governments ~~ability~~from time to ~~reduce~~time ~~electric~~may ~~supply~~review ~~companies'~~their ~~obligations~~policies tothat ~~meet~~support renewable energy ~~requirements~~and inconsider ~~specified~~actions ~~circumstances~~to make the policies less conducive to the development and operation of renewable energy facilities. Any ~~changes~~reductions to, or the elimination of, governmental incentives that support renewable energy, such as those reductions that have been enacted in Spain and are applicable to the Spain solar projects in that country, or the imposition of additional taxes or other assessments on renewable energy, could result in, ~~less~~among ~~demand~~other items, the lack of a satisfactory market for ~~generation~~the ~~from~~development ~~NEE's~~of ~~wind~~new ~~and~~renewable ~~solar~~energy projects, NEER abandoning the development of renewable energy projects, a loss of NEER's investments in the projects and reduced project returns, any of which could have a material adverse effect on ~~NEER~~NEE's business, financial condition, results of operations and prospects.

NEER also depends heavily on investment cost recovery mechanisms currently available through the American Recovery and Reinvestment Act of 2009 (Recovery Act). The Recovery Act includes, among other things, provisions that allow companies building wind and solar energy facilities the option to choose between investment cost recovery mechanisms that make the development of such facilities economically attractive. Any changes to the Recovery Act that eliminate or reduce support for renewable generation projects could impede NEER's ability to economically develop wind and solar energy projects in the future and could have a material adverse effect on NEER's ability to develop renewable energy projects in the future.

If investments in renewable energy and associated projects are perceived less positively by legislators, regulators or the public, this could result in the non-renewal or elimination of beneficial tax policies, among other policies, that benefit NEER. Any such legislative changes could impede NEER's ability to economically develop wind and solar energy projects in the future and could have a material adverse effect on NEE's business, financial condition, results of operations and prospects.

NEE's and FPL's business, financial condition, results of operations and prospects could be materially adversely affected as a result of new or revised laws, regulations or interpretations or other regulatory initiatives.

NEE's and FPL's business is influenced by various legislative and regulatory initiatives, including, but not limited to, initiatives regarding deregulation or restructuring of the energy industry, regulation of the commodities trading and derivatives markets, and environmental regulation, such as regulation of air emissions, regulation of water consumption and water discharges, and regulation of gas and oil infrastructure operations, as well as associated environmental permitting. Changes in the nature of the regulation of NEE's and FPL's business could have a material adverse effect on NEE's and FPL's results of operations. NEE and FPL are unable to predict future legislative or regulatory changes, initiatives or interpretations, although any such changes, initiatives or interpretations may increase costs and competitive pressures on NEE and FPL, which could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

FPL has limited competition in the Florida market for retail electricity customers. Any changes in Florida law or regulation which introduce competition in the Florida retail electricity market could have a material adverse effect on FPL's business, financial condition, results of operations and prospects. There can be no assurance that FPL will be able to respond adequately to such regulatory changes, which could have a material adverse effect on FPL's business, financial condition, results of operations and prospects.

NEER is subject to FERC rules related to transmission that are designed to facilitate competition in the wholesale market on practically a nationwide basis by providing greater certainty, flexibility and more choices to wholesale power customers. NEE cannot predict the impact of changing FERC rules or the effect of changes in levels of wholesale supply and demand, which are typically driven by factors beyond NEE's control. There can be no assurance that NEER will be able to respond adequately or sufficiently quickly to such rules and developments, or to any other changes that reverse or restrict the competitive restructuring of the energy industry in those jurisdictions in which such restructuring has occurred. Any of these events could have a material adverse effect on NEE's business, financial condition, results of operations and prospects.

NEE's and FPL's business, financial condition, results of operations and prospects could be materially adversely affected if the rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) broaden the scope of its provisions regarding the regulation of OTC financial derivatives and make them applicable to NEE and FPL.

The Dodd-Frank Act, enacted into law in July 2010, among other things, provides for the regulation of the OTC derivatives market. The Dodd-Frank Act includes provisions that will require certain OTC derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. While the legislation is broad and detailed, there are still substantial portions of the legislation that either require implementing rules to be adopted by federal governmental agencies including, but not limited to, the SEC and the CFTC or otherwise require further interpretation guidance from federal government agencies.

NEE and FPL cannot predict the final rules that will be adopted to implement the OTC derivatives market provisions of the Dodd-Frank Act (or the ultimate interpretation of those rules). Those rules could negatively affect NEE's and FPL's ability to hedge their commodity and interest rate risks, which could have a material adverse effect on NEE's and FPL's results of operations. NEE is reviewing the scope of these rules and is evaluating whether it may have portions of its business that may be required to register as swap dealers or major swap participants and submit to extensive regulation if it wishes to continue certain aspects of its derivative activities. The rules could also cause NEER to restructure part of its energy marketing and trading operations or to discontinue certain portions of its business. In addition, if the rules require NEE and FPL to post significant amounts of cash collateral with respect to swap transactions, NEE's and FPL's liquidity could be materially adversely affected, and their ability to enter into OTC derivatives to hedge commodity and interest rate risks could be significantly limited. Reporting and compliance requirements of

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Frank Act. Those rules could negatively affect NEE's and FPL's ability to hedge their commodity and interest rate risks, which could have a material adverse effect on NEE's and FPL's results of operations. NEE or FPL may have portions of their business that may be required to register as swap dealers or major swap participants and submit to extensive regulation if they wish to continue certain aspects of their derivative activities. The rules could also cause NEER to restructure part of its energy marketing and trading operations or to discontinue certain portions of its business. In addition, if the rules require NEE and FPL to post significant amounts of cash collateral with respect to swap transactions, NEE's and FPL's liquidity could be materially adversely affected, and their ability to enter into OTC derivatives to hedge commodity and interest rate risks could be significantly limited. Reporting and compliance requirements of the rules also could significantly increase operating costs and expose NEE and FPL to penalties for non-compliance. The Dodd-Frank Act or other initiatives also could impede the efficient operation of the commodities trading and derivatives markets, which could also materially adversely affect NEE's and FPL's business, financial condition, results of operations and prospects.

NEE and FPL are subject to numerous environmental laws, regulations and ~~regulations~~other standards that ~~require~~may result in capital expenditures, ~~increase~~increased ~~their~~operating ~~cost~~costs ~~of operations~~ and ~~may~~various ~~expose them to~~ liabilities.

NEE and FPL are subject to domestic and foreign environmental laws and regulations, including, but not limited to, extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality and usage, climate change, emissions of greenhouse gases, including, but not limited to, CO₂, waste management, hazardous wastes, marine, avian and other wildlife mortality and habitat protection, historical artifact preservation, natural resources, health (including, but not limited to, electric and magnetic fields from power lines and substations), safety and RPS that could, among other things, prevent or delay the development of power generation, power or natural gas transmission, or other infrastructure projects, restrict the output of some existing facilities, limit the use of some fuels required for the production of electricity, require additional pollution control equipment, and otherwise increase costs, increase capital expenditures and limit or eliminate certain operations.

There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations, and those costs could be even more significant in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application of existing environmental regulations. For example, among other potential or pending changes, the use of hydraulic fracturing or similar technologies to drill for natural gas and related compounds used by NEE's gas infrastructure business is currently being debated for potential regulation at the state and federal levels.

Violations of current or future laws, rules, ~~and~~ regulations or other standards could expose NEE and FPL to regulatory and legal proceedings, disputes with, and legal challenges by, third parties, and potentially significant civil fines, criminal penalties and other sanctions. Proceedings could include, for example, litigation regarding property damage, personal injury, common law nuisance and enforcement by citizens or governmental authorities of environmental requirements such as air, water and soil quality standards.

NEE's and FPL's business could be negatively affected by federal or state laws or regulations mandating new or additional limits on the production of greenhouse gas emissions.

Federal or state laws or regulations may be adopted that would impose new or additional limits on the emissions of greenhouse gases, including, but not limited to, CO2 and methane, from electric generating units using fossil fuels like coal and natural gas. The potential effects of such greenhouse gas emission limits on NEE's and FPL's electric generating units are subject to significant uncertainties based on, among other things, the timing of the implementation of any new requirements, the required levels of emission reductions, the nature of any market-based or tax-based mechanisms adopted to facilitate reductions, the relative availability of greenhouse gas emission reduction offsets, the development of cost-effective, commercial-scale carbon capture and storage technology and supporting regulations and liability mitigation measures, and the range of available compliance alternatives.

While NEE's and FPL's electric generating units emit greenhouse gases at a lower rate of emissions than most of the U.S. electric generation sector, the results of operations of NEE and FPL could be adversely affected to the extent that new federal or state legislation or regulators impose any new greenhouse gas emission limits. Any future limits on greenhouse gas emissions could:


•	create substantial additional costs in the form of taxes or emission allowances;


•	make some of NEE's and FPL's electric generating units uneconomical to operate in the long term;


•	require significant capital investment in carbon capture and storage technology, fuel switching, or the replacement of high-emitting generation facilities with lower-emitting generation facilities; or


•	affect the availability or cost of fossil fuels.

There can be no assurance that NEE or FPL would be able to completely recover any such costs or investments, which could have a material adverse effect on their business, financial condition, results of operations and prospects.

Extensive federal regulation of the operations of NEE and FPL exposes NEE and FPL to significant and increasing compliance costs and may also expose them to substantial monetary penalties and other sanctions for compliance failures.

NEE and FPL are subject to extensive federal regulation, which generally imposes significant and increasing compliance costs on ~~their~~NEE's and FPL's operations. Additionally, any actual or alleged compliance failures could result in significant costs and other potentially adverse effects of regulatory investigations, proceedings, settlements, decisions and claims, including, among other items, potentially significant monetary penalties. As an example, under the Energy Policy Act of 2005, NEE and FPL, as owners and operators of bulk power transmission systems and/or electric generation facilities, are subject to mandatory reliability standards. Compliance with these mandatory reliability standards may subject NEE and FPL to higher operating costs and may result in increased capital expenditures. If FPL or NEE is found not to be in compliance with these standards, it may incur substantial monetary penalties and other sanctions. Both the costs of regulatory compliance and the costs that may be imposed as a result of any actual or alleged compliance failures could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

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with these mandatory reliability standards may subject NEE and FPL to higher operating costs and may result in increased capital expenditures. If FPL or NEE is found not to be in compliance with these standards, it may incur substantial monetary penalties and other sanctions. Both the costs of regulatory compliance and the costs that may be imposed as a result of any actual or alleged compliance failures could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could adversely affect NEE's and FPL's business, financial condition, results of operations and prospects.

NEE's and FPL's provision for income taxes and reporting of tax-related assets and liabilities require significant judgments and the use of estimates. Amounts of tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions and tax credits, including, but not limited to, estimates for potential adverse outcomes regarding tax positions that have been taken and the ability to utilize tax benefit carryforwards, such as net operating loss and tax credit carryforwards. Actual income taxes could vary significantly from estimated amounts due to the future impacts of, among other things, changes in tax laws, regulations and interpretations, the financial condition and results of operations of NEE and FPL, and the resolution of audit issues raised by taxing authorities. Ultimate resolution of income tax matters may result in material adjustments to tax-related assets and liabilities, which could negatively affect NEE's and FPL's business, financial condition, results of operations and prospects.

NEE's and FPL's business, financial condition, results of operations and prospects may be materially adversely affected due to adverse results of litigation.

NEE's and FPL's business, financial condition, results of operations and prospects may be materially affected by adverse results of litigation. Unfavorable resolution of legal proceedings in which NEE is involved or other future legal proceedings, including, but not limited to, class action lawsuits, may have a material adverse effect on the business, financial condition, results of operations and prospects of NEE and FPL.

Operational Risks

NEE's and FPL's business, financial condition, results of operations and prospects could suffer if NEE and FPL do not proceed with projects under development or are unable to complete the construction of, or capital improvements to, electric generation, transmission and distribution facilities, gas infrastructure facilities or other facilities on schedule or within budget.

NEE's and FPL's ability to complete construction of, and capital improvement projects for, their electric generation, transmission and distribution facilities, gas infrastructure facilities and other facilities on schedule and within budget may be adversely affected by escalating costs for materials and labor and regulatory compliance, inability to obtain or renew necessary licenses, rights-of-way, permits or other approvals on acceptable terms or on schedule, disputes involving contractors, labor organizations, land owners, governmental entities, environmental groups, Native American and aboriginal groups, and other third parties, negative publicity, transmission interconnection issues and other factors. If any development project or construction or capital improvement project is not completed, is delayed or is subject to cost overruns, certain associated costs may not be approved for recovery or recoverable through regulatory mechanisms that may otherwise be available, and NEE and FPL could become obligated to make delay or termination payments or become obligated for other damages under contracts, could experience the loss of tax credits or tax incentives, or delayed or diminished returns and could be required to write-off all or a portion of their ~~investments~~investment in the project. Any of these events could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

NEE and FPL may face risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede their development and operating activities.

NEE and FPL own, develop, construct, manage and operate electric-generating and transmission facilities. A key component of NEE's and FPL's growth is their ability to construct and operate generation and transmission facilities to meet customer needs. As part of these operations, NEE and FPL must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should NEE or FPL be unsuccessful in obtaining necessary licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on NEE or FPL, NEE's and FPL's business, financial condition, results of operations and prospects could be materially adversely affected. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results.

The operation and maintenance of NEE's and FPL's electric generation, transmission and distribution facilities, gas infrastructure facilities and other facilities are subject to many operational risks, the consequences of which could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

NEE's and FPL's electric generation, transmission and distribution facilities, gas infrastructure facilities and other facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property and personal injury damage, a failure to perform under applicable power sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements, and replacement equipment costs or an obligation to purchase or generate replacement power at potentially higher prices.

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a failure to perform under applicable power sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements, and replacement equipment costs or an obligation to purchase or generate replacement power at potentially higher prices.

Uncertainties and risks inherent in operating and maintaining NEE's and FPL's facilities include, but are not limited to:


•	risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned;


•	failures in the availability, acquisition or transportation of fuel or other necessary supplies;


•	the impact of unusual or adverse weather conditions, including, but not limited to, natural disasters such as hurricanes, floods, earthquakes and droughts;


•	performance below expected or contracted levels of output or efficiency;


•	breakdown or failure, including, but not limited to, explosions, fires or other major events, of equipment, transmission and distribution lines or pipelines;


•	availability of replacement equipment;


•	risks of property damage or human injury from energized equipment, hazardous substances or explosions, fires or other events;


•	availability of adequate water resources and ability to satisfy water intake and discharge requirements;


•	inability to manage properly or mitigate known equipment defects in NEE's and FPL's facilities;


•	use of new or unproven technology;


•	risks associated with dependence on a specific fuel source, such as commodity price risk and lack of available alternative fuel sources;


•	increased competition due to, among other factors, new facilities, excess supply and shifting demand; and


•	insufficient insurance, warranties or performance guarantees to cover any or all lost revenues or increased expenses from the foregoing.

NEE's and FPL's business, financial condition, results of operations and prospects may be negatively affected by a lack of growth or slower growth in the number of customers or in customer usage.

Growth in customer accounts and growth of customer usage each directly influence the demand for electricity and the need for additional power generation and power delivery facilities. Customer growth and customer usage are affected by a number of factors outside the control of NEE and FPL, such as mandated energy efficiency measures, demand side management goals, and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. A lack of growth, or a decline, in the number of customers or in customer demand for electricity may cause NEE and FPL to fail to fully realize the anticipated benefits from significant investments and expenditures and could have a material adverse effect on NEE's and FPL's own growth, business, financial condition, results of operations and prospects.

NEE's and FPL's business, financial condition, results of operations and prospects can be materially adversely affected by weather conditions, including, but not limited to, the impact of severe weather.

Weather conditions directly influence the demand for electricity and natural gas and other fuels and affect the price of energy and energy-related commodities. In addition, severe weather, such as hurricanes, floods and earthquakes, can be destructive and cause power outages and property damage, reduce revenue, affect fuel supply, and require NEE and FPL to incur additional costs, for example, to restore service and repair damaged facilities, obtain replacement power and access available financing sources. Furthermore, NEE's and FPL's physical plant could be placed at greater risk of damage should changes in global climate produce unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, particularly relevant to FPL, a change in sea level. FPL operates in the east and lower west coasts of Florida, an area that historically has been prone to severe weather events, such as hurricanes. A disruption or failure of electric generation, transmission or distribution systems or natural gas production, transmission, storage or distribution systems in the event of a hurricane, tornado or other severe weather event, or otherwise, could prevent NEE and FPL from operating their business in the normal course and could result in any of the adverse consequences described above. Any of the foregoing could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

At FPL and other businesses of NEE where cost recovery is available, recovery of costs to restore service and repair damaged facilities is or may be subject to regulatory approval, and any determination by the regulator not to permit timely and full recovery of the costs incurred could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

Changes in weather can also affect the production of electricity at power generating facilities, including, but not limited to, NEER's wind, solar and hydro-powered facilities. For example, the level of wind resource affects the revenue produced by wind generating facilities. Because the levels of wind, solar and hydro resources are variable and difficult to predict, NEER's results of operations for individual wind, solar and hydro facilities specifically, and NEE's results of operations generally, may vary significantly from period to period, depending on the level of available resources. To the extent that resources are not available at planned levels, the financial results from these facilities may be less than expected.

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Threats of terrorism and catastrophic events that could result from terrorism, cyber attacks, or individuals and/or groups attempting to disrupt NEE's and FPL's business, or the businesses of third parties, may materially adversely affect NEE's and FPL's business, financial condition, results of operations and prospects.

NEE and FPL are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups. NEE's and FPL's generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems could be direct targets of, or be indirectly affected by, such activities.

Terrorist acts or other similar events affecting NEE's and FPL's systems and facilities, or those of third parties on which NEE and FPL rely, could harm NEE's and FPL's business, for example, by limiting their ability to generate, purchase or transmit power, by limiting their ability to bill customers and collect and process payments, and by delaying their development and construction of new generating facilities or capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues, significant additional costs (for example, to repair assets, implement additional security requirements or maintain or acquire insurance), and reputational damage, could adversely affect NEE's and FPL's operations (for example, by contributing to disruption of supplies and markets for natural gas, oil and other fuels), and could impair NEE's and FPL's ability to raise capital (for example, by contributing to financial instability and lower economic activity).

The ability of NEE and FPL to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. NEE's and FPL's insurance coverage does not provide protection against all significant losses.

Insurance coverage may not continue to be available or may not be available at rates or on terms similar to those presently available to NEE and FPL. The ability of NEE and FPL to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. If insurance coverage is not available or obtainable on acceptable terms, NEE or FPL may be required to pay costs associated with adverse future events. NEE and FPL generally are not fully insured against all significant losses. For example, FPL is not fully insured against hurricane-related losses, but would instead seek recovery of such uninsured losses from customers subject to approval by the FPSC, to the extent losses exceed restricted funds set aside to cover the cost of storm damage. A loss for which NEE or FPL is not fully insured could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

If supply costs necessary to provide NEER's full energy and capacity requirement services are not favorable, operating costs could increase and adversely affect NEE's business, financial condition, results of operations and prospects.

NEER provides full energy and capacity requirements services primarily to distribution utilities, which include load-following services and various ancillary services to satisfy all or a portion of such utilities' power supply obligations to their customers. The supply costs for these transactions may be affected by a number of factors, including, but not limited to, events that may occur after such utilities have committed to supply power, such as weather conditions, fluctuating prices for energy and ancillary services, and the ability of the distribution utilities' customers to elect to receive service from competing suppliers. NEER may not be able to recover all of its increased supply costs, which could have a material adverse effect on NEE's business, financial condition, results of operations and prospects.

Due to the potential for significant volatility in market prices for fuel, electricity and renewable and other energy commodities, NEER's inability or failure to hedge effectively its assets or positions against changes in commodity prices, volumes, interest rates, counterparty credit risk or other risk measures could significantly impair NEE's results of operations.

There can be significant volatility in market prices for fuel, electricity and renewable and other energy commodities. NEE's inability to manage properly or hedge the commodity risks within its portfolios, based on factors both from within or wholly or partially outside of NEE's control, may materially adversely affect NEE's business, financial condition, results of operations and prospects.

Sales of power on the spot market or on a short-term contractual basis may cause NEE's results of operations to be volatile.

A portion of NEER's power generation facilities operate wholly or partially without long-term power purchase agreements. Power from these facilities is sold on the spot market or on a short-term contractual basis. Spot market sales are subject to market volatility, and the revenue generated from these sales is subject to fluctuation that may cause NEE's results of operations to be volatile. NEER and NEE may not be able to manage volatility adequately, which could then have a material adverse effect on NEE's business, financial condition, results of operations and prospects.

Reductions in the liquidity of energy markets may restrict the ability of NEE to manage its operational risks, which, in turn, could negatively affect NEE's results of operations.

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NEE is an active participant in energy markets. The liquidity of regional energy markets is an important factor in the company's ability to manage risks in these operations. Over the past several years, other market participants have ceased or significantly reduced their activities in energy markets as a result of several factors, including, but not limited to, government investigations, changes in market design and deteriorating credit quality. Liquidity in the energy markets can be adversely affected by price volatility, restrictions on the availability of credit and other factors, and any reduction in the liquidity of energy markets could have a material adverse effect on NEE's business, financial condition, results of operations and prospects.

If price movements significantly or persistently deviate from historical behavior, NEE's and FPL's hedging and trading procedures and associated risk management tools may not protect against significant losses.

NEE and FPL have hedging and trading procedures and associated risk management tools, such as separate but complementary financial, credit, operational, compliance and legal reporting systems, internal controls, management review processes and other mechanisms. NEE and FPL are unable to assure that such procedures and tools will be effective against all potential risks. Additionally, risk management tools and metrics such as daily value at risk, earnings at risk, stop loss limits and liquidity guidelines are based on historical price movements. Due to the inherent uncertainty involved in price movements and potential deviation from historical pricing behavior, NEE and FPL are unable to assure that their risk management tools and metrics will be effective to protect against adverse effects on their business, financial condition, results of operations and prospects. Such adverse effects could be material.

If power transmission or natural gas, nuclear fuel or other commodity transportation facilities are unavailable or disrupted, FPL's and NEER's ability to sell and deliver power or natural gas may be limited.

FPL and NEER depend upon power transmission and natural gas, nuclear fuel and other commodity transportation facilities, many of which they do not own. Occurrences affecting the operation of these facilities that may or may not be beyond FPL's and NEER's control (such as severe weather or a generator or transmission facility outage, pipeline rupture, or sudden and significant increase or decrease in wind generation) may limit or halt the ability of FPL and NEER to sell and deliver power and natural gas, or to purchase necessary fuels and other commodities, which could materially adversely impact NEE's and FPL's business, financial condition, results of operations and prospects.

NEE and FPL are subject to credit and performance risk from customers, hedging counterparties and vendors.

NEE and FPL are exposed to risks associated with the creditworthiness and performance of their customers, hedging counterparties and vendors under contracts for the supply of equipment, materials, fuel and other goods and services required for their business operations and for the construction and operation of, and for capital improvements to, their facilities. Adverse conditions in the energy industry or the general economy, as well as circumstances of individual customers, hedging counterparties and vendors, may affect the ability of some customers, hedging counterparties and vendors to perform as required under their contracts with NEE and FPL.

If any hedging, vending or other counterparty fails to fulfill its contractual obligations, NEE and FPL may need to make arrangements with other counterparties or vendors, which could result in financial losses, higher costs, untimely completion of power generation facilities and other projects, and/or a disruption of their operations. If a defaulting counterparty is in poor financial condition, NEE and FPL may not be able to recover damages for any contract breach.

NEE and FPL could recognize financial losses or a reduction in operating cash flows if a counterparty fails to perform or make payments in accordance with the terms of derivative contracts or if NEE or FPL is required to post margin cash collateral under derivative contracts.

NEE and FPL use derivative instruments, such as swaps, options, futures and forwards, some of which are traded in the OTC markets or on exchanges, to manage their commodity and financial market risks, and for NEE to engage in trading and marketing activities. Any failures by their counterparties to perform or make payments in accordance with the terms of those transactions could have a material adverse effect on NEE's or FPL's business, financial condition, results of operations and prospects. Similarly, any requirement for FPL or NEE to post margin cash collateral under its derivative contracts could have a material adverse effect on its business, financial condition, results of operations and prospects.

NEE and FPL are highly dependent on sensitive and complex information technology systems, and any failure or breach of those systems could have a material adverse effect on their business, financial condition, results of operations and prospects.

NEE and FPL operate in a highly regulated industry that requires the continuous functioning of sophisticated information technology systems and network infrastructure. Despite NEE's and FPL's implementation of security measures, all of their technology systems are vulnerable to disability, failures or unauthorized access due to such activities. If NEE's or FPL's information technology systems were to fail or be breached, and NEE or FPL was unable to recover in a timely way, NEE and FPL would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised.

NEE's and FPL's business is highly dependent on their ability to process and monitor, on a daily basis, a very large number of

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NEE's and FPL's business is highly dependent on their ability to process and monitor, on a daily basis, a very large number of transactions, many of which are highly complex and cross numerous and diverse markets. Due to the size, scope and geographical reach of NEE's and FPL's business, and due to the complexity of the process of power generation, transmission and distribution, the development and maintenance of information technology systems to keep track of and process this information is both critical and extremely challenging. NEE's and FPL's operating systems and facilities may fail to operate properly or become disabled as a result of events that are either within, or wholly or partially outside, their control, such as operator error, severe weather or terrorist activities. Any such failure or disabling event could adversely affect NEE's and FPL's ability to process transactions and provide services, and their financial results and liquidity.

NEE and FPL add, modify and replace information systems on a regular basis. Modifying existing information systems or implementing new or replacement information systems is costly and involves risks, including, but not limited to, integrating the modified, new or replacement system with existing systems and processes, implementing associated changes in accounting procedures and controls, and ensuring that data conversion is accurate and consistent. Any disruptions or deficiencies in existing information systems, or disruptions, delays or deficiencies in the modification or implementation of new information systems, could result in increased costs, the inability to track or collect revenues, the diversion of management's and employees' attention and resources, and could negatively impact the effectiveness of the companies' control environment, and/or the companies' ability to timely file required regulatory reports.

NEE and FPL also face the risks of operational failure or capacity constraints of third parties, including, but not limited to, those who provide power transmission and natural gas transportation services.

NEE's and FPL's retail businesses are subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to their reputation and/or the results of operations of the retail business.

NEE's and FPL's retail businesses require access to sensitive customer data in the ordinary course of business. NEE's and FPL's retail businesses may also need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center services, to the retail businesses. If a significant breach occurred, the reputation of NEE and FPL could be adversely affected, customer confidence could be diminished, or customer information could be subject to identity theft. NEE and FPL would be subject to costs associated with the breach and/or NEE and FPL could be subject to fines and legal claims, any of which may have a material adverse effect on the business, financial condition, results of operations and prospects of NEE and FPL.

NEE and FPL could recognize financial losses as a result of volatility in the market values of derivative instruments and limited liquidity in OTC markets.

NEE and FPL execute transactions in derivative instruments on either recognized exchanges or via the OTC markets, depending on management's assessment of the most favorable credit and market execution factors. Transactions executed in OTC markets have the potential for greater volatility and less liquidity than transactions on recognized exchanges. As a result, NEE and FPL may not be able to execute desired OTC transactions due to such heightened volatility and limited liquidity.

In the absence of actively quoted market prices and pricing information from external sources, the valuation of derivative instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these derivative instruments and have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

NEE and FPL may be adversely affected by negative publicity.

From time to time, political and public sentiment may result in a significant amount of adverse press coverage and other adverse public statements affecting NEE and FPL. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceeding, can divert the time and effort of senior management from NEE's and FPL's business.

Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of NEE and FPL, on the morale and performance of their employees and on their relationships with their respective regulators. It may also have a negative impact on their ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

NEE's and FPL's business, financial condition, results of operations and prospects may be materially adversely affected if FPL is unable to maintain, negotiate or renegotiate franchise agreements on acceptable terms with municipalities and counties in Florida.

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FPL must negotiate franchise agreements with municipalities and counties in Florida to provide electric services within such municipalities and counties, and electricity sales generated pursuant to these agreements represent a very substantial portion of FPL's revenues. If FPL is unable to maintain, negotiate or renegotiate such franchise agreements on acceptable terms, it could contribute to lower earnings and FPL may not fully realize the anticipated benefits from significant investments and expenditures, which could materially adversely affect NEE's and FPL's business, financial condition, results of operations and prospects.

Increasing costs associated with health care plans may materially adversely affect NEE's and FPL's results of operations.

The costs of providing health care benefits to employees and retirees have increased substantially in recent years. NEE and FPL anticipate that their employee benefit costs, including, but not limited to, costs related to health care plans for employees and former employees, will continue to rise. The increasing costs and funding requirements associated with NEE's and FPL's health care plans may materially adversely affect NEE's and FPL's business, financial condition, results of operations and prospects.

NEE's and FPL's business, financial condition, results of operations and prospects could be negatively affected by the lack of a qualified workforce or the loss or retirement of key employees.

NEE and FPL may not be able to service customers, grow their business or generally meet their other business plan goals effectively and profitably if they do not attract and retain a qualified workforce. Additionally, the loss or retirement of key executives and other employees may materially adversely affect service and productivity and contribute to higher training and safety costs.

Over the next several years, a significant portion of NEE's and FPL's workforce, including, but not limited to, many workers with specialized skills maintaining and servicing the nuclear generation facilities and electrical infrastructure, will be eligible to retire. Such highly skilled individuals may not be able to be replaced quickly due to the technically complex work they perform. If a significant amount of such workers retire and are not replaced, the subsequent loss in productivity and increased recruiting and training costs could result in a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

NEE's and FPL's business, financial condition, results of operations and prospects could be materially adversely affected by work strikes or stoppages and increasing personnel costs.

Employee strikes or work stoppages could disrupt operations and lead to a loss of revenue and customers. Personnel costs may also increase due to inflationary or competitive pressures on payroll and benefits costs and revised terms of collective bargaining agreements with union employees. These consequences could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

NEE's ability to successfully identify, complete and integrate acquisitions is subject to significant risks, including, but not limited to, the effect of increased competition for acquisitions resulting from the consolidation of the power industry.

NEE is likely to encounter significant competition for acquisition opportunities that may become available as a result of the consolidation of the power industry in general. In addition, NEE may be unable to identify attractive acquisition opportunities at favorable prices and to complete and integrate them successfully and in a timely manner.

Nuclear Generation Risks

The construction, operation and maintenance of NEE's and FPL's nuclear generation facilities involve environmental, health and financial risks that could result in fines or the closure of the facilities and in increased costs and capital expenditures.

NEE's and FPL's nuclear generation facilities are subject to environmental, health and financial risks, including, but not limited to, those relating to site storage of spent nuclear fuel, the disposition of spent nuclear fuel, leakage and emissions of tritium and other radioactive elements in the event of a nuclear accident or otherwise, the threat of a terrorist attack and other potential liabilities arising out of the ownership or operation of the facilities. NEE and FPL maintain decommissioning funds and external insurance coverage which are intended to reduce the financial exposure to some of these risks; however, the cost of decommissioning nuclear generation facilities could exceed the amount available in NEE's and FPL's decommissioning funds, and the exposure to liability and property damages could exceed the amount of insurance coverage. If NEE or FPL is unable to recover the additional costs incurred through insurance or, in the case of FPL, through regulatory mechanisms, their business, financial condition, results of operations and prospects could be materially adversely affected.

In the event of an incident at any nuclear generation facility in the U.S. or at certain nuclear generation facilities in Europe, NEE and FPL could be assessed significant retrospective assessments and/or retrospective insurance premiums as a result of their participation in a secondary financial protection system and nuclear insurance mutual companies.

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Liability for accidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with this Act, NEE maintains $375 million of private liability insurance per site, which is the maximum obtainable, and participates in a secondary financial protection system, which provides up to $12.2 billion of liability insurance coverage per incident at any nuclear reactor in the U.S. Under the secondary financial protection system, NEE is subject to retrospective assessments and/or retrospective insurance premiums of up to $940 million ($470 million for FPL), plus any applicable taxes, per incident at any nuclear reactor in the U.S. or at certain nuclear generation facilities in Europe, regardless of fault or proximity to the incident, payable at a rate not to exceed $140 million ($70 million for FPL) per incident per year. Such assessments, if levied, could materially adversely affect NEE's and FPL's business, financial condition, results of operations and prospects.

NRC orders or new regulations related to increased security measures and any future safety requirements promulgated by the NRC could require NEE and FPL to incur substantial operating and capital expenditures at their nuclear generation facilities.

The NRC has broad authority to impose licensing and safety-related requirements for the operation and maintenance of nuclear generation facilities, the addition of capacity at existing nuclear generation facilities and the construction of nuclear generation facilities, and these requirements are subject to change. In the event of non-compliance, the NRC has the authority to impose fines or shut down a nuclear generation facility, or to take both of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved. Any of the foregoing events could require NEE and FPL to incur increased costs and capital expenditures, and could reduce revenues.

Any serious nuclear incident occurring at a NEE or FPL plant could result in substantial remediation costs and other expenses. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear generation facility. An incident at a nuclear facility anywhere in the world also could cause the NRC to impose additional conditions or other requirements on the industry, which could increase costs, reduce revenues and result in additional capital expenditures.

The inability to operate any of NEER's or FPL's nuclear generation units through the end of their respective operating licenses could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

The operating licenses for NEE's and FPL's nuclear generation facilities extend through at least 2030. If the facilities cannot be operated for any reason through the life of those operating licenses, NEE or FPL may be required to increase depreciation rates, incur impairment charges and accelerate future decommissioning expenditures, any of which could materially adversely affect their business, financial condition, results of operations and prospects.

Various hazards posed to nuclear generation facilities, along with increased public attention to and awareness of such hazards, could result in increased nuclear licensing or compliance costs which are difficult or impossible to predict and could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

The threat of terrorist activity, as well as recent international events implicating the safety of nuclear facilities, could result in more stringent or complex measures to keep facilities safe from a variety of hazards, including, but not limited to, natural disasters such as earthquakes and tsunamis, as well as terrorist or other criminal threats. This increased focus on safety could result in higher compliance costs which, at present, cannot be assessed with any measure of certainty and which could have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

NEE's and FPL's nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, and for other purposes. If planned outages last longer than anticipated or if there are unplanned outages, NEE's and FPL's results of operations and financial condition could be materially adversely affected.

NEE's and FPL's nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, including, but not limited to, inspections, repairs and certain other modifications. In addition, outages may be scheduled, often in connection with a refueling outage, to replace equipment, to increase the generation capacity at a particular nuclear unit, or for other purposes, and those planned activities increase the time the unit is not in operation. In the event that a scheduled outage lasts longer than anticipated or in the event of an unplanned outage due to, for example, equipment failure, such outages could materially adversely affect NEE's or FPL's business, financial condition, results of operations and prospects.

Liquidity, Capital Requirements and Common Stock Risks

Disruptions, uncertainty or volatility in the credit and capital markets may negatively affect NEE's and FPL's ability to fund their liquidity and capital needs and to meet their growth objectives, and can also adversely affect the results of operations and financial condition of NEE and FPL.

NEE and FPL rely on access to capital and credit markets as significant sources of liquidity for capital requirements and other operations requirements that are not satisfied by operating cash flows. Disruptions, uncertainty or volatility in those capital and credit markets, including, but not limited to, the conditions of the most recent financial crises in the U.S. and abroad, could increase NEE's and FPL's cost of capital. If NEE or FPL is unable to access regularly the capital and credit markets on terms that are reasonable, it may have to delay raising capital, issue shorter-term securities and incur an unfavorable cost of capital, which, in turn, could adversely affect its ability to grow its business, could contribute to lower earnings and reduced financial flexibility, and could have a material adverse effect on its business, financial condition, results of operations and prospects.

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Although NEE's competitive energy subsidiaries have used non-recourse or limited-recourse, project-specific financing in the past, market conditions and other factors could adversely affect the future availability of such financing. The inability of NEE's subsidiaries to access the capital and credit markets to provide project-specific financing for electric-generating and other energy facilities on favorable terms, whether because of disruptions or volatility in those markets or otherwise, could necessitate additional capital raising or borrowings by NEE and/or NEECH in the future.

The inability of subsidiaries that have existing project-specific financing arrangements to meet the requirements of various agreements relating to those financings could give rise to a project-specific financing default which, if not cured or waived, might result in the specific project, and potentially in some limited instances its parent companies, being required to repay the associated debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have rights to foreclose against the project assets and related collateral. Such an occurrence also could result in NEE expending additional funds or incurring additional obligations over the shorter term to ensure continuing compliance with project-specific financing arrangements based upon the expectation of improvement in the project's performance or financial returns over the longer term. Any of these actions could materially adversely affect NEE's business, financial condition, results of operations and prospects, as well as the availability or terms of future financings for NEE or its subsidiaries.

NEE's, NEECH's and FPL's inability to maintain their current credit ratings may adversely affect NEE's and FPL's liquidity and results of operations, limit the ability of NEE and FPL to grow their business, and increase interest costs.

The inability of NEE, NEECH and FPL to maintain their current credit ratings could adversely affect their ability to raise capital or obtain credit on favorable terms, which, in turn, could impact NEE's and FPL's ability to grow their business and service indebtedness and repay borrowings, and would likely increase their interest costs. Some of the factors that can affect credit ratings are cash flows, liquidity, the amount of debt as a component of total capitalization, and political, legislative and regulatory actions. There can be no assurance that one or more of the ratings of NEE, NEECH and FPL will not be lowered or withdrawn entirely by a rating agency.

NEE's and FPL's liquidity may be impaired if their creditors are unable to fund their credit commitments to the companies or to maintain their current credit ratings.

The inability of NEE's, NEECH's and FPL's credit providers to fund their credit commitments or to maintain their current credit ratings could require NEE, NEECH or FPL, among other things, to renegotiate requirements in agreements, find an alternative credit provider with acceptable credit ratings to meet funding requirements, or post cash collateral and could have a material adverse effect on NEE's and FPL's liquidity.

Poor market performance and other economic factors could affect NEE's ~~and FPL's~~ defined benefit pension plan's funded status, which may materially adversely affect NEE's and FPL's liquidity and results of operations.

NEE sponsors a qualified noncontributory defined benefit pension plan for substantially all employees of NEE and its subsidiaries. A decline in the market value of the assets held in the defined benefit pension plan due to poor investment performance or other factors may increase the funding requirements for this obligation.

NEE's ~~and FPL's~~ defined benefit pension plan is sensitive to changes in interest rates, since, as interest rates decrease the funding liabilities increase, potentially increasing benefits costs and funding requirements. Any increase in benefits costs or funding requirements may have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

Poor market performance and other economic factors could adversely affect the asset values of NEE's and FPL's nuclear decommissioning funds, which may materially adversely affect NEE's and FPL's liquidity and results of operations.

NEE and FPL are required to maintain decommissioning funds to satisfy their future obligations to decommission their nuclear power plants. A decline in the market value of the assets held in the decommissioning funds due to poor investment performance or other factors may increase the funding requirements for these obligations. Any increase in funding requirements may have a material adverse effect on NEE's and FPL's business, financial condition, results of operations and prospects.

Certain of NEE's investments are subject to changes in market value and other risks, which may adversely affect NEE's liquidity and financial results.

NEE holds other investments where changes in the fair value affect NEE's financial results. In some cases there may be no observable market values for these investments, requiring fair value estimates to be based on other valuation techniques. This type of analysis requires significant judgment and the actual values realized in a sale of these investments could differ materially from those estimated. A sale of an investment below previously estimated value, or other decline in the fair value of an investment, could result in losses or the write-off of such investment, and may have an material adverse effect on NEE's financial condition and results of operations.

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NEE holds other investments where changes in the fair value affect NEE's financial results. In some cases there may be no observable market values for these investments, requiring fair value estimates to be based on other valuation techniques. This type of analysis requires significant judgment and the actual values realized in a sale of these investments could differ materially from those estimated. A sale of an investment below previously estimated value, or other decline in the fair value of an investment, could result in losses or the write-off of such investment, and may have a material adverse effect on NEE's financial condition and results of operations.

NEE may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay upstream dividends or repay funds to NEE.

NEE is a holding company and, as such, has no material operations of its own. Substantially all of NEE's consolidated assets are held by its subsidiaries. NEE's ability to meet its financial obligations, including, but not limited to, its guarantees, and to pay dividends on its common stock ~~are~~is primarily dependent on its subsidiaries' net income and cash flows, which are subject to the risks of their respective businesses, and their ability to pay upstream dividends or to repay funds to NEE.

NEE's subsidiaries are separate legal entities and have no independent obligation to provide NEE with funds for its payment obligations. The subsidiaries have financial obligations, including, but not limited to, payment of debt service, which they must satisfy before they can fund NEE. In addition, in the event of a subsidiary's liquidation or reorganization, NEE's right to participate in a distribution of assets is subject to the prior claims of the subsidiary's creditors.

The dividend-paying ability of some of the subsidiaries is limited by contractual restrictions which are contained in outstanding financing agreements and which may be included in future financing agreements. The future enactment of laws or regulations also may prohibit or restrict the ability of NEE's subsidiaries to pay upstream dividends or to repay funds.

NEE may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if NEE is required to perform under guarantees of obligations of its subsidiaries.

NEE guarantees many of the obligations of its consolidated subsidiaries, other than FPL, through guarantee agreements with NEECH. These guarantees may require NEE to provide substantial funds to its subsidiaries or their creditors or counterparties at a time when NEE is in need of liquidity to meet its own financial obligations. Funding such guarantees may materially adversely affect NEE's ability to pay dividends.

Disruptions, uncertainty or volatility in the credit and capital markets may exert downward pressure on the market price of NEE's common stock.

The market price and trading volume of NEE's common stock are subject to fluctuations as a result of, among other factors, general credit and capital market conditions and changes in market sentiment regarding the operations, business and financing strategies of NEE and its subsidiaries. As a result, disruptions, uncertainty or volatility in the credit and capital markets may, for example, have a material adverse effect on the market price of NEE's common stock.

The factors described above, as well as other information set forth in this report, which could materially adversely affect NEE's and FPL's businesses, financial condition, future financial results and/or liquidity should be carefully considered. The risks described above are not the only risks facing NEE and FPL. Additional risks and uncertainties not currently known to NEE or FPL, or that are currently deemed to be immaterial, also may materially adversely affect NEE's or FPL's business, financial condition, results of operations and prospects.

Item 1B. Unresolved Staff Comments

None

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Item 2. Properties

NEE and its subsidiaries maintain properties which are adequate for their operations. The principal properties of FPL and NEER are described below.

Generating Facilities

FPL

At December 31, ~~2011~~2012, the electric generating, transmission, distribution and general facilities of FPL represented approximately 4850%, 1211%, 3634% and 45%, respectively, of FPL's gross investment in electric utility plant in service and other property. At December 31, ~~2011~~2012, FPL had the following generating facilities:

FPL Facilities	Location	No.of Units	Fuel	NetCapability(mw)(a)
Fossil
Combined-cycle
Fort Myers	Fort Myers, FL	1	Gas	1,432
Lauderdale	Dania, FL	2	Gas/Oil	884
Manatee	Parrish, FL	1	Gas	1,111
Martin	Indiantown, FL	1	Gas/Oil/Solar Thermal	1,~~132~~141	(b)
Martin	Indiantown, FL	2	Gas	938
Putnam	Palatka, FL	2	Gas/Oil	498
Sanford	Lake Monroe, FL	2	Gas	1,~~912~~946
Turkey Point	Florida City, FL	1	Gas/Oil	1,148
West County	West Palm Beach, FL	3	Gas/Oil	3,657
Steam turbines
Cutler	Miami, FL	2	Gas	205
Manatee	Parrish, FL	2	Oil/Gas	1,621
Manatee	Parrish, FL	2	Oil/Gas	1,624
Martin	Indiantown, FL	2	Oil/Gas	1,652
Port Everglades	Port Everglades, FL	42	Oil/Gas	~~1,187~~761	(c)
St. Johns River Power Park	Jacksonville, FL	2	Coal/Petroleum Coke	254	(cd)
Sanford	Lake Monroe, FL	1	Oil/Gas	138
Scherer	Monroe County, GA	1	Coal	642	(e)
Scherer	Monroe County, GA	1	Coal	672	(d)
Turkey Point	Florida City, FL	2	Oil/Gas	788
Simple-cycle combustion turbines
Fort Myers	Fort Myers, FL	2	Gas/Oil	315
Gas turbines
Fort Myers	Fort Myers, FL	12	Oil	648
Lauderdale	Dania, FL	24	Oil/Gas	840
Port Everglades	Port Everglades, FL	12	Oil/Gas	420
Nuclear
St. Lucie	Hutchinson Island, FL	2	Nuclear	1,~~584~~824	(ef)
Turkey Point	Florida City, FL	2	Nuclear	1,~~386~~502
Solar PV
DeSoto	Arcadia, FL	1	Solar PV	25
Space Coast	Cocoa, FL	1	Solar PV	10
TOTAL				24,~~460~~057	(fg)

______________________

(a) Represents FPL's net ownership interest in ~~plant~~warm weather peaking capability.


(b)	The megawatts generated by the 75 mw solar thermal facility replace steam produced by this unit and therefore are not incremental.

(c) ~~Represents~~As ~~FPL's~~part ~~20%~~of ~~ownership~~the ~~interest~~modernization inof ~~each~~the ofPort ~~SJRPP~~Everglades ~~Units~~plant, ~~Nos.~~two 1units were retired in November 2012 and 2,the ~~which~~remaining ~~are~~two ~~jointly~~units ~~owned~~will ~~with~~be ~~JEA~~retired during the first quarter of 2013.

(d) Represents FPL's ~~approximately 76~~20% ownership interest in each of ~~Scherer~~SJRPP ~~Unit~~Units NoNos. 41 and 2, which isare jointly owned with JEA.

(e) ~~Excludes~~Represents ~~Orlando Utilities Commission~~FPL's ~~and~~approximately ~~the~~76% ~~Florida~~ownership ~~Municipal~~of ~~Power~~Scherer ~~Agency's~~Unit ~~combined~~No. ~~share~~4, ofwhich ~~approximately~~is ~~15%~~jointly ofowned ~~St.~~with ~~Lucie Unit No~~JEA. 2.

(f) ~~Substantially~~Excludes ~~all~~Orlando ofUtilities ~~FPL~~Commission's ~~properties~~and ~~are~~the ~~subject~~Florida toMunicipal ~~the~~Power ~~lien~~Agency's combined share of ~~FPL's~~approximately ~~mortgage~~15% of St. Lucie Unit No. 2.


(g)	Substantially all of FPL's properties are subject to the lien of FPL's mortgage.

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NEER

At December 31, ~~2011~~2012, NEER had the following generating facilities:

NEER Facilities

Location

GeographicRegion

No.of Units

Fuel

NetCapability(mw)(a)

Wind

Ashtabula Wind(b)(c)

Barnes County, ND

Midwest

Wind

148

Ashtabula Wind II(c)

Griggs & Steele Counties, ND

Midwest

Wind

120

Ashtabula Wind II(b)(c)

Griggs & Steele Counties, ND

Midwest

Wind

120

Ashtabula Wind III

Barnes County, ND

Midwest

Wind

Baldwin Wind(b)

Burleigh County, ND

Midwest

Wind

102

Blackwell Wind

Kay County, OK

Other South

Wind

Blue Summit

Wilbarger County, TX

Texas

Wind

135

Buffalo Ridge

Lincoln County, MN

Midwest

Wind

Butler Ridge Wind(b)(c)

Dodge County, WI

Midwest

Wind

Cabazon(b)

Riverside County, CA

West

5352

Wind

4039

Callahan Divide(b)

Taylor County, TX

~~ERCOT~~Texas

Wind

114

Capricorn Ridge

Sterling & Coke Counties, TX

ERCOT

208

Wind

364

Capricorn Ridge(c)

Sterling & Coke Counties, TX

Texas

208

Wind

364

Capricorn Ridge Expansion

Sterling & Coke Counties, TX

ERCOT

199

Wind

298

Capricorn Ridge Expansion(c)

Sterling & Coke Counties, TX

Texas

199

Wind

298

Cerro Gordo(b)

Cerro Gordo County, IA

Midwest

Wind

Cimarron(b)

Gray County, KS

Other South

Wind

166

Conestogo Wind

Wellington County, Ontario, Canada

Midwest

Wind

Crystal Lake I(b)(c)

Hancock County, IA

Midwest

100

Wind

150

Crystal Lake II

Winnebago County, IA

Midwest

Wind

200

Crystal Lake III

Winnebago County, IA

Midwest

Wind

Day County Wind(b)

Day County, SD

Midwest

Wind

Delaware Mountain

Culberson County, TX

~~ERCOT~~Texas

Wind

Diablo Wind(b)

Alameda County, CA

West

Wind

Elk City Wind(b)

Roger Mills & Beckham Counties, OK

Other South

Wind

Elk City Wind II

Roger Mills & Beckham Counties, OK

Other South

Wind

101

Endeavor Wind

Osceola County, IA

Midwest

Wind

100

Endeavor Wind II

Osceola County, IA

Midwest

Wind

Ghost Pine Wind

Trochu, Alberta, Canada

West

Wind

Ensign Wind

Gray County, KS

Other South

Wind

Ghost Pine Wind

Kneehill County, Alberta, Canada

West

Wind

Gray County

Gray County, KS

Other South

170

Wind

112

Green Mountain(b)

Somerset County, PA

Northeast

Wind

Green Power

Riverside County, CA

West

Wind

Green Ridge Power

Alameda & Contra Costa Counties, CA

West

803

Wind

Hancock County(b)

Hancock County, IA

Midwest

148

Wind

High Winds(b)

Solano County, CA

West

Wind

162

Horse Hollow Wind(b)

Taylor County, TX

~~ERCOT~~Texas

142

Wind

213

Horse Hollow Wind II(b)

Taylor & Nolan Counties, TX

~~ERCOT~~Texas

130

Wind

299

Horse Hollow Wind III(b)

Nolan County, TX

~~ERCOT~~Texas

149

Wind

224

Indian Mesa

Pecos County, TX

~~ERCOT~~Texas

125

Wind

King Mountain(b)

Upton County, TX

~~ERCOT~~Texas

214

Wind

278

Lake Benton II(b)

Pipestone County, MN

Midwest

137

Wind

103

Langdon Wind(b)(c)

Cavalier County, ND

Midwest

Wind

118

Langdon Wind II(b)(c)

Cavalier County, ND

Midwest

Wind

Lee / DeKalb Wind

Lee & DeKalb Counties, IL

Midwest

145

Wind

217

Limon I(b)(c)

Lincoln, Elbert & Arapahoe Counties, CO

West

125

Wind

200

Limon II(b)(c)

Lincoln, Elbert & Arapahoe Counties, CO

West

125

Wind

200

Logan Wind(c)

Logan County, CO

West

134

Wind

201

Majestic Wind(b)(c)

Carson County, TX

~~Other South~~Texas

Wind

Majestic Wind II(b)(c)

Carson & Potter Counties, TX

Texas

Wind

Meyersdale(b)

Somerset County, PA

Northeast

Wind

Mill Run(b)

Fayette County, PA

Northeast

Wind

Minco Wind(b)

Grady County, OK

Other South

Wind

Minco Wind II(b)

Grady & Caddo Counties, OK

Other South

Wind

101

Minco Wind III

Grady, Caddo & Canadian Counties, OK

Other South

Wind

101

Mojave 3/4/5

Kern County, CA

West

246

Wind

Montezuma Wind(b)

Solano County, CA

West

Wind

Montfort(b)

Iowa County, WI

Midwest

Wind

Montezuma Wind II(b)(c)

Solano County, CA

West

Wind

Mount Copper(b)

~~Murdochville~~Gaspésie, Quebec, Canada

Midwest

Wind

Mount Miller(b)

Murdochville, Quebec, Canada

Midwest

Wind

Mountaineer(b)

Preston & Tucker Counties, WV

Northeast

Wind

Mower County Wind(c)

Mower County, MN

Midwest

Wind

New Mexico Wind(b)

Quay & Debaca Counties, NM

West

136

Wind

204

North Dakota Wind(b)

LaMoure County, ND

Midwest

Wind

Northern Colorado(b)

Logan County, CO

West

Wind

174

Oklahoma / Sooner Wind(b)

Harper & Woodward Counties, OK

Other South

Wind

102

Oliver County Wind I(c)

Oliver County, ND

Midwest

Wind

Oliver County Wind II(c)

Oliver County, ND

Midwest

Wind

Peetz Table Wind(c)

Logan County, CO

West

133

Wind

199

Pubnico Point(b)

Yarmouth, Nova Scotia, Canada

Midwest

Wind

Red Canyon Wind Energy(b)

Borden, Garza & Scurry Counties, TX

ERCOT

Wind

Table of Contents

NEER Facilities

Location

GeographicRegion

No.of Units

Fuel

NetCapability(mw)(a)

Mount Miller(b)

Gaspésie, Quebec, Canada

Midwest

Wind

Mountaineer Wind(b)

Preston & Tucker Counties, WV

Northeast

Wind

Mower County Wind(c)

Mower County, MN

Midwest

Wind

New Mexico Wind(b)

Quay & Debaca Counties, NM

West

136

Wind

204

North Dakota Wind(b)

LaMoure County, ND

Midwest

Wind

North Sky River

Kern County, CA

West

100

Wind

160

Northern Colorado(b)

Logan County, CO

West

Wind

174

Oklahoma / Sooner Wind(b)

Harper & Woodward Counties, OK

Other South

Wind

102

Oliver County Wind I(c)

Oliver County, ND

Midwest

Wind

Oliver County Wind II(c)

Oliver County, ND

Midwest

Wind

Peetz Table Wind(c)

Logan County, CO

West

133

Wind

199

Perrin Ranch Wind(b)

Coconino County, AZ

West

Wind

Pubnico Point(b)

Yarmouth County, Nova Scotia, Canada

Midwest

Wind

Red Canyon Wind(b)

Borden, Garza & Scurry Counties, TX

Texas

Wind

Red Mesa Wind

Cibola County, NM

West

Wind

102

Sky River(b)

Kern County, CA

West

~~342~~322

Wind

7773

Somerset Wind Power(b)

Somerset County, PA

Northeast

Wind

South Dakota Wind(b)

Hyde County, SD

Midwest

Wind

Southwest Mesa(b)

Upton & Crockett Counties, TX

~~ERCOT~~Texas

106

Wind

Stateline(b)

Umatilla County, OR and Walla Walla County, WA

West

454

Wind

300

Story County Wind(b)(c)

Story County, IA

Midwest

100

Wind

150

Story County Wind II(b)

Story & Hardin Counties, IA

Midwest

100

Wind

150

Tuscola Bay(b)

Tuscola, Bay & Saginaw Counties, MI

Midwest

Wind

120

Vansycle(b)

Umatilla County, OR

West

Wind

Vansycle II

Umatilla County, OR

West

Wind

Vasco Winds(c)

Contra Costa County, CA

West

Wind

Vasco Winds(b)(c)

Contra Costa County, CA

West

Wind

Victory Garden(b)

Kern County, CA

West

Wind

Waymart(b)

Wayne County, PA

Northeast

Wind

Weatherford Wind(b)

Custer & Washita Counties, OK

Other South

Wind

147

Wessington Springs Wind(b)(c)

Jerauld County, SD

Midwest

Wind

White Oak(c)

McLean County, IL

Midwest

100

Wind

150

White Oak(b)(c)

McLean County, IL

Midwest

100

Wind

150

Wilton Wind(b)

Burleigh County, ND

Midwest

Wind

Wilton Wind II(c)

Burleigh County, ND

Midwest

Wind

Wilton Wind II(b)(c)

Burleigh County, ND

Midwest

Wind

Windpower Partners 1990

Alameda & Contra Costa Counties, CA

West

141

Wind

Windpower Partners 1991

Alameda & Contra Costa Counties, CA

West

162

Wind

Windpower Partners 1991-92

Alameda & Contra Costa Counties, CA

West

223

Wind

Windpower Partners 1992

Alameda & Contra Costa Counties, CA

West

300

Wind

Windpower Partners 1993(c)

Riverside County, CA

West

Wind

Windpower Partners 1993(b)(c)

Riverside County, CA

West

Wind

Windpower Partners 1993

Lincoln County, MN

Midwest

Wind

Windpower Partners 1994

Culberson County, TX

Texas

107

Wind

Windpower Partners 1994

Culberson County, TX

ERCOT

107

Wind

Wolf Ridge Wind

Cooke County, TX

Texas

Wind

112

Wolf Ridge Wind

Cooke County, TX

ERCOT

Wind

112

Woodward Mountain

Upton & Pecos Counties, TX

Texas

242

Wind

160

Woodward Mountain

Upton & Pecos Counties, TX

ERCOT

242

Wind

160

Wyoming Wind(b)

Uinta County, WY

West

Wind

144

Investments in joint ventures(d)

Various

West

643

Wind

Investments in joint ventures(b)

Kern County, CA

West

397

Wind

Total Wind

810,~~569~~057

Contracted

Bayswater(b)

Far Rockaway, NY

Northeast

Gas

Duane Arnold

Palo, IA

Midwest

Nuclear

431

(ed)

Hatch Solar

Hatch, NM

West

~~CPV~~ Solar CPV

Jamaica Bay(b)

Far Rockaway, NY

Northeast

Gas/Oil

Marcus Hook 750(b)

Marcus Hook, PA

Northeast

Gas

744

Moore Solar(b)

Lambton County, Ontario, Canada

Northeast

Solar PV

Point Beach

Two Rivers, WI

Midwest

Nuclear

1,190

Sombra Solar(b)

Lambton County, Ontario, Canada

Northeast

Solar PV

Investments in joint ventures:

SEGS III-IX(b)

Kramer Junction & Harper Lake, CA

West

Solar Thermal

148

Other

Various

Northeast

(fe)

158

Total Contracted

2,~~786~~826

Merchant

Forney

Forney, TX

ERCOT

Gas

1,792

Lamar Power Partners

Paris, TX

ERCOT

Gas

1,000

Maine - Cape, Wyman

Various - ME

Northeast

Oil

796

(g)

Maine(b)

Various - ME

Northeast

Hydro

359

Marcus Hook 50

Marcus Hook, PA

Northeast

Gas

Paradise Solar

West Deptford, NJ

Northeast

Solar PV

Seabrook

Seabrook, NH

Northeast

Nuclear

1,100

(h)

Investment in joint ventures

Various

Northeast

(f)

150

Total Merchant

5,252

TOTAL

16,607

~~________________________~~38

Table of Contents

NEER Facilities

Location

Geographic

Region

No.

of Units

Fuel

Net

Capability

(mw)^(a)

Merchant

Forney

Forney, TX

Texas

Gas

1,792

Lamar Power Partners

Paris, TX

Texas

Gas

1,000

Maine - Cape, Wyman

Various - ME

Northeast

Oil

796

^(f)

Maine^(b)

Various - ME

Northeast

Hydro

351

^(g)

Marcus Hook 50

Marcus Hook, PA

Northeast

Gas

Paradise Solar

West Deptford, NJ

Northeast

Solar PV

Seabrook

Seabrook, NH

Northeast

Nuclear

1,100

^(h)

Investment in joint venture

Sayreville, NJ

Northeast

Gas

145

Total Merchant

5,239

TOTAL

18,122

______________________


(a)	Represents NEER's net ownership interest in plant capacity.


(b)	These generating facilities are encumbered by liens against their assets securing various financings.


(c)	NEER owns these wind facilities together with third-party investors with differential membership interests. See Note 1 - Sale of Differential Membership Interests.

(d) ~~Represents~~Excludes ~~plants~~Central ~~with~~Iowa noPower ~~more~~Cooperative ~~than~~and ~~50%~~Corn ~~ownership~~Belt ~~using~~Power ~~wind~~Cooperative's ~~technology.~~combined ~~Certain~~share ~~facilities,~~of ~~totaling 57 mw, are encumbered by liens against their assets securing a financing~~30%.

(e) ~~Excludes~~Represents ~~Central~~plants ~~Iowa~~with ~~Power~~no ~~Cooperative~~more ~~and~~than ~~Cornbelt~~50% ~~Power~~ownership ~~Cooperative's~~using ~~combined~~fuels ~~share~~such ofas ~~30%~~natural gas and waste coal.

(f) ~~Represents~~Excludes ~~plants~~six ~~with~~other noenergy-related ~~more~~partners' ~~than~~combined ~~50%~~share ~~ownership~~of ~~using fuels such as natural gas and waste coal~~16%.

(g) ~~Excludes~~See ~~six~~Note ~~other~~1 ~~energy~~-~~related~~ ~~partners'~~Assets ~~combined~~and ~~share~~Liabilities Associated with Assets Held for Sale for discussion of ~~16%~~the pending sale of these facilities.


(h)	Excludes Massachusetts Municipal Wholesale Electric Company's, Taunton Municipal Lighting Plant's and Hudson Light & Power Department's combined share of 11.77%.

Table of Contents

Transmission and Distribution

At December 31, ~~2011~~2012, FPL owned and operated ~~587~~591 substations and the following electric transmission and distribution lines:

NominalVoltage		Overhead LinesPole Miles		Trench andSubmarineCables Miles
500	kv	1,106	(a)	—
230	kv	3,038		25
138	kv	1,~~575~~577		53
115	kv	~~746~~748		1
69	kv	~~164~~165		14
Less than 69 kv		42,~~334~~331		25,~~111~~207
Total		48,~~963~~965		25,~~204~~300

~~___________________~~______________________

(a) Includes approximately 75 miles owned jointly with JEA.

Character of Ownership

Substantially all of FPL's properties are subject to the lien of FPL's mortgage, which secures most debt securities issued by FPL. The majority of FPL's real property is held in fee and is free from other encumbrances, subject to minor exceptions which are not of a nature as to substantially impair the usefulness to FPL of such properties. Some of FPL's electric lines are located on parcels of land which are not owned in fee by FPL but are covered by necessary consents of governmental authorities or rights obtained from owners of private property. The majority of NEER's generating facilities are owned by NEER subsidiaries and a number of those facilities are encumbered by liens securing various financings. Additionally, certain of NEER's generating facilities are located on land leased from owners of private property. See Generating Facilities and Note 1 - Electric Plant, Depreciation and Amortization.

Item 3. Legal Proceedings

NEE and FPL are parties to various legal and regulatory proceedings in the ordinary course of their respective businesses. For information regarding legal proceedings that could have a material effect on NEE or FPL, see Note 1413 - Legal Proceedings. Such descriptions are incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable

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PART II

Item 5. Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock Data. All of FPL's common stock is owned by NEE. NEE's common stock is traded on the New York Stock Exchange under the symbol "NEE." The high and low sales prices for the common stock of NEE as reported in the consolidated transaction reporting system of the New York Stock Exchange and the cash dividends per share declared for each quarter during the past two years are as follows:

	2011						2010
	2012						2011
Quarter	High		Low		CashDividends		High		Low		CashDividends
First	$	5561.8621	$	5158.5457	$	0.5560	$	5355.7586	$	4551.2954	$	0.5055
Second	$	5868.9896	$	5461.1620	$	0.5560	$	5358.5098	$	4754.9616	$	0.5055
Third	$	5872.2522	$	4965.0095	$	0.5560	$	5558.9825	$	4849.4400	$	0.5055
Fourth	$	6172.2021	$	5166.3305	$	0.5560	$	5661.2620	$	5051.0033	$	0.5055

39The amount and timing of dividends payable on NEE's common stock are within the sole discretion of NEE's Board of Directors. The Board of Directors reviews the dividend rate at least annually (generally in February) to determine its appropriateness in light of NEE's financial position and results of operations, legislative and regulatory developments affecting the electric utility industry in general and FPL in particular, competitive conditions, change in business mix and any other factors the Board of Directors deems relevant. The ability of NEE to pay dividends on its common stock is dependent upon, among other things, dividends paid to it by its subsidiaries. There are no restrictions in effect that currently limit FPL's ability to pay dividends to NEE. In February 2013, NEE announced that it would increase its quarterly dividend on its common stock from $0.60 to $0.66 per share. See Management's Discussion - Liquidity and Capital Resources - Covenants with respect to dividend restrictions and Note 10 - Common Stock Dividend Restrictions regarding dividends paid by FPL to NEE.

~~Table~~As of ~~Contents~~the close of business on January 31, 2013, there were 24,339 holders of record of NEE's common stock.

~~The~~Issuer ~~amount~~Purchases ~~and timing~~ of ~~dividends~~Equity ~~payable on NEE's common stock are within the sole discretion of NEE's Board of Directors~~Securities. ~~The~~Information ~~Board~~regarding ofpurchases ~~Directors~~made ~~reviews~~by ~~the dividend rate at least annually (generally in February) to determine its appropriateness in light of~~ NEE's ~~financial position and results~~ of operations, legislative and regulatory developments affecting the electric utility industry in general and FPL in particular, competitive conditions, change in business mix and any other factors the Board of Directors deems relevant. The ability of NEE to pay dividends on its common stock isduring ~~dependent~~the ~~upon,~~three ~~among~~months ~~other~~ended ~~things~~December 31, ~~dividends paid to it by its subsidiaries. There are no restrictions in effect that currently limit FPL's ability to pay dividends to NEE. In February~~ 2012, ~~NEE~~is ~~announced~~as that it would increase its quarterly dividend on its common stock from $0.55 to $0.60 per share. See Management's Discussion - Liquidity and Capital Resources - Covenants with respect to dividend restrictions and Note 11 - Common Stock Dividend Restrictions regarding dividends paid by FPL to NEE.follows:

As of the close of business on January 31, 2012, there were 25,588 holders of record of NEE's common stock.



Period	Total Number of Shares Purchased ^(a)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Number of Shares that May Yet be Purchased Under the Program^(b)
10/1/2012 - 10/31/12	847	$	70.26	—	13,274,748
11/1/2012 - 11/30/12	516	$	66.49	—	13,274,748
12/1/2012 - 12/31/12	512	$	70.58	—	13,274,748
Total	1,875	$	69.31	—

~~Issuer Purchases of Equity Securities. Information regarding purchases made by NEE of its common stock during the three months ended December 31, 2011 is as follows:~~______________________

Period	TotalNumberof SharesPurchased		AveragePrice PaidPer Share		Total Number of SharesPurchased as Part of aPublicly Announced Program	Maximum Number ofShares that May Yet bePurchased Under theProgram(a)
10/1/2011 - 10/31/11	848	(b)	$	54.82	—	20,000,000
11/1/2011 - 11/30/11	5,093	(b)	$	55.65	—	20,000,000
12/1/2011 - 12/31/11	6,725,809	(c)	$	55.76	6,725,252	13,274,748
Total	6,731,750		$	55.76	6,725,252

(a)

Includes: (1) in October and November 2012, shares of common stock withheld from employees to pay certain withholding taxes upon the vesting of stock awards granted to such employees under the NextEra Energy, Inc. Amended and Restated Long-Term Incentive Plan (former LTIP); and (2) in December 2012, shares of common stock purchased as a reinvestment of dividends by the trustee of a grantor trust in connection with NEE's obligation under a February 2006 grant under the former LTIP to an executive officer of deferred retirement share awards.

~~__________________________________~~(b) In February 2005, NEE's Board of Directors authorized common stock repurchases of up to 20 million shares of common stock over an unspecified period, which authorization was most recently reaffirmed and ratified by the Board of Directors in July 2011.

(a) In February 2005, NEE's Board of Directors authorized a common stock repurchase plan of up to 20 million shares of common stock over an unspecified period, which authorization was most recently reaffirmed and ratified by the Board of Directors in July 2011.

(b) Includes shares of common stock withheld from employees to pay certain withholding taxes upon the vesting of stock awards granted to such employees under the NextEra Energy, Inc. Amended and Restated Long-Term Incentive Plan (former LTIP).

(c) Includes: (1) 557 shares of common stock purchased as a reinvestment of dividends by the trustee of a grantor trust in connection with NEE's obligation under a February 2006 grant under the former LTIP of deferred retirement share awards to an executive officer; and (2) 6,725,252 shares of common stock purchased under an Accelerated Share Repurchase (ASR) agreement (see Note 11 - ASR of NEE Common Stock).

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Item 6. Selected Financial Data

	Years Ended December 31,
	2011			2010			2009			2008			2007
	2012			2011			2010			2009			2008
SELECTED DATA OF NEE (millions, except per share amounts):
Operating revenues	$	1514,~~341~~256		$	15,~~317~~341		$	15,~~643~~317		$	1615,~~410~~643		$	1516,~~263~~410
Net income(a)	$	1,~~923~~911		$	1,~~957~~923		$	1,~~615~~957		$	1,~~639~~615		$	1,~~312~~639
Earnings per share of common stock - basic	$	4.6259		$	4.7762		$	34.9977		$	43.1099		$	34.3010
Earnings per share of common stock - assuming dilution	$	4.5956		$	4.7459		$	34.9774		$	43.0797		$	34.2707
Dividends paid per share of common stock	$	2.2040		$	2.0020		$	12.8900		$	1.7889		$	1.6478
Total assets	$	57,188		$	52,994		$	48,458		$	44,821		$	40,123
Total assets(b)	$	64,439		$	57,188		$	52,994		$	48,458		$	44,821
Long-term debt, excluding current maturities	$	2023,~~810~~177		$	1820,~~013~~810		$	1618,~~300~~013		$	1316,~~833~~300		$	1113,~~280~~833
SELECTED DATA OF FPL (millions):
Operating revenues	$	10,~~613~~114		$	10,~~485~~613		$	1110,~~491~~485		$	11,~~649~~491		$	11,~~622~~649
Net income	$	1,~~068~~240		$	~~945~~1,068		$	~~831~~945		$	~~789~~831		$	~~836~~789
Total assets	$	3134,~~816~~853		$	2831,~~698~~816		$	2628,~~812~~698		$	26,~~175~~812		$	2426,~~044~~175
Long-term debt, excluding current maturities	$	78,~~483~~329		$	67,~~682~~483		$	56,~~794~~682		$	5,~~311~~794		$	45,~~976~~311
Energy sales (kwh)	~~106~~105,~~662~~109			~~107~~106,~~978~~662			~~105~~107,~~414~~978			105,~~406~~414			~~108~~105,~~636~~406
Energy sales:
Residential	5150.28		%	5251.2		%	5152.2		%	5051.52		%	50.85		%
Commercial	4243.20			4142.32			4241.73			4342.27			4243.32
Industrial	2.9			2.9			32.19			3.41			3.54
Interchange power sales	0.97			0.89			10.48			1.64			1.86
Other(b)	2.8			2.8			1.6			1.3			1.6
Other(c)	2.6			2.8			2.8			1.6			1.3
Total	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%
Approximate 60-minute peak load (mw):(c)
Approximate 60-minute peak load (mw):(d)
Summer season	21,~~619~~440			2221,~~256~~619			22,~~351~~256			2122,~~060~~351			21,~~962~~060
Winter season	1720,~~934~~286			2117,~~153~~934			2421,~~346~~153			2024,~~031~~346			1820,~~055~~031
Average number of customer accounts (thousands):
Residential	4,~~027~~052			4,~~004~~027			34,~~984~~004			3,~~992~~984			3,~~981~~992
Commercial	~~508~~512			~~504~~508			~~501~~504			501			~~493~~501
Industrial	9			9			109			1310			1913
Other	3			3			43			4			4
Total	4,~~547~~576			4,~~520~~547			4,~~499~~520			4,~~510~~499			4,~~497~~510
Average price billed to customers (cents per kwh)	9.8351			9.3483			119.1934			1011.9619			10.6396

~~__________________________________~~______________________

(a) Includes net unrealized mark-to-market after-tax (gains) (losses) associated with non-qualifying hedges of $(~~190~~34) million, $~~(175)~~190 million, $20175 million, $(~~170~~20) million and $86170 million and OTTI after-tax income (losses), net of OTTI reversals of $631 million, $(46) million, $134 million, $76(13) million and $6(76) million for the years ended December 31, 2012, 2011, 2010, 2009, ~~2008~~ and ~~2007~~2008, respectively. Also, 2011 includes aan after-tax loss on the sale of natural gas-fired generating assets of approximately $98 million. See Note 4 - Nonrecurring Fair Value Measurements.

(b) ~~Includes~~In ~~the~~2012, ~~net~~includes ~~change~~assets inheld ~~unbilled~~for ~~sales~~sale of approximately $335 million. See Note 1 - Assets and Liabilities Associated with Assets Held for Sale.

(c) ~~Winter~~Includes ~~season includes November and December of~~ the ~~current~~net ~~year~~change ~~and~~in ~~January~~unbilled ~~to March of the following year (for 2011, through February 27, 2012)~~sales.


(d)	Winter season includes November and December of the current year and January to March of the following year (for 2012, through February 27, 2013).

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

NEE’s operating performance is driven primarily by the operations of its two principal subsidiaries, FPL, which serves approximately 4.6 million customer accounts in Florida and is one of the largest rate-regulated electric utilities in the U.S., and NEER, which together with ~~its~~ affiliated entities is the largest generator in ~~the~~North ~~U.S.~~America of renewable energy from the wind and sun. The table below presents NEE’s net income and earnings per share by reportable segment - FPL, NEER and Corporate and Other, which is primarily comprised of interest expense, the operating results of NEET, FPL FiberNet, ~~Lone Star~~ and other business activities, as well as other income and expense items, including income taxes and eliminating entries (see Note 1514 for additional segment information). The discussion that follows should be read in conjunction with the Notes to the Consolidated Financial Statements contained herein. In the discussion below and in Results of Operations, all comparisons are with the corresponding items in the prior year.



	Net Income (Loss)							Earnings (Loss) Per Share, assuming dilution
	Years Ended December 31,							Years Ended December 31,
	2012			2011		2010		2012			2011		2010
	(millions)
FPL	$	1,240		$	1,068	$	945	$	2.96		$	2.55	$	2.29
NEER^(a)	687			774		980		1.64			1.85		2.37
Corporate and Other	(16		)	81		32		(0.04		)	0.19		0.08
NEE	$	1,911		$	1,923	$	1,957	$	4.56		$	4.59	$	4.74

______________________


(a)	NEER’s results reflect an allocation of interest expense from NEECH based on a deemed capital structure of 70% debt and allocated shared service costs.

For the five years ended December 31, 2012, NEE delivered a total shareholder return of approximately 22%, significantly outpacing the S&P 500’s 9% return, the S&P 500 Utilities' 2% return, the Dow Jones U.S. Electricity's 5% decline and the S&P 500 Electric Utilities’ 5% decline. The historical stock performance of NEE's common stock shown in the performance graph below is not necessarily indicative of future stock price performance.

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discussion that follows should be read in conjunction with the Notes to the Consolidated Financial Statements contained herein. In the discussion below and in Results of Operations, all comparisons are with the corresponding items in the prior year.

	Net Income						Earnings Per Share,assuming dilution
	Years Ended December 31,						Years Ended December 31,
	2011		2010		2009		2011		2010		2009
	(millions)
FPL	$	1,068	$	945	$	831	$	2.55	$	2.29	$	2.04
NEER(a)	774		980		759		1.85		2.37		1.86
Corporate and Other	81		32		25		0.19		0.08		0.07
NEE	$	1,923	$	1,957	$	1,615	$	4.59	$	4.74	$	3.97

(a) NEER’s results reflect an allocation of interest expense from NEECH to NEER based on a deemed capital structure of 70% debt and allocated shared service costs.

For the five years ended December 31, 2011, NEE delivered a total shareholder return of approximately 33%, significantly outpacing the S&P 500’s 1% decline, the Dow Jones US Electricity's 14% return and the S&P 500 Electric Utilities’ 18% return. The historical stock performance of NEE's common stock shown in the performance graph below is not necessarily indicative of future stock price performance.

Adjusted Earnings

NEE prepares its financial statements in accordance with GAAP. However, management uses earnings excluding certain items (adjusted earnings), a non-GAAP financial measure, internally for financial planning, for analysis of performance, for reporting of results to the Board of Directors and as an input in determining whether performance goals are met for performance-based compensation under NEE’s employee incentive compensation plans. NEE also uses adjusted earnings when communicating its financial results and earnings outlook to investors. NEE’s management believes adjusted earnings provides a more meaningful representation of the company’s fundamental earnings power. Although the excluded amounts are properly included in the determination of net income in accordance with GAAP, management believes that the amount and/or nature of such items make period to period comparisons of operations difficult and potentially confusing. Adjusted earnings do not represent a substitute for net income, as prepared in accordance with GAAP.

42Adjusted earnings exclude the unrealized mark-to-market effect of non-qualifying hedges (as described below) and OTTI losses on securities held in NEER’s nuclear decommissioning funds, net of the reversal of previously recognized OTTI losses on securities sold and losses on securities where price recovery was deemed unlikely (collectively, OTTI reversals). However, other adjustments may be made from time to time with the intent to provide more meaningful and comparable results of ongoing operations. In 2011, adjusted earnings also excluded the after-tax loss on the sale of natural gas-fired generating assets (as described below).

~~Table~~NEE and NEER segregate into two categories unrealized mark-to-market gains and losses on energy derivative transactions which are used to manage commodity price risk. The first category, referred to as non-qualifying hedges, represents certain transactions entered into as economic hedges but the transactions do not meet the requirements for hedge accounting or hedge accounting treatment is not elected. Changes in the fair value of ~~Contents~~those transactions are marked to market and reported in the consolidated statements of income, resulting in earnings volatility because the economic offset to the positions, such as the physical assets from which power is generated, are not marked to market. As a consequence, NEE's net income reflects only the movement in one part of economically-linked transactions. For this reason, NEE's management views results expressed excluding the unrealized mark-to-market impact of the non-qualifying hedges as a meaningful measure of current period performance. The second category, referred to as trading activities, which is included in adjusted earnings, represents the net unrealized effect of actively traded positions entered into to take advantage of expected market price movements and all other commodity hedging activities. At FPL, substantially all changes in the fair value of energy derivative transactions are deferred as a regulatory asset or liability until the contracts are settled, and, upon settlement, any gains or losses are passed through the fuel clause or the capacity clause. See Note 3.

~~Adjusted~~In ~~earnings~~late ~~exclude~~2011, ~~the~~subsidiaries ~~unrealized~~of ~~mark-to-market~~NEER ~~effect~~completed ofthe ~~non-qualifying~~sales ~~hedges~~of ~~(as~~their ~~described~~ownership ~~below),~~interests ~~OTTI~~in ~~losses~~five onnatural ~~securities~~gas-fired ~~held~~generating inplants ~~NEER’s~~with ~~nuclear~~a ~~decommissioning~~total ~~funds,~~generating ~~net~~capacity of ~~the~~approximately ~~reversal~~2,700 ofmw ~~previously~~located ~~recognized~~in ~~OTTI~~California, ~~losses~~Virginia, onAlabama, ~~securities~~South ~~sold~~Carolina and ~~losses~~Rhode onIsland. In ~~securities~~connection ~~where~~with ~~price~~these ~~recovery~~sales, ~~was~~a ~~deemed~~loss ~~unlikely~~of ~~(collectively,~~approximately ~~OTTI~~$151 ~~reversals)~~million ~~and,~~($98 inmillion ~~2011,~~total ~~the~~ after-tax ~~loss~~with on$92 ~~the~~million ~~sale~~ of ~~natural~~this ~~gas-fired~~loss ~~generating~~recorded ~~assets. OTTI~~by ~~reversals~~NEER) ~~are~~was ~~reported~~recorded in ~~other - net in~~ NEE's consolidated statements of income, which was excluded from adjusted earnings. See Note 4 - Nonrecurring Fair Value Measurements.

~~NEE~~In ~~and~~late ~~NEER segregate into two categories unrealized mark-to-market gains and losses on energy derivative transactions which are used to manage commodity price risk. The first category~~2012, ~~referred~~a tosubsidiary ~~as trading activities, represents the net unrealized effect~~ of ~~actively~~NEER ~~traded positions~~ entered into toan ~~take~~agreement ~~advantage~~to ofsell ~~market~~its ~~price~~ownership ~~movements~~interest ~~and,~~ in ~~2011~~a ~~and~~portfolio ~~2010,~~of ~~the~~hydropower ~~impact~~generation ~~related~~plants toand ~~exiting~~related ~~hedged~~assets ~~positions~~with ona ~~future~~total ~~gas~~generating ~~drilling~~capacity ~~opportunities. The~~of ~~second~~351 ~~category,~~mw ~~referred~~located toin asMaine ~~non-qualifying~~and ~~hedges,~~New ~~represents certain hedging transactions entered into as economic hedges but the transactions do not meet the requirements for hedge accounting or hedge accounting treatment is not elected~~Hampshire. ~~Changes~~ Upon in the ~~fair~~anticipated ~~value~~closing ~~of those transactions are marked to market and reported~~ in the ~~consolidated~~first ~~statements~~quarter of ~~income~~2013, ~~resulting~~NEER inexpects ~~earnings volatility because the economic offset~~ to ~~the~~record ~~positions~~a gain which ~~are~~is ~~required~~expected to be ~~marked~~excluded tofrom ~~market~~2013 ~~(such~~adjusted asearnings. The ~~the~~operations ~~physical~~of ~~assets~~these ~~from~~projects ~~which~~were ~~power is generated) are~~ not ~~marked~~material to ~~market. As a consequence, net income reflects only the movement in one part of economically-linked transactions. For this reason,~~ NEE's ~~management~~consolidated ~~views~~statements ~~results~~of ~~expressed~~income ~~excluding~~for the ~~unrealized~~years ~~mark-to-market~~ended ~~impact~~December of31, ~~the non-qualifying hedges as a meaningful measure of current period performance. At FPL~~2012, ~~substantially~~2011 ~~all~~and ~~changes~~2010 inand the ~~fair~~transaction ~~value~~is ofnot ~~energy~~expected ~~derivative~~to ~~transactions~~have ~~are deferred as~~ a ~~regulatory~~material ~~asset~~effect oron ~~liability~~ongoing ~~until~~future ~~the~~financial ~~contracts~~results. See ~~are~~Note ~~settled,~~1 - Assets and, ~~upon~~Liabilities ~~settlement,~~Associated ~~any~~with ~~gains~~Assets orHeld ~~losses~~for ~~are passed through the fuel clause or the capacity clause~~Sale. ~~See Note 4 - Nonrecurring Fair Value Measurements.~~

InThe ~~2011,~~following ~~subsidiaries~~table ofprovides ~~NEER~~details ~~completed~~of the ~~sales~~adjustments ofconsidered ~~their ownership interest~~ in ~~five~~computing natural gas-fired generating plants with a total generating capacity of approximately 2,700 mw located in California, Virginia, Alabama, South Carolina and Rhode Island. In connection with these sales, a loss of approximately $151 million ($98 million total after-tax with $92 million of this loss recorded by NEER) was recorded in NEE's ~~consolidated statements of income, which due to its nature and significance, was excluded from~~ adjusted earnings~~. See~~ ~~Note~~discussed 3above.

The following table provides details of the net unrealized after-tax gains and losses from non-qualifying hedges, after-tax OTTI losses, net of reversals and the after-tax loss on the sale of the natural gas-fired generating assets.



	Years Ended December 31,
	2012			2011			2010
				(millions)
Net unrealized mark-to-market after-tax gains (losses) from non-qualifying hedge activity^(a)	$	(34	)	$	190		$	175
Income (loss) from OTTI after-tax losses on securities held in NEER's nuclear decommissioning funds, net of OTTI reversals	$	31		$	(6	)	$	4
After-tax loss on sale of natural gas-fired generating assets^(b)	$	—		$	(98	)	$	—

	Years Ended December 31,
	2011			2010		2009
				(millions)
Net unrealized mark-to-market after-tax gains (losses) from non-qualifying hedge activity(a)	$	190		$	175	$	(20	)
OTTI after-tax losses on securities held in nuclear decommissioning funds, net of OTTI reversals	$	(6	)	$	4	$	(13	)
After-tax loss on sale of natural gas-fired assets(b)	$	(98	)	$	—	$	—

______________________

~~____________________~~(a) $37 million of losses, $193 million of gains and $176 million of gains, respectively, are included in NEER's net income; the balance is included in Corporate and Other.

(a) $193 million, $176 million and $(20) million, respectively, is included in NEER's net income; the balance, if any, is included in Corporate and Other.


(b)	$92 million is included in NEER's net income; the balance is included in Corporate and Other.

The change in unrealized mark-to-market activity from non-qualifying hedges is primarily attributable to changes in forward power and natural gas prices, as well as the reversal of previously recognized unrealized mark-to-market gains or losses as the underlying transactions were realized. As a general rule, a gain (loss) in the non-qualifying hedge category is offset by decreases (increases) in the fair value of related physical asset positions in the portfolio or contracts, which are not marked to market under GAAP.

2011 Summary

FPL's earned regulatory ROE was 11% in both 2010 and 2011 and FPL expects to earn an 11% regulatory ROE in 2012. FPL's increase in net income in 2011 was primarily driven by investments in plant in service and FPL's ability to use the surplus depreciation credit, as permitted under the 2010 rate agreement, to earn up to FPL's allowed 11% regulatory ROE on its retail rate base, as well as higher cost recovery clause results. The 2010 rate agreement results in retail base rates that remain effectively frozen until the end of 2012. Additionally, cost recovery for FPL’s WCEC Unit No. 3 is permitted during the term of the agreement and FPL can vary the amount of surplus depreciation amortized in any one year subject to certain caps, provided its retail regulatory return on equity remains within the allowed range of 9% to 11%.

NEER's earnings declined in 2011 reflecting the loss on sale of natural gas-fired generating assets, lower results from the customer supply and proprietary power and gas trading businesses, extended and unplanned outages at Seabrook and lower deferred tax benefits associated with cash grants (convertible ITCs), partly offset by a higher wind resource and higher gas infrastructure results. In 2011, NEER added 379 mw of wind capacity and secured approximately 1,600 mw of long-term wind power sales agreements. Additionally, in 2011 construction began on the 250 mw Genesis solar project in California and the 550 mw Desert Sunlight solar project in California, in which NEER has a 50% equity investment.

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~~Corporate~~2012 ~~and Other's earnings in 2011 increased primarily due to state deferred income tax benefits related to state tax law changes and an income tax benefit related to the dissolution of a subsidiary.~~Summary

NEE's ~~and~~net ~~its~~income ~~subsidiaries,~~for ~~including~~2012 ~~FPL,~~was ~~require~~$12 ~~funds~~million, toor ~~support~~3 ~~and~~cents ~~grow~~per ~~their~~share, ~~businesses. These~~lower ~~funds~~than ~~are~~2011 primarily ~~provided~~due byto ~~cash~~lower ~~flow~~results ~~from~~at ~~operations~~Corporate and ~~short-~~Other and ~~long-term borrowings and~~NEER, ~~from~~partly ~~time~~offset toby ~~time,~~higher ~~issuance~~earnings ofat ~~equity securities. As of February 9, 2012, NEE's total net available liquidity was approximately $5.1 billion, of which~~ FPL~~'s portion was approximately $2~~.~~8 billion.~~

FPL's increase in net income in 2012 was primarily driven by investments in plant in service which resulted in higher use of FPL's surplus depreciation credit, as permitted under the 2010 rate agreement, to earn an 11% regulatory ROE on its retail rate base, as well as higher cost recovery clause results and higher AFUDC - equity. The 2010 rate agreement was effective through December 31, 2012. See Outlook below for a discussion of the 2012 rate agreement. FPL's planned smart meter installations throughout Florida are approximately 96% complete, with a cumulative total of 4.3 million smart meters installed. In 2012, FPL maintained a typical residential bill that was the lowest of all 55 utilities in Florida and 26% below the national average based on a rate per kwh as of July 2012.

NEER's earnings decreased in 2012 primarily due to net unrealized mark-to-market losses from non-qualifying hedge activity in 2012 compared to gains on such hedges in 2011 and lower results from the existing asset portfolio, partly offset by the absence of the loss on sale of natural gas-fired generating assets and impairment charges recorded in 2011 and higher results in 2012 from new investments and the customer supply and proprietary power and gas trading businesses. In 2012, NEER added over 1,500 mw of wind capacity, including its first wind project in the province of Ontario, Canada, and placed its 10,000^th mw of wind capacity into service.

Corporate and Other's earnings in 2012 decreased primarily due to the absence of state deferred income tax benefits related to state tax law changes and an income tax benefit related to the dissolution of a subsidiary recorded in 2011.

NEE and its subsidiaries, including FPL, require funds to support and grow their businesses. These funds are primarily provided by cash flow from operations and short- and long-term borrowings and, from time to time, issuance of equity securities. As of February 8, 2013, NEE's total net available liquidity was approximately $5.7 billion, of which FPL's portion was approximately $3.1 billion.

Outlook

~~NEE~~FPL's ~~strategy~~2012 atrate ~~both~~agreement ofprovides, ~~its~~among ~~major~~other ~~businesses~~things, ~~seeks~~base torate ~~meet~~predictability ~~customer~~through ~~needs~~December ~~more~~2016, ~~economically~~including ~~and~~allowances ~~reliably~~for ~~than~~rate ~~competitors. Meeting~~increases ~~customer~~when ~~needs frequently requires~~ the ~~commitment~~modernized ofCape ~~large~~Canaveral, ~~capital~~Rivera ~~expenditures~~Beach toand ~~projects~~Port ~~that~~Everglades ~~have~~power ~~long~~plants ~~lives and such commitments~~ are ~~difficult~~placed toin ~~reverse~~service, ~~once~~and, ~~made. At~~as ~~the~~discussed ~~end~~in ofmore ~~2011~~detail below, ~~both~~permits FPL ~~and NEER had made commitments~~ to aamortize ~~variety~~the ofreserve ~~major~~up ~~capital projects that are expected~~ to be$400 ~~completed~~million over the ~~next~~2013 ~~several~~to ~~years~~2016 period. ~~While~~FPL's ~~NEE~~allowed ~~management~~regulatory ~~believes~~ROE ~~that~~over ~~these~~this ~~projects~~period ~~individually and collectively are attractive investments with the potential to create value for shareholders, there can be no guarantee that all or any of these projects~~ will be ~~successful~~10. ~~Because~~50%, ofwith ~~their~~a ~~importance,~~range ~~management~~of ~~focuses~~plus ~~particular~~or ~~attention~~minus on100 ~~these~~basis ~~large projects~~points.

InNEE's ~~2012,~~strategy at both of its principal businesses seeks to meet customer needs more economically and reliably than competitors. Meeting customer needs frequently requires the commitment of large capital expenditures to projects that have long lives and such commitments are difficult to reverse once made. Both FPL and NEER have made commitments to a variety of major capital projects that are expected to be completed over the next several years. While NEE ~~expects~~management believes that these projects individually and collectively are attractive investments with the potential to ~~focus~~create ~~efforts~~value infor shareholders, there can be no guarantee that all or any of these projects will be successful. Because of their importance, management focuses particular attention on ~~the~~these ~~following~~large ~~initiatives:~~projects.

In 2013, NEE expects to focus efforts in particular on the following initiatives:

At FPL:

• Sustaining FPL's customer value proposition.: The combination of low bills, good reliability and excellent customer service that FPL currently provides its customers is both an objective of FPL's strategy and an important contributor to its long-term business success. FPL seeks to, at a minimum, maintain and ideally improve its overall customer value proposition.

• Major ~~Capital~~capital ~~Projects~~projects: FPL is currently engaged in a large capital expansion program and its objective is to bring these projects in on schedule and within budget. This program includes:

• modernizing its Cape Canaveral, ~~and~~ Riviera Beach and Port Everglades power plants to high-efficiency natural gas-fired units (approximately 1,200 mw ~~units~~each at Cape Canaveral and Riviera Beach and 1,280 mw at Port Everglades) to be placed in service by June 2013, ~~and~~June 2014 and mid-2016, respectively, and

• adding aat ~~total~~least of510 ~~approximately 450~~ mw ~~to 490 mw~~ of capacity at its existing nuclear units at St. Lucie and Turkey Point, to be placed in service by the spring of 2013, ~~and~~of which approximately 395 mw are in service as of December 31, 2012.

• petitioning the FPSC in November 2011 to modernize its Port Everglades power plant to a high-efficiency natural gas-fired 1,280 mw unit which, if approved, is expected to be in service in 2016 and cost approximately $1.2 billion.44

•Table Rate Case: In January 2012, FPL filed a formal notification with the FPSC indicating its intent to initiate a base rate proceeding. The notification stated that, based on preliminary estimates, FPL expects to request a base rate increase of approximately $525 million effective January 2013 and an additional base rate increase of approximately $170 million annually commencing when the modernized Cape Canaveral plant becomes operational, which is expected to occur in June 2013.Contents

•

Natural gas pipeline: In December 2012, FPL issued an RFP to build a third major natural gas pipeline to serve peninsular Florida. The proposed new pipeline will have an upstream segment which originates at an existing hub in Western Alabama and ends at a new hub to be built in Central Florida. The downstream segment will originate at the new hub in Central Florida and connect with FPL's system in Martin County. FPL plans to propose a self-build option for the downstream segment of the pipeline, which, if selected, is expected to be built, owned and operated by a FERC-regulated affiliate. The FERC-regulated affiliate is prepared to consider investing in support of a selected upstream segment to facilitate timely construction. The bids are due in April 2013, with the winning proposal(s) expected to be selected by the end of June 2013. The pipeline will be subject to regulatory approvals.

At NEER:

• Maintaining excellence in day-to-day operations.: NEER has developed a track record of generally running its facilities reliably and cost-effectively. The company seeks to, at minimum, maintain and ideally improve its operating performance.

• ~~Wind~~Solar: Add ~~approximately~~nearly 1900 mw of new solar generation by 2016,~~150~~ including the completion of the construction of the Spain solar projects in 2013 (see Note 13 - Commitments for recent changes in law that could negatively affect the Spain solar projects), the 250 mw toGenesis 1solar project in California,~~500~~ the 550 mw ofDesert ~~new~~Sunlight ~~U.S.~~solar ~~wind~~project ~~generation~~in California, in ~~2012~~which NEER has a 50% equity investment, and ~~600~~the 250 mw ofMcCoy ~~new~~solar ~~Canadian~~PV ~~wind~~project ~~generation~~located ~~between~~in ~~2012~~the ~~and~~Mojave ~~2015,~~Desert near the Genesis and Desert Sunlight solar projects.

• ~~Solar~~Wind: Add approximately ~~935~~600 mw of new ~~solar~~Canadian wind generation ~~during~~by the ~~period~~end ~~2012~~of ~~through~~2015 ~~2016,~~and ~~including~~175 ~~the 250~~ mw ~~Genesis~~of ~~solar~~new ~~project in California, the 99~~U.8S. mwwind ~~Spain~~generation ~~solar project, the 550 mw Desert Sunlight solar project~~ in ~~California,~~2013. inContinue ~~which~~to ~~NEER~~develop ~~has~~ a ~~50%~~backlog ~~equity~~for ~~investment,~~U.S. ~~and~~wind ~~the~~for ~~250~~2013 mwand ~~McCoy~~2014 ~~solar~~in PVlight ~~project~~of ~~located in~~ the ~~Mojave~~PTC ~~Desert~~extension ~~near~~under the ~~Genesis~~Taxpayer ~~and~~Relief ~~Desert Sunlight solar projects~~Act.

At Lone Star,: ~~which~~Achieve iscommercial inoperations by the ~~process~~end of ~~constructing~~the first quarter of 2013 on approximately ~~320~~330 miles of transmission lines and other associated facilities in Texas:.

• Construction: Achieve commercial operations by the end of the first quarter of 2013.

• Rate Case: In January 2012, Lone Star filed a petition with the PUCT requesting, among other things, interim rates which would take effect when Lone Star's first substation is placed in service, currently projected to be in 2012, and final rates when the transmission lines are energized. If approved, based on the expected in-service dates, the requested rates would result in annual revenues of approximately $14 million in 2012 and $110 million in 2013.

In addition, NEE and FPL devote effort to numerous other initiatives designed to support their long-term growth and development. There can be no guarantees that NEE or FPL will be successful in attaining their goals with respect to any of these initiatives.

For additional information on certain of the above matters, see Item 1. Business.

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RESULTS OF OPERATIONS

NEE’s net income for ~~2011~~2012 was $1.9291 billion, compared to $1.9692 billion in ~~2010~~2011 and $1.6196 billion in ~~2009~~2010. The decrease in ~~NEE’s~~2012 ~~2011~~ net income was primarily ~~driven~~due byto the absence of certain income tax benefits at Corporate and Other recorded in 2011 and lower ~~earnings~~results at NEER, partly offset by improved results at FPL ~~and income tax benefits at Corporate and Other~~. The ~~increase~~decrease in NEE'’s ~~2010~~2011 net income was primarily driven by ~~improved~~lower ~~results~~earnings at ~~FPL~~NEER, ~~and~~partly offset by ~~net~~improved ~~unrealized~~results ~~mark-to-market~~at ~~after-tax~~FPL ~~gains~~and ~~from~~income ~~non-qualifying~~tax ~~hedges~~benefits at ~~NEER~~Corporate and Other.

NEE's effective income tax rate for all periods presented reflects PTCs for wind projects at NEER and deferred income tax benefits associated with convertible ITCs under the American Recovery and Reinvestment Act of 2009 (Recovery Act). PTCs and deferred income tax benefits associated with convertible ITCs can significantly affect NEE's effective income tax rate depending on the amount of pretax income. PTCs can be significantly affected by wind generation and by the ~~expiration~~roll off of PTCs on certain wind projects after ten years of production (PTC roll off). See Note 1 - Income Taxes, ~~and~~Note 1 - Sale of Differential Membership Interests and Note 6. Also see Item 1. Business - NEER - Generation and Other Operations - Policy Incentives for Renewable Energy Projects, for a discussion of the Taxpayer Relief Act.

FPL: Results of Operations

FPL’s net income for ~~2011~~2012, ~~2010~~2011 and ~~2009~~2010 was $1,~~068~~240 million, $~~945~~1,068 million and $~~831~~945 million, respectively, representing an increase in ~~2011~~2012 of $~~123~~172 million and an increase in ~~2010~~2011 of $~~114~~123 million. FPL obtains its operating revenues primarily from the sale of electricity to retail customers at rates established by the FPSC through base rates and cost recovery clause mechanisms.

In ~~2011~~2010 ~~and~~through ~~2010~~2012, FPL earned a regulatory ROE of 11.0%, as permitted by the 2010 rate agreement~~, and expects to earn an 11% regulatory ROE in 2012~~. In ~~2011~~2012 and in ~~2010~~2011, growth in earnings for FPL was driven by:

• investment in plant in service ~~and~~which ~~FPL's~~resulted ~~ability~~in tohigher use ~~the~~of FPL's surplus depreciation credit, ~~and~~to earn an 11.0% regulatory ROE on its retail rate base,

• higher cost recovery clause results, and

~~partly~~• ~~offset~~ for ~~2010 by~~2012, higher AFUDC - equity.

•Beginning ~~lower~~in ~~AFUDC~~2013, -FPL's ~~equity~~allowed regulatory ROE range under the 2012 rate agreement is 9.50% to 11.50%.

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FPL's operating revenues consisted of the following:

	Years Ended December 31,
	2011			2010		2009
	2012			2011		2010
				(millions)
Retail base	$	4,~~217~~246		$	4,~~190~~217	$	34,~~828~~190
Fuel cost recovery	43,~~416~~815			4,~~090~~416		54,~~982~~090
Net deferral of retail fuel revenues	—(44		)	—		~~(356~~—		)
Net repayment of previously deferred retail fuel revenues	—			~~356~~—		—356
Other cost recovery clauses and pass-through costs, net of any deferrals	1,~~751~~858			1,~~638~~751		1,~~840~~638
Other, primarily pole attachment rentals, transmission and wholesale sales and customer-related fees	~~229~~239			~~211~~229		~~197~~211
Total	$	10,~~613~~114		$	10,~~485~~613	$	1110,~~491~~485

Retail Base

As permitted by the 2010 rate agreement, in 2012 and 2011, FPL collected approximately $52 million and $101 million, respectively, in additional retail base revenues through the capacity clause related to the placement in service of WCEC Unit No. 3 in May 2011. InAlso ~~addition,~~included ain 2012 retail base ~~rate~~revenues ~~increase~~were ~~pursuant~~approximately to$18 anmillion ~~FPSC~~of ~~order~~unbilled ~~which~~revenues ~~became~~associated ~~effective~~with ~~March 1,~~new ~~2010~~retail base rates under the 2012 rate agreement (see FPSC Rate Orders below), ~~increased~~which ~~retail~~were billed in 2013. Additional base revenues byof approximately $822 million ~~and~~were ~~$68~~collected ~~million~~ in ~~2011~~2012 ~~and~~related ~~2010,~~to ~~respectively,~~new ~~and~~nuclear ~~retail~~capacity ~~base~~which ~~revenues~~was ~~increased~~placed in ~~2010~~service in 2011, as permitted by the FPSC's nuclear cost recovery rule. In 2013, FPL expects to collect approximately $~~196~~245 million ~~resulting~~of ~~from~~additional ~~WCEC~~base ~~Unit~~revenues ~~Nos. 1~~related ~~and~~to 2new nuclear capacity of approximately 365 mw, which was placed in service in ~~2009~~2012. A base rate increase pursuant to the 2010 FPSC rate order increased 2011 retail base revenues by approximately $8 million.

FPSC Rate ~~Order~~Orders

~~Effective~~During ~~March 1,~~the period 2010, ~~pursuant~~ to ~~the FPSC rate order~~2012, ~~new~~FPL's ~~retail~~ base rates ~~for FPL~~ were established, ~~resulting~~by in an increase in retail base revenues of approximately $75 million on an annualized basis. The FPSC rate order also established a regulatory ROE of 10.0% with a range of plus or minus 100 basis points and an adjusted regulatory equity ratio of 59.1%. It also shifted certain costs from retail base rates to the ~~capacity~~2010 ~~clause. In addition, the~~ FPSC rate order directed FPL to reduce depreciation expense (surplus depreciation credit) over the 2010 to 2013 period related to a depreciation reserve surplus. Subsequently, the principal parties in FPL's 2009 rate case signed the 2010 rate agreement and, ~~in February 2011,~~ the ~~FPSC issued a final order approving the~~ 2010 rate agreement~~. Key~~ ~~elements of that rate agreement~~which, ~~which~~among isother ~~effective through December 31~~things, ~~2012,~~during ~~are~~this ~~as follows~~period:

• ~~Subject~~provided toan ~~the~~approximately ~~provisions~~$75 ofmillion ~~the~~base ~~2010~~ rate ~~agreement,~~increase ~~retail~~on ~~base~~an ~~rates~~annualized ~~are~~basis, ~~effectively~~effective ~~frozen~~March ~~through~~1, ~~the~~2010, ~~end of 2012.~~and

• ~~Incremental~~permitted ~~cost~~FPL ~~recovery~~to ~~through~~vary ~~FPL’s~~the ~~capacity~~amount ~~clause~~of ~~for~~surplus ~~the~~depreciation ~~new~~credit ~~combined-cycle~~taken ~~natural~~in ~~gas~~any ~~unit~~calendar atyear ~~WCEC~~up ~~Unit~~to ~~No.~~certain 3limits, ~~which~~provided ~~was~~that ~~placed~~ in ~~service~~any inyear ~~May~~of ~~2011,~~the is2010 ~~permitted~~rate upagreement FPL was required to ~~the~~use ~~amount~~enough ofsurplus ~~the~~depreciation ~~projected~~credit ~~annual~~to ~~fuel~~maintain ~~savings~~an ~~for~~earned ~~customers~~regulatory ~~during~~ROE within the ~~term~~range of ~~the~~9.0% ~~2010~~- ~~rate agreement~~11.0%.

•During ~~Future~~2012, ~~storm~~2011 ~~restoration~~and ~~costs~~2010, ~~would~~FPL berecorded ~~recoverable~~$480 onmillion, an$187 ~~accelerated~~million ~~basis~~and ~~beginning~~$4 60million ~~days~~of ~~from~~surplus depreciation credit. See Item 1. Business - FPL - FPL Regulation for additional information on the ~~filing~~2010 ofFPSC arate ~~cost~~order ~~recovery~~and the 2010 rate agreement.

45Effective January 2013 through December 2016, FPL's base rates will be determined by the 2012 rate agreement, which was approved by the FPSC in January 2013. Key elements of the 2012 rate agreement include, among other things, the following:


•	New retail base rates and charges were established in January 2013 resulting in an increase in retail base revenues of $350 million on an annualized basis.


•	FPL's allowed regulatory ROE will be 10.50%, with a range of plus or minus 100 basis points. If FPL's earned regulatory ROE falls below 9.50%, FPL may seek retail base rate relief. If the earned regulatory ROE rises above 11.50%, any party to the 2012 rate agreement other than FPL may seek a review of FPL's retail base rates.


•	Retail base rates will be increased by the annualized base revenue requirements for FPL's three modernization projects (Cape Canaveral, Riviera Beach and Port Everglades) as each of the modernized power plants becomes operational (which is expected by June 2013, June 2014 and mid-2016, respectively).


•	Cost recovery of WCEC Unit No. 3, which was placed in service in May 2011, will continue to occur through the capacity clause; however, such recovery will not be limited to the projected annual fuel cost savings as was the case in the previous rate agreement.

•

Subject to certain conditions, FPL must amortize, over the term of the 2012 rate agreement, a depreciation reserve surplus remaining at the end of 2012 under the 2010 rate order (approximately $224 million) and may amortize a portion of FPL's fossil dismantlement reserve up to a maximum of $176 million (collectively, the reserve), provided that in any year of the 2012 rate agreement, FPL must amortize at least enough reserve to maintain a 9.50% earned regulatory ROE but may not amortize any reserve that would result in an earned regulatory ROE in excess of 11.50%. The reserve will be amortized as a reduction of regulatory liabilities - accrued asset removal costs on NEE's and FPL's consolidated balance sheets.

•

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~~petition,~~On ~~but~~February ~~capped~~7, at2013, anthe ~~amount~~Office ~~that produces a surcharge~~ of noPublic ~~more~~Counsel ~~than~~filed $4a ~~for~~notice ~~every 1,000 kwh~~ of ~~usage~~appeal onto ~~residential bills during~~ the ~~first~~Florida 12Supreme ~~months~~Court of ~~cost recovery. Any additional costs would be eligible for recovery in subsequent years. If storm restoration costs exceed $800 million in any given calendar year, FPL may request an increase to~~ the $4FPSC's ~~surcharge~~final toorder ~~recover~~regarding the ~~amount~~2012 ~~above~~rate ~~$800 million~~agreement.

• If FPL’s earned regulatory ROE falls below 9%, FPL may seek retail base rate relief. If FPL’s earned regulatory ROE rises above 11%, any party to the 2010 rate agreement may seek a reduction in FPL’s retail base rates. In determining the regulatory ROE for all purposes under the 2010 rate agreement, earnings will be calculated on an actual, non-weather-adjusted basis.

• FPL can vary the amount of surplus depreciation credit taken in any calendar year up to a cap in 2010 of $267 million, a cap in subsequent years of $267 million plus the amount of any unused portion from prior years, and a total cap of $776 million (surplus depreciation credit cap) over the course of the 2010 rate agreement, provided that in any year of the 2010 rate agreement, FPL must use at least enough surplus depreciation credit to maintain a 9% earned regulatory ROE but may not use any amount of surplus depreciation credit that would result in an earned regulatory ROE in excess of 11%. In 2010 and 2011, FPL used a total of $191 million of surplus depreciation credit; $585 million of the surplus depreciation credit cap remains available for use in 2012.

Under the terms of the 2005 rate agreement, which was in effect from January 1, 2006 through February 28, 2010, retail base rates did not increase except to allow recovery of the revenue requirements of FPL’s three power plants that achieved commercial operation during the term of the 2005 rate agreement: Turkey Point Unit No. 5 in 2007 and WCEC Units Nos. 1 and 2 in 2009. Under the terms of the 2005 rate agreement, FPL’s electric property depreciation rates were based upon the comprehensive depreciation studies it filed with the FPSC in March 2005; however, FPL reduced depreciation on its plant in service by $125 million each year as allowed by the 2005 rate agreement. The 2005 rate agreement also provided for a revenue sharing mechanism, whereby revenues from retail base operations in excess of certain thresholds would be shared with customers. During the term of the 2005 rate agreement, FPL’s revenues did not exceed the thresholds.

Retail Customer Usage and Growth

~~For~~In each of the ~~year~~years ended December 31, 2012 and 2011, FPL experienced a 2.0% decrease in average usage per retail customer, ~~reflecting~~primarily ~~weather~~due ~~and~~to ~~other~~weather ~~factors,~~conditions ~~which~~partly ~~decreased~~offset ~~retail~~in ~~base~~2012 ~~revenues~~ by ~~approximately~~higher ~~$107~~non-weather ~~million. For~~related ~~the year ended December 31, 2010, FPL experienced a 1.7% increase in~~ usage per retail customer, ~~reflecting weather and other factors,~~ which ~~increased~~decreased retail base revenues by approximately $7990 million and $107 million, respectively. The usage per retail customer data for the year ended December 31, 2011 includes three extra days of sales after adjusting for a change from a fiscal month to a calendar month. AtFor both years ended December 31, ~~2011,~~2012 ~~inactive accounts (accounts with installed meters without corresponding customer names)~~ and ~~low-usage customers (customers using less than 200 kwh per month)~~2011, ~~both~~FPL ~~measures~~experienced ofa ~~empty homes, were approximately 5~~0.~~8% and 1.~~6% ~~less,~~increase ~~respectively,~~in ~~than~~the ~~they~~average ~~had~~number ~~been~~of atcustomer ~~December 31~~accounts, ~~2010. Non-weather~~increasing ~~related usage per~~ retail ~~customer~~base ~~began~~revenues toby ~~decline~~approximately in$27 ~~the~~million ~~mid-2000s~~ and ~~this~~$25 ~~decline~~million, ~~intensified in the 2007 to 2009 period~~respectively. ~~The rate of decline in non-weather related usage per retail customer moderated in 2010 and 2011.~~

~~For~~Non-weather ~~the~~related ~~year~~usage ~~ended~~per ~~December 31,~~retail ~~2011,~~customer ~~FPL~~increased ~~experienced~~in a2012 ~~0.6%~~mirroring ~~increase~~the continued gradual improvements in the ~~average~~Florida ~~number~~economy. As of ~~customer~~December ~~accounts~~2012, ~~increasing~~Florida ~~retail~~has ~~base~~experienced ~~revenues~~29 byconsecutive ~~approximately~~months ~~$25~~of ~~million,~~positive ~~compared~~year-over-year toemployment growth. The state's unemployment rate has fallen from a 0high of 11.54% ~~increase~~ in ~~customer~~January ~~accounts~~2010 to 8.0% in ~~2010,~~December ~~which~~2012. The ~~increased~~number ~~2010~~of ~~retail~~empty ~~base~~homes ~~revenues~~in byFPL's ~~$19~~service ~~million~~area is also gradually declining. ~~Positive~~The ~~customer~~number ~~account~~of ~~growth~~inactive meters (premises where electric service is ~~projected~~available tobut ~~continue~~no customer is requesting electric service) declined by 6.4% in 2012, ~~although~~while the ~~rate~~number of ~~growth~~low isusage ~~projected~~accounts todecreased beby ~~below~~1.3%. At ~~FPL’s~~the ~~average~~same ~~rate~~time, higher energy efficiencies are offsetting some of ~~1.5%~~the ~~over~~increase in non-weather related usage per retail customer resulting from the ~~last~~improved 10economic ~~years~~outlook.

FPL ~~believes~~has ~~that~~now ~~the~~experienced ~~economic~~three ~~slowdown~~consecutive ~~and~~years ~~the downturn in the housing market that have affected the country and the state~~ of ~~Florida~~moderately ~~have~~positive ~~contributed~~growth ~~to the slowdown~~ in ~~customer growth and to~~ the ~~decline~~average innumber ~~non-weather~~of ~~related usage per retail~~ customer accounts. ~~The~~Some ~~unemployment~~improvement ~~rate~~ in ~~Florida was 9.9% and 12.0% in December 2011 and 2010, respectively;~~ the ~~December 2011~~ rate ~~is the lowest since April 2009. A portion~~ of ~~the decline in non-weather related usage per retail~~ customer ~~may~~growth ~~also be related to federal and state energy efficiency standards. FPL~~ is ~~unable~~expected toin ~~predict~~2013, ~~whether~~assuming orno ~~when~~significant ~~growth~~decline in ~~customers~~the ~~and~~overall ~~non-weather~~state ~~related~~of ~~customer~~Florida's ~~usage might return to previous trends~~economy.

Cost Recovery Clauses

Revenues from fuel and other cost recovery clauses and pass-through costs, such as franchise fees, revenue taxes and storm-related surcharges, are largely a pass-through of costs. Such revenues also include a return on investment allowed to be recovered through the cost recovery clauses on certain assets, primarily related to nuclear capacity, solar and environmental projects. In ~~2011~~2012, ~~2010~~2011 and ~~2009~~2010, cost recovery clauses contributed $~~108~~160 million, $75108 million, and $4175 million, respectively, to FPL’s net income. The increase in ~~2011~~2012 ~~and~~in ~~2010~~ cost recovery clause results iswas primarily due to a return related to additional nuclear capacity investments, while the increase in 2011 reflects a return related to additional solar, environmental and nuclear capacity ~~expenditures~~investments. In ~~2012~~2013, it is expected that earnings from cost recovery clauses will ~~contribute~~decline ~~higher~~primarily ~~earnings for FPL~~ as a result of ~~additional~~the collection in 2013 of retail base revenues related to new nuclear capacity ~~expenditures~~which was placed in service in 2012 (see Retail Base above). Fluctuations in fuel cost recovery revenues are primarily driven by changes in fuel and energy charges which are included in fuel, purchased power and interchange expense in the consolidated statements of income, as well as by changes in energy sales. Fluctuations in revenues from other cost recovery clauses and pass-through costs are primarily driven by changes in storm-related surcharges, capacity charges, franchise fee costs, the impact of changes in O&M and depreciation expenses on the underlying cost recovery clause, investment in solar and environmental projects, investment in nuclear capacity until such capacity goes into service and is recovered in base rates, pre-construction costs associated with the development of two additional nuclear units at the Turkey Point site and changes in energy sales. Capacity charges and franchise fee costs are included in fuel, purchased power and interchange and taxes other than income taxes and other, respectively, in the consolidated statements of income. Underrecovery or overrecovery of cost recovery clause and other pass-through costs can significantly affect NextEra Energy's and FPL's operating cash flows. The change from December 31, 2011 to December 31, 2012 in deferred clause and franchise expenses and in deferred clause and franchise revenues was approximately $129 million and positively affected NEE’s and FPL’s cash flows from operating activities for the year ended December 31, 2012.

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Risk Management Fuel Procurement Program

FPL uses a risk management fuel procurement program which was approved by the FPSC. The FPSC reviews the program activities and results for prudence on an annual basis as part of its annual review of fuel costs. The program is intended to manage fuel price volatility by locking in fuel prices for a portion of FPL’s fuel requirements. The current regulatory asset for the change in fair value of derivative instruments used in the fuel procurement program ~~amounted~~was to approximately $~~502~~16 million and $~~236~~502 million at December 31, ~~2011~~2012 and ~~2010~~2011, respectively.

InThe ~~2010,~~decrease ~~pursuant~~in tofuel ancost ~~FPSC~~recovery ~~order,~~revenues ~~FPL was required to refund~~ in ~~the~~2012 ~~form~~is ofprimarily adue ~~one-time credit~~ to ~~retail~~a ~~customers’~~lower ~~bills~~average ~~the 2009 year-end estimated~~ fuel ~~overrecovery;~~factor ~~during the first quarter~~ of ~~2010,~~ approximately $~~404~~558 million ~~was~~and ~~refunded~~lower toenergy ~~retail~~sales ~~customers. At~~of ~~December 31, 2009, approximately~~ $~~356~~43 million. The ofincrease ~~retail~~in fuel ~~revenues~~cost ~~were~~recovery ~~overrecovered, the reversal of which is reflected in the net repayment of previously deferred retail fuel~~ revenues ~~caption included~~ in ~~the~~2011 ~~table~~reflects ~~above. The difference between~~ the ~~refund~~absence ~~and~~of ~~the~~a ~~December 31,~~$404 ~~2009~~million ~~overrecovery~~one-time ~~was~~credit ~~collected~~to ~~from~~ retail customers’ inbills ~~2011. The~~made ~~increase~~ in ~~fuel~~2010 ~~revenues~~pursuant into ~~2011~~an ~~reflects~~FPSC ~~the~~order, ~~absence of the $404 million refund~~ partly offset by approximately $41 million related to lower energy sales and $37 million related to a lower average fuel factor. The decrease in fuel revenues in 2010 reflects the $404 million refund and approximately $1,573 million related to a lower average fuel factor, partly offset by $85 million attributable to higher energy sales. The decrease from December 31, 2010 to December 31, 2011 in deferred clause and franchise expenses and in deferred clause and franchise revenues was approximately $181 million and positively affected NEE’s and FPL’s cash flows from operating activities for the year ended December 31, 2011.

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Other

The ~~decrease~~increase in revenues from other cost recovery clauses and pass-through costs in ~~2010~~2012 is primarily due to ~~lower~~higher revenues associated with the FPSC’s nuclear cost recovery rule ~~and~~reflective ~~lower~~of ~~revenues related to franchise and revenue taxes, partly offset by~~ higher ~~environmental~~earnings ~~clause~~on ~~revenues. The decline in 2010 in revenues associated with the nuclear cost recovery rule is primarily due to lower spending related to the development of the two~~ additional nuclear ~~units~~capacity ~~at the Turkey Point site~~investments. The ~~decline in 2010 revenues related to franchise and revenue taxes reflects the decline in fuel revenues. The~~ nuclear cost recovery rule provides for the recovery of prudently incurred pre-construction costs and carrying charges (equal to a fixed pretax AFUDC rate) on construction costs and a return on investment for new nuclear capacity through levelized charges under the capacity clause. The same rule provides for the recovery of construction costs, once property related to the new nuclear capacity goes into service, through a base rate increase effective beginning the following January.

Other Items Impacting FPL Results

Fuel, Purchased Power and Interchange

The major components of FPL's fuel, purchased power and interchange expense are as follows:

	Years Ended December 31,
	2011		2010			2009
	2012			2011				2010
			~~(millions)~~	(millions)
Fuel and energy charges during the period	$	43,~~237~~657	$	~~4,714~~$	4,237	$	~~5,425~~	$	4,714
Net collection of previously deferred retail fuel costs	103	~~159~~		—159			~~256~~	—
Net deferral of retail fuel costs	—	—		~~(276~~—	)		—	(276		)
Other, primarily capacity charges, net of any capacity deferral	505	~~581~~		~~544~~581			~~539~~	544
Total	$	4,~~977~~265	$	~~4,982~~$	4,977	$	~~6,220~~	$	4,982

The decrease in fuel and energy charges in ~~2011~~2012 reflects lower fuel and energy prices of $~~415~~526 million and lower energy sales of $6254 million. The decrease in fuel and energy charges in ~~2010~~2011 reflects lower fuel and energy prices of approximately $~~822~~415 million, ~~partly~~and ~~offset~~lower byenergy ~~approximately~~sales of $~~111~~62 million ~~attributable to higher energy sales~~.

O&M Expenses

FPL’'s O&M expenses increased $7974 million in ~~2011~~2012 primarily due to higher employee-related and insurance costs, as well as higher fossil plant outage costs primarily due to timing. Also, FPL's O&M expenses in 2012 reflect higher cost recovery clause costs of approximately $21 million, which did not significantly affect net income. FPL’s O&M expenses increased $79 million in 2011 primarily due to higher cost recovery clause costs.

FPL’s O&M expenses increased $124 million in 2010 reflecting an approximately $20 million charge for workforce reductions and higher nuclear and fossil generation, distribution, transmission and nuclear insurance costs of $34 million, $29 million, $16 million, $8 million and $12 million, respectively, partly offset by lower customer service costs, primarily due to lower uncollectible accounts, of $13 million. The increase in nuclear generation costs is primarily due to higher maintenance costs and reflects a reimbursement in 2009 of prior years’ costs of approximately $10 million related to a spent nuclear fuel litigation settlement agreement with the U.S. Government. The increase in fossil generation costs is primarily related to WCEC Units Nos. 1 and 2, which units were placed in service in the second half of 2009, and higher plant overhaul costs. The increase in distribution and transmission costs reflects higher restoration and tree trimming costs. Other changes in O&M expenses were primarily driven by pass-through costs which did not significantly affect net income.

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Depreciation and Amortization Expense

The major components of FPL’s depreciation and amortization expense are as follows:

	Years Ended December 31,
	2011			2010			2009
	2012			2011			2010
				(millions)
$125 million annual reduction under the 2005 rate agreement	$	—		$	—		$	(125	)
Surplus depreciation credit recorded under the 2010 rate agreement	$	(480	)	$	(187	)	$	(4	)
Surplus depreciation credit recorded under the 2010 rate agreement	(187		)	(4		)	—
Other depreciation and amortization recovered under base rates	1,013			944			891
Other depreciation and amortization recovered under base rates	944			891			942
Depreciation and amortization recovered under cost recovery clauses and securitized storm-recovery cost amortization	126			41			121
Depreciation and amortization recovered under cost recovery clauses and securitized storm-recovery cost amortization	41			121			280
Total	$	659		$	798		$	1,008
Total	$	798		$	1,008		$	1,097

~~From 2002 through 2009, FPL recorded the $125 million annual reduction in depreciation and amortization expense that was approved by the FPSC in previous rate orders.~~ Under the terms of the 2010 rate agreement, FPL ~~can~~could vary the amount of surplus depreciation credit taken in any calendar year up to a cap in 2010 of $267 million, a cap in subsequent years of $267 million plus the amount of any unused portion from prior years, and a cap of $776 million ~~(surplus depreciation credit cap)~~ over the 2010 to 2012 period. InSee ~~any~~FPSC ~~year~~Rate ofOrders ~~the~~above ~~2010~~for ~~rate~~additional ~~agreement~~information ~~FPL~~on ~~must~~the use atof ~~least~~the ~~enough~~remaining ~~surplus~~ depreciation ~~credit~~reserve tosurplus. The ~~maintain~~increase ain ~~9% earned regulatory ROE but may not use any amount of~~ surplus depreciation credit ~~that~~recorded ~~would~~under ~~result~~the in2010 anrate ~~earned~~agreement ~~regulatory ROE~~ in ~~excess~~2012 ofand ~~11%. As of December 31,~~ 2011, ~~approximately~~is ~~$585~~primarily ~~million~~a result of ~~the~~increased ~~surplus~~plant ~~depreciation~~investment ~~credit~~and ~~cap~~enabled ~~remains~~FPL ~~available~~to ~~for~~earn ~~use~~its in11.0% ~~2012~~regulatory ROE. The increase in other depreciation and amortization expense recovered under base rates in 2012 and 2011 is primarily due to higher plant in service balances. The ~~decline~~increase in ~~other~~ depreciation and amortization ~~expense~~ recovered under ~~base~~cost ~~rates~~recovery clauses and securitized storm-recovery cost amortization in ~~2010~~2012 is primarily due to ~~lower~~true ~~depreciation~~ups ~~rates~~of asprior ayear ~~result~~recoveries ofunder the FPSC's ~~rate~~nuclear ~~order,~~cost ~~partly~~recovery ~~offset by higher plant in service balances related to WCEC Units Nos. 1 and 2~~rule, ~~which~~while ~~were~~the ~~placed in service in 2009. The~~ decrease in such depreciation ~~and amortization recovered under cost recovery clauses and securitized storm-recovery cost amortization~~ in 2011 ~~and 2010~~ is primarily due to lower depreciation and amortization under the FPSC's nuclear cost recovery rule. See Note 1 - Electric Plant, Depreciation and Amortization.

Taxes Other Than Income Taxes and Other

Taxes other than income taxes and other ~~increased~~decreased $373 million in ~~2011~~2012 primarily due to ~~higher~~lower franchise fees and revenue taxes (collectively, $31 million), both of which are pass-through costs and reflect the ~~increase~~decrease in fuel cost recovery clause revenues, ~~from~~partly ~~fuel~~offset ~~and~~by ~~other~~higher ~~cost~~property ~~recovery~~taxes ~~clauses~~of ~~and~~$28 ~~pass-through~~million ~~costs. Taxes~~reflecting ~~other~~growth ~~than~~in ~~income~~plant ~~taxes~~in ~~and~~service ~~other~~balances. The ~~decreased~~increase byin 2011 of $7137 million inwas ~~2010~~ primarily due to ~~changes~~higher in franchise fees and revenue taxes~~. In addition~~, ~~taxes~~reflecting ~~other~~the ~~than~~increase ~~income~~in ~~taxes~~revenues from fuel and other incost ~~2011~~recovery clauses and ~~2010~~pass-through ~~reflect~~costs, and higher property taxes of $5 million ~~and~~reflecting ~~$34 million, respectively, primarily due to~~ growth in plant in service balances ~~and, in 2010, a higher average property tax rate,~~ partly offset ~~in 2011~~ by a lower average property tax rate.

Interest Expense

The increase in interest expense in 2011 is primarily due to higher average interest rates and higher average debt balances. The increase in interest expense in 2010 is primarily due to higher average debt balances, as well as lower AFUDC - debt. Interest expense on storm-recovery bonds, as well as certain other interest expense (collectively, clause interest), are essentially pass-through amounts and do not significantly affect net income, as the clause interest is recovered either under cost recovery clause mechanisms or through a storm-recovery bond surcharge. Clause interest for 2011, 2010 and 2009 amounted to approximately $65 million, $56 million, and $45 million, respectively. The increase in clause interest in 2011 and 2010 is primarily due to higher interest associated with solar, environmental and nuclear capacity expenditures.

AFUDC - Equity

The decrease in AFUDC - equity in 2010 is primarily attributable to WCEC Units Nos. 1 and 2, which units commenced commercial operation in 2009, partly offset by additional AFUDC - equity on WCEC Unit No. 3. The decrease in AFUDC - equity in 2010 also reflects a decline, effective April 1, 2010, in the AFUDC rate from 7.41% to 6.41%, as approved by the FPSC.

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Interest Expense

The increase in interest expense in 2012 is primarily due to higher average debt balances, partly offset by lower average interest rates, lower interest expense on customer deposits reflecting lower rates and lower average customer deposit balances and higher AFUDC - debt. The change in AFUDC - debt is due to the same factors as described below in AFUDC - equity. The increase in interest expense in 2011 is primarily due to higher average interest rates and higher average debt balances. Interest expense on storm-recovery bonds, as well as certain other interest expense on clause-recoverable investments (collectively, clause interest), are essentially pass-through amounts and do not significantly affect net income, as the clause interest is recovered either under cost recovery clause mechanisms or through a storm-recovery bond surcharge. Clause interest for 2012, 2011 and 2010 amounted to approximately $81 million, $65 million and $56 million, respectively. The increase in clause interest in 2012 and 2011 is primarily due to higher interest associated with nuclear capacity and environmental investments and, in 2011, also reflects higher interest associated with solar investments.

AFUDC - Equity

The increase in AFUDC - equity in 2012 is primarily due to additional AFUDC - equity on the Cape Canaveral and Riviera Beach modernization projects, partly offset by the absence of AFUDC - equity on WCEC Unit No. 3, which was placed in service in May 2011.

NEER: Results of Operations

NEER’s net income for ~~2011~~2012, ~~2010~~2011 and ~~2009~~2010 was $~~774~~687 million, $~~980~~774 million and $~~759~~980 million, respectively, resulting in a decrease in ~~2011~~2012 of $~~206~~87 million and ana ~~increase~~decrease in ~~2010~~2011 of $~~221~~206 million. The primary drivers, on an after-tax basis, of these ~~changes~~decreases were as follows:

	Increase (Decrease)From Prior Period
	Years EndedDecember 31,
	2011				2010
	2012					2011
	(millions)
New investments(a)	$	~~(26~~91	)		$	45$	(26	)
Existing assets(a)	26				54
Existing assets:(a)
Gas infrastructure(b)	23				23
Wind	(86			)		96
Customer supply and proprietary power and gas trading businesses(b)	(92		)		(25		)
Merchant	(59			)		(93		)
Asset sales	(18		)		7
Contracted	(33			)		23
Impairment charges	(20		)		(11		)
Total existing assets	(178			)		26
Interest expense, differential membership costs and other	(14		)		(85		)
Gas infrastructure(b)	24					23
Change in unrealized mark-to-market non-qualifying hedge activity(c)(d)	17				196
Customer supply and proprietary power and gas trading businesses(b)	44					(92		)
Loss on sale of natural gas-fired generating assets(e)	(92		)		—
Asset sales and restructuring activities	20					(18		)
Change in OTTI losses on securities held in nuclear decommissioning funds, net of OTTI reversals(d)	(10		)		17
Impairment charges	31					(20		)
Net income increase (decrease)	$	(206	)		$	221
Interest expense, differential membership costs and other	(18			)		(14		)
Change in unrealized mark-to-market non-qualifying hedge activity(c)(d)	(230			)		17
Loss on sale of natural gas-fired generating assets(e)	92					(92		)
Change in OTTI losses on securities held in nuclear decommissioning funds, net of OTTI reversals(d)	37					(10		)
Net income decrease	$	(87		)		$	(206	)

______________________

(a)

Includes PTCs and state ITCs on wind projects and, for new investments, deferred income tax and other benefits associated with convertible ITCs (see Note 1 -Electric Plant, Depreciation and Amortization, Note 1 - Income Taxes, Note 1 - Sale of Differential Membership Interests and Note 6) but does not include allocation of interest expense or corporate general and administrative expenses. Results from new projects are included in new investments during the first twelve months of operation. A project's results are included in existing assets beginning with the thirteenth month of operation.


(b)	Does not include allocation of interest expense or corporate general and administrative expenses.


(c)	See Note 3 and Overview related to derivative instruments.


(d)	See table in Overview for additional detail.


(e)	See Note 4 - Nonrecurring Fair Value Measurements and Overview for additional information.

New Investments

Results from new investments for the years ended December 31, 2011, 2010 and 2009 include approximately $1 million, $66 million and $87 million, respectively, of deferred tax benefits associated with convertible ITCs. In ~~addition~~2012, an after-tax benefit associated with convertible ITCs of approximately $34 million was recorded in 2011 from the sale of membership interests where the investors elected to receive the convertible ITCs related to the underlying wind projects; the pretax amount of such benefit was recorded in taxes other than income taxes and other in NEE's consolidated statements of income for the year ended December 31, 2011. Results from new investments in 2011 also reflect lower state ITCs partly offset by the addition of approximately 1,130 mw of wind and 5 mw of solar generation during or after 2010. NEER’s 2010 results from new investments ~~also~~increased ~~reflect~~primarily ~~the~~due ~~addition of over 2,100 mw of wind generation during or after 2009 and a benefit related~~ to ~~state ITCs.~~:

~~Existing~~• ~~Assets~~the addition of approximately 1,899 mw of wind and 45 mw of solar generation during or after 2011,

In• ~~2011,~~higher ~~results~~deferred ~~from~~income ~~NEER's~~tax ~~existing~~and ~~asset~~other ~~portfolio~~benefits ~~increased~~associated ~~$26~~with ~~million~~convertible ~~primarily~~ITCs ~~due~~of ~~to:~~$16 million, and

• ~~lower~~higher ~~after-tax~~state ~~depreciation~~ITCs ~~and amortization expense~~ of $4410 million ~~due to a change in estimate of the useful lives of certain equipment across the wind portfolio (see Note 1 - Electric Plant, Depreciation and Amortization),~~.

• higher wind results of approximately $35 million due to a higher wind resource partly offset by lower prices,

• a $30 million income tax benefit related to a valuation allowance reversal for certain state ITCs reflecting state tax planning initiatives,

• higher results of $23 million from a natural gas-fired project in California, which was sold in the fourth quarter of 2011, reflecting higher prices under a new long-term contract,

partly offset by,

• lower results at Seabrook of $91 million primarily due to extended and unplanned outages in 2011 and lower priced hedges, and

• the expiration of PTCs ($15 million) on certain projects after ten years of production.

In 2010, results from NEER's existing asset portfolio increased $54 million primarily due to:

• favorable results at Seabrook of approximately $62 million resulting primarily from the absence of an extended outage in 2010,

• favorable generation due to lower curtailments and a higher wind resource across the wind portfolio totaling $46 million,

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In 2011, results from new investments decreased primarily due to:


•	lower deferred income tax and other benefits associated with convertible ITCs of approximately $33 million, and


•	lower state ITCs of $6 million,

partly offset by,

• ~~unfavorable~~the ~~market~~addition ~~conditions~~of inapproximately ~~the~~1,130 ~~ERCOT~~mw ~~market~~of ~~affecting~~wind ~~NEER's~~and ~~merchant~~5 ~~gas~~mw ~~assets~~of ~~totaling~~solar ~~$30~~generation ~~million,~~during ~~and~~or after 2010.

•Existing ~~the absence of a tax benefit of $15 million recorded in 2009 related to a change in state tax law that extended the carry forward period of ITCs on certain wind projects.~~Assets

Wind

In 2012, results from NEER's existing wind asset portfolio decreased primarily due to:


•	PTC roll off of $37 million,


•	the absence of approximately $33 million of income tax benefits related to a valuation allowance reversal for certain state ITCs (state ITC benefit) recorded in 2011, and


•	the balance primarily attributable to a lower wind resource, partly offset by certain state tax benefits.

In 2011, results from NEER's existing wind asset portfolio increased primarily due to:


•	lower after-tax depreciation and amortization expense of $44 million due to a change in estimate of the useful lives of certain equipment across the wind portfolio (see Note 1 - Electric Plant, Depreciation and Amortization),


•	higher wind results of approximately $35 million due to a higher wind resource offset in part by lower prices, and


•	a $30 million state ITC benefit,

partly offset by


•	PTC roll off of $15 million.

Merchant

In 2012, results from NEER's existing merchant asset portfolio decreased primarily due to:


•	lower results at Seabrook of approximately $23 million primarily due to lower priced hedges,


•	lower results of $22 million in the ERCOT region, primarily due to market conditions as the prior year benefited from high market prices in August 2011, and higher O&M costs, and


•	lower hydro results of $13 million primarily due to lower priced hedges and a lower water resource.

In 2011, results from NEER's existing merchant asset portfolio decreased due to lower results at Seabrook of approximately $91 million primarily due to extended and unplanned outages in 2011 and lower priced hedges.

Contracted

In 2012, results from NEER's existing contracted asset portfolio decreased primarily due to:


•	the absence of earnings of approximately $39 million from the natural gas-fired generating plants which were sold in the fourth quarter of 2011, and


•	lower results of $19 million related to the expiration of power sales agreements at certain joint venture projects, which is reflected in equity in earnings of equity method investees in NEE's consolidated statements of income,

partly offset by,


•	higher results of $25 million at Point Beach primarily due to the absence of a planned outage which occurred in the prior year and the addition of 167 mw of capacity, approximately one-half of which was completed in June 2011 and the other half of which was completed in December 2011, partly offset by higher O&M and depreciation expenses.

In 2011, results from NEER's existing contracted asset portfolio increased primarily due to:


•	earnings on the Marcus Hook 750 facility which was moved from the merchant category in mid-2010, and


•	higher earnings from the natural gas-fired project in California, which was moved from the merchant category in mid-2010 and sold in the fourth quarter of 2011.

Gas Infrastructure

The increase in gas infrastructure results in ~~2011~~2012 ~~and~~is ~~2010~~primarily due to income from additional production, partly offset by lower gains from exiting the hedged positions on a number of future gas production opportunities. The increase in gas infrastructure results in 2011 is primarily due to higher gains from exiting the hedged positions on a number of future gas ~~drilling~~production opportunities.

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Customer Supply and Proprietary Power and Gas Trading

Results from the customer supply and proprietary power and gas trading businesses ~~decreased~~increased in 2012 primarily due to improved market conditions, favorable weather and the absence of certain losses incurred in the prior year. The decrease in 2011 byresults ~~$92~~from ~~million~~the customer supply and proprietary power and gas trading businesses is primarily due to lower full requirements results, lower power and gas trading results, lower results from the retail electricity provider reflecting the adverse effects of purchasing power at high prices during a period of hot weather in Texas in August 2011 and the absence of a gain on the sale of a power supply contract realized in 2010. In 2010, results from the customer supply and proprietary power and gas trading businesses decreased by $25 million, primarily due to lower power and gas trading results, partly offset by the gain from the sale of the power supply contract.

Asset Sales and Restructuring Activities

Asset sales and restructuring activities in ~~2011~~2012 primarily include an after-tax ~~loss~~gain of approximately $928 million ~~realized~~ on the sale of ~~natural~~a ~~gas-fired~~30 ~~generating~~mw ~~assets~~wind project, ~~which~~an ~~due~~after-tax togain ~~its~~of ~~nature~~$6 million on the sale of solar development rights and ~~significance~~a ~~was~~$5 ~~excluded~~million ~~from~~after-tax ~~adjusted~~gain ~~earnings~~related to an investment previously accounted for under the equity method in which NEER obtained a controlling interest (~~see~~controlling ~~Overview~~interest gain). Asset sales and restructuring activities in 2010 include an after-tax gain of approximately $6 million on the sale of a coal-fired project and an after-tax gain on a waste-to-energy project of approximately $12 million recorded in 2010 after the expiration of an option for the buyer to sell the project back to NEER. Asset sales in 2009 include after-tax gains of $3 million for the sale of wind development rights, $6 million for the sale of a 50 mw wind project and $2 million for the sale of an interest in the waste-to-energy project.

Impairment Charges

In 2011, NEER recorded impairment charges primarily to write down the value of certain wind and oil-fired generation assets deemed to be unrecoverable. As a result of a fair value analysis, long-lived assets held and used with a carrying amount of approximately $79 million were written down to their fair value of $28 million, resulting in an impairment charge of $51 million or $31 million after-tax. See Note 4 - Nonrecurring Fair Value Measurements. In 2010, NEER recorded impairment charges of $19 million or $11 million after-tax to write down the value of certain assets associated with the plans to repower two California wind facilities. These impairment charges are reported as a separate line item in NEE's consolidated statements of income.

Interest Expense, Differential Membership Costs and Other

In ~~both 2011 and 2010~~2012, interest expense, differential membership costs and other reflects higher ~~interest~~employee-related costs and, ~~other~~higher borrowing costs ~~due~~ to support the growth of the business ~~and,~~substantially ~~for~~offset ~~2010,~~by ~~also~~lower ~~reflects~~average interest rates and the absence of aninterest ~~$18~~expense ~~million~~on ~~income~~debt ~~tax~~associated ~~benefit~~with ~~recorded~~the innatural ~~2009~~gas-fired ~~due~~generating toplants asold ~~reduction~~in the fourth quarter of ~~previously~~2011. In ~~deferred~~2011, ~~income~~interest ~~taxes~~expense, ~~resulting~~differential ~~from~~membership ancosts ~~additional~~and ~~equity~~other ~~investment~~reflects inhigher ~~Canadian~~interest ~~operations~~and other costs due to growth of the business.

Other Factors

InSupplemental ~~addition~~ to the primary drivers of the changes in net income discussed above, the discussion below describes changes in certain line items set forth in NEE's consolidated statements of income as they relate to NEER.

Operating Revenues

Operating revenues for the year ended December 31, 2012 decreased $607 million primarily due to:


•	the absence of revenues of approximately $469 million associated with five natural gas-fired generating plants sold in the fourth quarter of 2011,


•	lower unrealized mark-to-market gains from non-qualifying hedges ($115 million in 2012 compared to $414 million in 2011), and


•	unfavorable market conditions in the ERCOT and NEPOOL regions and lower revenues at PMI (collectively, $215 million),

partly offset by,


•	higher revenues from new investments and gas infrastructure (collectively, $228 million),


•	higher revenues of $120 million at NEER's contracted nuclear facilities primarily due to the absence of a 2011 planned outage, the addition of capacity at Point Beach and favorable contract pricing.

Operating revenues for the year ended December 31, 2011 decreased $134 million primarily due to:

• lower revenues at PMI, reflecting lower trading and full requirements activity, and lower revenues from the existing asset portfolio, primarily due to the extended and unplanned outages at Seabrook and unfavorable market conditions in the NEPOOL and ERCOT regions (collectively, approximately $763 million),

partly offset by,

• higher unrealized mark-to-market gains ~~of $414 million~~ from non-qualifying hedges ($414 million in 2011 compared to $75 million of losses on such hedges in 2010), and


•	higher revenues from project additions of $132 million.

~~Operating revenues for the year ended December 31, 2010 increased $639 million primarily due to:~~51

• higher revenues at PMI and NEER's retail electricity provider (collectively, approximately $242 million),

• higher revenues in the existing asset portfolio of $206 million primarily due to the absence of an extended outage in 2010 at Seabrook,

• higher revenues from project additions of $143 million,

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• higher gas infrastructure revenues of $31 million,

• favorable generation due to lower curtailments and a higher wind resource across the wind portfolio, and

• losses of $75 million on unrealized mark-to-market non-qualifying hedge activity compared to $88 million of such losses in 2009.

Operating Expenses

Operating expenses for the year ended December 31, ~~2011~~2012 decreased $53327 million primarily due to:

• ~~lower~~the ~~fuel~~absence ~~costs~~of operating expenses of approximately $~~445~~365 million associated with five natural gas-fired generating plants sold in the fourth quarter of 2011, and

• ~~higher~~the ~~benefits~~absence ~~associated~~of ~~with~~the ~~differential~~$51 ~~membership~~million ~~interests~~impairment ofcharge ~~$102~~recorded ~~million~~in 2011,

partly offset by,

• ~~$95~~higher ~~million of~~ unrealized mark-to-market losses from non-qualifying hedges ~~compared to~~ ($~~364~~184 million ofin ~~gains~~2012 oncompared ~~such~~to ~~hedges~~$95 million in ~~2010, and~~2011).

•Operating ~~higher~~expenses ~~impairment~~for ~~charges~~the ofyear ended December 31, 2011 increased $3249 million. primarily due to:

~~Operating~~• ~~expenses~~higher ~~for~~unrealized ~~the~~mark-to-market ~~year~~losses ~~ended~~from ~~December~~non-qualifying ~~31,~~hedges ~~2010~~($95 ~~increased~~million in 2011 compared to $~~262~~364 million ~~primarily~~of ~~due~~gains ~~to:~~on such hedges in 2010), and

• higher ~~fuel~~impairment ~~costs~~charges of ~~approximately~~ $~~366~~32 million,

• higher other operating expenses of $130 million due to higher maintenance activities, impairment charges associated with the plans to repower two California wind facilities and additional wells in gas infrastructure,

• higher costs for project additions of approximately $85 million,

partly offset by,

• ~~$364~~lower ~~million~~fuel costs of ~~unrealized~~approximately ~~mark-to-market gains from non-qualifying hedges compared to~~ $60445 million ~~of such gains in 2009~~.

Interest Expense

NEER’s interest expense for the ~~years~~year ended December 31, ~~2011~~2012 ~~and~~decreased ~~2010 increased~~ $1556 million primarily due to lower average interest rates and ~~$55~~the ~~million,~~absence ~~respectively~~of interest expense on debt associated with the natural gas-fired generating plants sold in the fourth quarter of 2011. NEER’s interest expense for the year ended December 31, 2011 increased $15 million primarily due to increased borrowings to support the growth of the business, partly offset by lower average interest rates and, ~~in 2011,~~ higher interest capitalized on construction projects.

Benefits associated with differential memberships interests - net

Benefits associated with differential memberships interests - net in NEE's consolidated statements of income for the years ended December 31, 2012, 2011 and 2010 reflect benefits recognized by NEER as third-party investors received their portion of the economic attributes, including income tax attributes, of the underlying wind project, net of associated costs. See Note 1 - Basis of Presentation and Note 1 - Sale of Differential Membership Interests. For the years ended December 31, 2012 and 2011 benefits associated with differential memberships interests - net also includes $13 million and $52 million, respectively, of benefits where the investors elected to receive the convertible ITCs related to the underlying wind project.

Gains on Disposal of Assets - net

Gains on disposal of assets - net in NEE’s consolidated statements of income for the ~~year~~years ended December 31, ~~2011~~2012, ~~2010~~2011 and ~~2009~~2010 primarily reflect gains on sales of securities held in NEER’s nuclear decommissioning funds and, infor ~~2010~~these respective periods, ~~also~~include ~~reflect~~approximately a$69 ~~pretax~~million, ~~gain~~$25 ofmillion and $1824 million of OTTI reversals. Gains on ~~the~~disposal ~~sale~~of assets - net in NEE’s consolidated statements of ~~the~~income ~~waste-to-energy~~also ~~project.~~reflect:


•	in 2012, a pretax gain of $13 million on the sale of the 30 mw wind project,


•	in 2012, a pretax gain of $7 million related to the controlling interest gain, and


•	in 2010, a pretax gain of $18 million on the sale of the waste-to-energy project.

Tax Credits and Benefits

PTCs from NEER’s wind projects are reflected in NEER’s earnings. PTCs are recognized as wind energy is generated and sold based on a per kwh rate prescribed in applicable federal and state statutes, and were approximately $~~271~~203 million, $~~307~~271 million and $~~255~~307 million for the years ended December 31, ~~2011~~2012, ~~2010~~2011 and ~~2009~~2010, respectively. In addition, NEE’s effective income tax rate for the years ended December 31, ~~2011~~2012, ~~2010~~2011 and ~~2009~~2010 was affected by deferred income tax benefits associated with convertible ITCs of $244 million, $682 million and $8868 million, respectively. See Note 6.

~~Corporate and Other: Results of Operations~~52

Corporate and Other is primarily comprised of interest expense, the operating results of FPL FiberNet, Lone Star and other business activities, as well as corporate interest income and expenses. Corporate and Other allocates non-utility interest expense and shared service costs to NEER. Interest expense is allocated based on a deemed capital structure of 70% debt and, for purposes of allocating non-utility interest expense, the deferred credit associated with differential membership interests sold by NEER’s subsidiaries is included with debt. Each subsidiary’s income taxes are calculated based on the “separate return method,” except that tax benefits that could not be used on a separate return basis, but are used on the consolidated tax return, are recorded by the subsidiary that generated the tax benefits. Any remaining consolidated income tax benefits or expenses are recorded at Corporate and Other. The major components of Corporate and Other’s results, on an after-tax basis, are as follows:

	Years Ended December 31,
	2011			2010			2009
				(millions)
Interest expense, net of allocations to NEER	$	(72	)	$	(63	)	$	(43	)
Interest income	32			43			34
Federal and state income tax benefits	91			35			—
Other	30			17			34
Net income	$	81		$	32		$	25

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~~The~~Corporate ~~increase in interest expense in 2011~~ and ~~2010~~Other: ~~reflects~~Results ~~additional debt outstanding, partly offset by lower average interest rates and, in 2010, a higher allocation~~ of interest costs to NEER. The decline in interest income in 2011 is primarily due to lower interest recorded on unrecognized tax benefits, reflecting the settlement with the Internal Revenue Service in 2011. See Note 6 - Unrecognized Tax Benefits. The increase in interest income in 2010 is primarily due to earnings on an energy-related loan made to a third party by a NEECH subsidiary. The federal and state income tax benefits reflect consolidating income tax adjustments and include the following the items:Operations

Corporate and Other is primarily comprised of interest expense, the operating results of NEET, FPL FiberNet and other business activities, as well as corporate interest income and expenses. Corporate and Other allocates non-utility interest expense and shared service costs to NEER. Interest expense is allocated based on a deemed capital structure of 70% debt and, for purposes of allocating non-utility interest expense, the liability associated with differential membership interests sold by NEER’s subsidiaries is included with debt. Each subsidiary’s income taxes are calculated based on the "separate return method," except that tax benefits that could not be used on a separate return basis, but are used on the consolidated tax return, are recorded by the subsidiary that generated the tax benefits. Any remaining consolidated income tax benefits or expenses are recorded at Corporate and Other. The major components of Corporate and Other’s results, on an after-tax basis, are as follows:



	Years Ended December 31,
	2012			2011			2010
				(millions)
Interest expense, net of allocations to NEER	$	(90	)	$	(72	)	$	(63	)
Interest income	36			32			43
Federal and state income tax benefits	20			91			35
Other	18			30			17
Net income (loss)	$	(16	)	$	81		$	32

The increase in interest expense in 2012 and 2011 reflects higher average debt balances and, in 2012, a lower allocation of interest costs to NEER, as NEER obtained additional project-specific financing, partly offset by lower average interest rates. The decline in interest income in 2011 is primarily due to lower interest recorded on unrecognized tax benefits, reflecting the settlement with the Internal Revenue Service in 2011. See Note 6 - Unrecognized Tax Benefits. The federal and state income tax benefits reflect consolidating income tax adjustments and include the following items:


•	in 2011, a state deferred income tax benefit of approximately $64 million, net of federal income taxes, related to state tax law changes,


•	in 2011, an income tax benefit of $41 million related to the dissolution of a subsidiary,


•	in 2011, a $6 million expense associated with the loss on sale of natural gas-fired generating assets, and


•	in 2010, an income tax benefit of $24 million related to employee benefits.

Other includes all other corporate income and expenses, as well as other business activities. The decline in other in ~~2010~~2012 is primarily due to approximately $18 million of after-tax investment losses, including an impairment charge on an early stage technology investment, a $6 million after-tax loss on the redemption in 2012 of NEECH junior subordinated debentures, as well as other corporate costs, partly offset by higher results from other business activities. The pretax amount of the impairment charge on the early stage technology investment and the loss on the redemption of NEECH junior subordinated debentures collectively amounted to approximately $30 million and is reflected in other - net in NEE's consolidated statements of income. The increase in other in 2011 is primarily due to the absence of an $11 million after-tax loss recorded in 2010 on the sale of assets held under leveraged leases; the pretax amount ($17 million) of such loss is reflected in other - net in NEE's consolidated statements of income.

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LIQUIDITY AND CAPITAL RESOURCES

NEE and its subsidiaries, including FPL, require funds to support and grow their businesses. These funds are used for, among other things, working capital, capital expenditures, investments in or acquisitions of assets and businesses, payment of maturing debt obligations and, from time to time, redemption or repurchase of outstanding debt or equity securities. It is anticipated that these requirements will be satisfied through a combination of cash flow from operations, short- and long-term borrowings, and the issuance, from time to time, of short- and long-term debt and equity securities, consistent with NEE’s and FPL’s objective of maintaining, on a long-term basis, a capital structure that will support a strong investment grade credit rating. NEE, FPL and NEECH rely on access to credit and capital markets as significant sources of liquidity for capital requirements and other operations that are not satisfied by operating cash flows. The inability of NEE, FPL and NEECH to maintain their current credit ratings could affect their ability to raise short- and long-term capital, their cost of capital and the execution of their respective financing strategies, and could require the posting of additional collateral under certain agreements.

Cash Flows

Sources and uses of NEE's and FPL's cash for the years ended December 31, ~~2011~~2012, ~~2010~~2011 and ~~2009~~2010 were as follows:

	NEE									FPL
	Years Ended December 31,									Years Ended December 31,
	2011			2010			2009			2011			2010			2009
	2012			2011			2010			2012			2011			2010
	(millions)
Sources of cash:
Cash flows from operating activities	$	43,~~074~~992		$	34,~~834~~074		$	43,~~463~~834		$	2,~~245~~823		$	12,~~934~~245		$	21,~~871~~934
Long-term borrowings, net of loan proceeds restricted for construction	3,375			3,724			3,220			840			924			516
Long-term borrowings and change in loan proceeds restricted for construction	6,944			3,375			3,724			1,296			840			924
Proceeds from the sale of differential membership interests, net of payments to investors	366			261			—			—			—			—
Proceeds from sale of differential membership interests, net of payments to investors	669			366			261			—			—			—
Sale of natural gas-fired generating assets	~~1,204~~—			—1,204			—			—			—			—
Capital contribution from NEE	—			—			—			~~410~~440			~~660~~410			—660
Cash grants under the Recovery Act	~~624~~196			~~588~~624			~~100~~588			~~218~~—			~~161~~218			—161
Issuances of common stock - net	48405			~~308~~48			~~198~~308			—			—			—
Net increase in short-term debt	~~460~~61			—460			~~154~~—			~~229~~—			—229			45—
Other sources	205			76			102			89			65			76
Other sources - net	141			205			76			68			89			65
Total sources of cash	1012,~~356~~408			810,~~791~~356			8,~~237~~791			4,~~031~~627			34,~~744~~031			3,~~508~~744
Uses of cash:
Capital expenditures and independent power and other investments and nuclear fuel purchases	(69,~~628~~461		)	(56,~~846~~628		)	(65,~~006~~846		)	(34,~~502~~285		)	(23,~~706~~502		)	(2,~~717~~706		)
Retirements of long-term debt	(21,~~121~~612		)	(~~769~~2,121		)	(~~1,635~~769		)	(4550		)	(4245		)	(~~263~~42		)
Net decrease in short-term debt	—			~~(1,130~~—		)	—(1,130		)	—(225		)	~~(717~~—		)	—(717		)
Dividends	(~~920~~1,004		)	(~~823~~920		)	(~~766~~823		)	~~(400~~—		)	(~~250~~400		)	(~~485~~250		)
Repurchases of common stock	(~~375~~19		)	—(375		)	—			—			—			—
Other uses	(237		)	(159		)	(127		)	(68		)	(92		)	(80		)
Other uses - net	(360		)	(237		)	(159		)	(63		)	(68		)	(92		)
Total uses of cash	(1012,~~281~~456		)	(810,~~727~~281		)	(8,~~534~~727		)	(4,~~015~~623		)	(34,~~807~~015		)	(3,~~545~~807		)
Net increase (decrease) in cash and cash equivalents	$	75(48	)	$	6475		$	~~(297~~64	)	$	164		$	~~(63~~16	)	$	(3763	)

5254

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NEE's primary capital requirements are for expanding and enhancing FPL's electric system and generating facilities to continue to provide reliable service to meet customer electricity demands and for funding NEER's investments in independent power and other projects. The following table provides a summary of the major capital investments for the years ended December 31, ~~2011~~2012, ~~2010~~2011 and ~~2009~~2010.

	Years Ended December 31,
	2011			2010			2009
	2012			2011			2010
	(millions)
FPL:
Generation:
New	$	12,~~424~~488		$	1,~~112~~424		$	1,~~185~~112
Existing	~~907~~520			~~636~~907			~~734~~636
Transmission and distribution	~~880~~966			~~606~~880			~~633~~606
Nuclear fuel	~~365~~215			~~101~~365			~~195~~101
General and other	~~213~~95			~~101~~213			~~102~~101
Other, primarily the exclusion of AFUDC - equity and change in accrued property additions	~~(287~~1		)	~~150~~(287		)	~~(132~~150		)
Total	$4,285	~~3,502~~		$3,502	~~2,706~~		$2,706	~~2,717~~
NEER:
Wind	~~953~~2,365			1,~~950~~037			21,~~625~~972
Solar	~~594~~1,235			~~185~~519			40155
Nuclear, including nuclear fuel	~~727~~286			~~510~~686			~~455~~512
Other	~~500~~795			~~427~~532			~~115~~433
Total	24,~~774~~681			32,~~072~~774			3,~~235~~072
Corporate and Other	~~352~~495			68352			5468
Total capital expenditures and independent power and other investments and nuclear fuel purchases	$	69,~~628~~461		$	56,~~846~~628		$	65,~~006~~846

In ~~February~~January ~~2012~~2013, anNEECH ~~indirect~~redeemed ~~wholly-owned~~all ~~subsidiary~~$350 ofmillion ~~NEER~~principal ~~issued~~amount ~~Class~~of Bits ~~membership~~outstanding ~~interests~~6.60% toSeries ~~two~~A ~~third-party~~Enhanced ~~investors~~Junior ~~for~~Subordinated ~~approximately~~Debentures ~~$225~~due ~~million. The~~in ~~NEER~~2066 ~~subsidiary~~and ~~has~~sold ~~ownership~~$450 ~~interests~~million inprincipal aamount ~~wind~~of ~~generation~~its ~~facility~~5.00% ~~with~~Series ~~generating~~J ~~capacity~~Junior ~~totaling~~Subordinated ~~approximately~~Debentures ~~662~~due ~~mw located~~ in ~~Texas~~2073.

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Liquidity

On February 98, ~~2012~~2013, FPL and NEECH refinanced a portion of their bank revolving line of credit facilities. The table below provides the components of FPL's and NEECH's estimated ~~total~~ net available liquidity as of that date.

										Maturity Date
	FPL			NEECH			Total				FPL	NEECH
				(millions)
Bank revolving line of credit facilities(a)	$	3,~~018~~000		$	4,~~579~~600		$	7,~~597~~600			(b)	(b)
Less letters of credit(c)	(803		)	(1,~~484~~134		)	(1,~~564~~137		)
	2,938			3,095			6,033
	2,997			3,466			6,463
Revolving credit facility	235			—			235				2014
Less borrowings	—			—			—
Less borrowings(c)	—			—			—
	235			—			235
Subtotal	3,173			3,095			6,268
Letter of credit facilities(d)	—			250			250					2015
Cash and cash equivalents(c)	26			400			426
Less letters of credit(c)	—			(46		)	(46		)
Less commercial paper(c)	(412		)	(1,188		)	(1,600		)
	—			204			204
Net available liquidity	$	2,787		$	2,307		$	5,094
Subtotal	3,232			3,670			6,902
Cash and cash equivalents(c)	306			271			577
Less commercial paper and short-term debt(c)	(395		)	(1,421		)	(1,816		)
Net available liquidity	$	3,143		$	2,520		$	5,663

~~_______________________~~______________________

(a) Provide for the funding of loans up to $7,~~597~~600 million ($3,~~018~~000 million for FPL) and the issuance of letters of credit up to $46,~~097~~600 million ($12,~~568~~500 million for FPL). The entire amount of the credit facilities is available for general corporate purposes, including to provide back-up liquidity for FPL’s and NEECH’s commercial paper programs and other short-term borrowings and to provide additional liquidity in the event of a loss to the companies’ or their subsidiaries’ operating facilities (including, in the case of FPL, a transmission and distribution property loss). FPL’s bank revolving line of credit facilities are also available to support the purchase of $633 million of pollution control, solid waste disposal and industrial development revenue bonds (tax exempt bonds) in the event they are tendered by individual bond holders and not remarketed prior to maturity.

(b) ~~Approximately~~ $4500 million ~~and~~of ~~$1,114~~each ~~million~~ of FPL’'s ~~bank revolving line of credit facilities expire in 2012~~ and ~~2013, respectively. Approximately $10 million and $1,469 million of~~ NEECH’'s bank revolving line of credit facilities ~~expire~~expires in ~~2012 and~~ 2013, ~~respectively.~~essentially ~~The~~all ~~remaining portion~~ of ~~bank~~the ~~revolving~~remaining ~~line~~balance ~~of credit facilities for FPL and NEECH~~ expires in ~~2017~~2018.

53(d) Only available for the issuance of letters of credit.

As of February 27, 2013, 58 banks participate in FPL’s and NEECH’s revolving credit facilities, with no one bank providing more than 7% of the combined revolving credit facilities. European banks provide approximately 33% of the combined revolving credit facilities. Pursuant to a 1998 guarantee agreement, NEE guarantees the payment of NEECH’s debt obligations under the revolving credit facilities. In order for FPL or NEECH to borrow or to have letters of credit issued under the terms of their respective revolving credit facilities, FPL, in the case of FPL, and NEE, in the case of NEECH, are required, among other things, to maintain a ratio of funded debt to total capitalization that does not exceed a stated ratio. The FPL and NEECH revolving credit facilities also contain default and related acceleration provisions relating to, among other things, failure of FPL and NEE, as the case may be, to maintain the respective ratio of funded debt to total capitalization at or below the specified ratio. At December 31, 2012, each of NEE and FPL was in compliance with its required ratio.

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AsAdditionally, ofat ~~February~~December 2731, 2012, 62certain ~~banks~~subsidiaries ~~participate in FPL’s and NEECH’s bank revolving line~~ of credit facilities and FPL’s revolving credit facility, with no one bank providing more than 5% of the combined bank revolving line of credit facilities and FPL’s revolving credit facility. European banks provide approximately 35% of the combined bank revolving line of credit facilities and FPL's revolving credit facility. Pursuant to a 1998 guarantee agreement, NEE ~~guarantees~~had ~~the payment of NEECH’s debt obligations under the bank revolving line of~~ credit ~~facilities. In order for FPL~~ or ~~NEECH~~loan ~~to borrow or to have letters of credit issued under the terms of their respective bank revolving line of credit~~ facilities ~~and~~with ~~FPL's~~available ~~revolving~~liquidity credit facility, FPL, in the case of FPL, and NEE, in the case of the NEECH, are required, among other things, to maintain a ratio of funded debt to total capitalization that does not exceed a stated ratio. The FPL and NEECH bank revolving line of credit facilities and FPL revolving credit facility also contain default and related acceleration provisions relating to, among other things, failure of FPL and NEE, as the case may be, to maintain the respective ratio of funded debt to total capitalization at or below the specified ratio. At December 31, 2011, each of NEE and FPL was in compliance with its required ratio.follows:

Additionally, at December 31, 2011, certain subsidiaries of NEE had credit or loan facilities with available liquidity as follows:



	Original Amount	Amount Remaining Available at December 31, 2012	Rate	Maturity Date	Related Project Use
	(millions)
NEECH and NEER:
Canadian bank revolving credit agreements^(a)(b)(c)	C$300	$2	Variable	2013	Canadian renewable generating assets
Canadian bank loan agreement^(a)(b)	C$150	$38	Variable	2014	Canadian renewable generating assets
Revolving loan agreement^(a)	€170	$63	Variable	2014	Construction of Spain solar projects
NEER:
Senior secured limited-recourse loan agreement^(d)(e)	€589	$143	Variable	2030	Construction of Spain solar projects
Term loan facility^(d)(e)	$150	$150	Variable	2019	Construction of Genesis solar project
Lone Star:
Senior secured limited-recourse loan agreement^(d)(f)	$387	$99	Variable	2016	Construction of Lone Star transmission line and substations

	OriginalAmount	AmountRemainingAvailable atDecember 31, 2011	Rate	MaturityDate	RelatedProject Use
	(millions)
NEECH and NEER:
Canadian bank revolving credit agreements(a)	C$300	$121	Variable	2013	Canadian renewable generating assets
Revolving loan agreement(a)	€170	$175	Variable	2014	Construction of Spain solar project
NEER:
Senior secured limited-recourse loan agreement(b)(c)	€589	$485	Variable	2030	Construction of Spain solar project
Term loan facility(b)(c)	$150	$150	Variable	2019	Construction of Genesis solar project
Lone Star:
Senior secured limited-recourse loan agreement(b)(d)	$387	$279	Variable	2016	Construction of Lone Star transmission line and substations

______________________

(a) Includes, as a precondition to borrowing or issuing letters of credit, as well as default and related payment acceleration, provisions that require NEE's ratio of funded debt to total capitalization to not exceed a stated ratio. Payment obligations are guaranteed by NEE pursuant to the 1998 guarantee agreement with NEECH.

(b) ~~Includes~~Available ~~default~~for ~~and~~general ~~related~~corporate ~~acceleration~~purposes; ~~provisions~~the ~~for,~~current ~~among~~intent ~~other~~is ~~things,~~for ~~failure~~it to ~~comply~~be ~~with~~used ~~certain~~for ~~covenants~~the purchase, ~~including~~development, ~~requirements~~construction, ~~that~~and/or ~~construction~~operation of ~~the~~Canadian ~~project~~renewable ~~must~~generating ~~be completed by a certain date~~assets.

(c) ~~Borrowings~~In ~~are~~January ~~preconditioned~~2013, onone ~~equity~~of ~~being contributed by~~ the ~~project's~~two ~~parent,~~agreements ~~and~~was ~~are~~amended ~~drawn~~to onincrease athe ~~pro-rata~~amount ~~basis~~under ~~with~~that ~~those~~agreement ~~equity~~by ~~contributions.~~C$100 ~~The~~million ~~total equity funding commitment~~ and, ~~until~~extend ~~certain conditions or obligations related to~~ the ~~project~~maturity ~~are met, certain obligations, including all or a portion~~ of the ~~debt~~entire ~~payment~~commitment ~~obligations,~~under ~~are~~that ~~guaranteed~~agreement by(C$250 ~~NEECH,~~million) ~~which guarantee obligations are in turn guaranteed by NEE. The related NEECH guarantee contains default and acceleration provisions relating~~ to, ~~among other things, NEE's ratio of funded debt to total capitalization exceeding a specified ratio~~2014.

(d) ~~Borrowings~~Includes ~~are~~default ~~preconditioned~~and onrelated ~~equity~~payment ~~being~~acceleration ~~contributed~~provisions byfor, ~~Lone~~among ~~Star's~~other ~~parent~~things, ~~and~~failure ~~are~~to ~~drawn~~comply ~~on a pro-rata basis~~ with ~~those~~certain ~~equity contributions. The total equity funding commitment has been guaranteed by NEECH~~covenants, ~~which~~including ~~guarantee~~requirements ~~obligations~~that ~~are~~construction ~~in turn guaranteed by NEE. The related NEECH guarantee contains default provisions and related provisions for acceleration~~ of the ~~unfunded~~project ~~equity~~must ~~commitment~~be ~~relating~~completed ~~to,~~by ~~among other things, NEE's ratio of funded debt to total capitalization exceeding~~ a ~~specified~~certain ~~ratio~~date.

(e)

Borrowings are preconditioned on equity being contributed by the project's parent, and are drawn on a pro-rata basis with those equity contributions. The total equity funding commitment and, until certain conditions or obligations related to the project are met, certain obligations, including all or a portion of the debt payment obligations, are guaranteed by NEECH, which guarantee obligations are in turn guaranteed by NEE. The related NEECH guarantee contains default and acceleration provisions relating to, among other things, NEE's ratio of funded debt to total capitalization exceeding a specified ratio.

(f)

Borrowings are preconditioned on equity being contributed by Lone Star's parent, and are drawn on a pro-rata basis with those equity contributions. The total equity funding commitment has been guaranteed by NEECH, which guarantee obligations are in turn guaranteed by NEE. The related NEECH guarantee contains default provisions and related provisions for acceleration of the unfunded equity commitment relating to, among other things, NEE's ratio of funded debt to total capitalization exceeding a specified ratio.

Storm Restoration Costs

AtAs of December 31, ~~2011~~2012, FPL had the capacity to absorb up to approximately $~~202~~117 million in future prudently incurred storm restoration costs without seeking recovery through a rate adjustment from the FPSC or filing a petition with the FPSC. See Note 1 – Revenue and Rates.

Dodd-Frank Act

The Dodd-Frank Act, enacted into law in July 2010, among other things, provides for ~~the~~substantially increased regulation of ~~the~~ OTC derivatives ~~market~~markets. The Dodd-Frank Act includes provisions that will require certain OTC derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. While the legislation is broad and detailed, substantial portions of the legislation require implementing rules to be adopted by federal governmental agencies including, but not limited to, the SEC and the CFTC. ~~While~~ NEE ~~some~~and ~~provisions~~FPL ofcontinue to monitor the ~~statute~~development of rules related to ~~OTC~~the ~~derivatives~~Dodd-Frank Act and are ~~currently~~taking insteps ~~effect~~to orcomply with those rules that affect their businesses. A number of rules have already been finalized, ~~the~~and ~~majority~~have ofbecome or will become effective over the ~~rules~~next ~~are~~ten ~~expected~~months. The rule related to bethe ~~finalized~~definition ~~and~~of ~~implemented~~a swap was effective in October 2012~~. NEE~~, ~~and~~which ~~FPL~~triggered ~~cannot~~formal ~~predict~~effective ~~the~~dates ~~impact~~for ofa ~~the~~number ~~final~~of other rules that ~~will~~are bedependent ~~adopted~~on ~~to implement~~ the ~~OTC~~definition ~~derivative-related~~of ~~provisions~~a ofswap over the ~~Dodd-Frank~~next ~~Act. Those~~ten ~~rules~~months, ~~could~~including ~~negatively~~the ~~affect~~reporting ~~NEE's~~ and ~~FPL's~~recordkeeping ~~ability~~obligations applicable to ~~hedge~~derivative ~~their~~end ~~commodity~~users such as NEE and ~~interest~~FPL. The ~~rate~~implementation ~~risks,~~of ~~which~~these ~~could~~rules is not expected to have a material effect on NEE's and FPL's; ~~risk~~however, ~~exposure~~it ~~and~~is ~~financial~~expected ~~results. The~~to ~~rules~~add ~~also~~cost ~~could~~and ~~cause~~compliance ~~NEER~~risk torelated ~~decide~~ to ~~restructure~~hedging ~~part~~activities. The ofrules ~~its~~related ~~energy marketing and trading operations or~~ to ~~discontinue~~collateral ~~certain~~requirements ~~portions~~have ofnot ~~that~~been ~~business~~finalized. InIf ~~addition~~those rules, ifwhen ~~the~~finalized, ~~rules~~ require NEE and FPL to post significant amounts of cash collateral with respect to swap transactions, NEE's and FPL's liquidity could be materially affected~~, and their ability to enter into OTC derivatives~~ .

54NEE and FPL cannot predict the impact these new rules will have on their ability to hedge their commodity and interest rate risks or on OTC derivatives markets as a whole, but management believes that they could potentially have a material effect on NEE's and FPL's risk exposure, as well as reduce market liquidity, and further increase the cost of hedging activities.

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to hedge commodity and interest rate risks could be significantly limited. Reporting and compliance requirements of the rules also could significantly increase operating costs and expose NEE and FPL to penalties for any failure to comply with the new requirements. The financial and operational impact of the final rules cannot be determined at this time, but could be material.

Capital Support

Letters of Credit, Surety Bonds and Guarantees

NEE and FPL obtain letters of credit and surety bonds, and issue guarantees to facilitate commercial transactions with third parties and financings. Letters of credit, surety bonds and guarantees support, among other things, the buying and selling of wholesale energy commodities, debt and related reserves, nuclear activities, capital expenditures for NEER's wind and solar development and other contractual agreements. Substantially all of NEE's and FPL's guarantee arrangements are on behalf of their consolidated subsidiaries for their related payment obligations.

In addition, as part of contract negotiations in the normal course of business, NEE and FPL may agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may include, but are not limited to, an adverse judgment in a lawsuit, the imposition of additional taxes due to a change in tax law or interpretations of the tax law or the non-receipt of renewable tax credits or proceeds from cash grants under the Recovery Act. NEE and FPL are unable to develop an estimate of the maximum potential amount of future payments under some of these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence.

In addition, NEE has guaranteed certain payment obligations of NEECH, including most of its debt and all of its debentures and commercial paper issuances, as well as most of its payment guarantees and indemnifications, and NEECH has guaranteed certain debt and other obligations of NEER and its subsidiaries. ~~See Note 14 - Commitments.~~

At December 31, ~~2011~~2012, NEE had approximately $1.43 billion of standby letters of credit ($403 million for FPL), approximately $~~160~~162 million of surety bonds ($5657 million for FPL) and approximately $1413.51 billion notional amount of guarantees and indemnifications ($2522 million for FPL), of which approximately $98.21 billion ~~($45~~of ~~million for FPL)~~ letters of credit, guarantees and indemnifications ($10 million for FPL) have expiration dates within the next five years. An aggregate of approximately $1.31 billion ~~($34 million for FPL)~~ of the standby letters of credit ($3.1 million for FPL) at December 31, ~~2011~~2012 were issued under FPL’s and NEECH’s credit facilities.

Each of NEE and FPL believe it is unlikely that it would incur any liabilities associated with these letters of credit, surety bonds, guarantees and indemnifications. Accordingly, at December 31, ~~2011~~2012, NEE and FPL did not have any liabilities recorded for these letters of credit, surety bonds, guarantees and indemnifications.

Shelf Registration

In August ~~2009~~2012, NEE, NEECH, ~~FPL~~ and ~~certain~~FPL ~~affiliated trusts~~ filed a shelf registration statement with the SEC for an unspecified amount of securities which became effective upon filing. The amount of securities issuable by the companies is established from time to time by their respective boards of directors. As of February 27, ~~2012~~2013, securities that may be issued under the registration statement include, depending on the registrant, senior debt securities, subordinated debt securities, junior subordinated debentures, first mortgage bonds, ~~preferred trust securities,~~ common stock, preferred stock, stock purchase contracts, stock purchase units, warrants and guarantees related to certain of those securities. As of February 27, ~~2012~~2013, NEE and NEECH had approximately $21.3 billion (issuable by either or both of them up to such aggregate amount) of board-authorized available capacity, and FPL had $~~750~~2.1 ~~million~~billion of board-authorized available capacity.

~~Contractual Obligations and Estimated Planned Capital Expenditures~~58

NEE’s and FPL’s commitments at December 31, 2011 were as follows:

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	2012		2013		2014		2015		2016		Thereafter			Total
	(millions)
Long-term debt, including interest:(a)
FPL	$	428	$	818	$	409	$	410	$	411	$	13,476	(b)	$	15,952
NEER	729		958		986		707		677		4,317			8,374
Corporate and Other	739		1,697		1,531		1,610		405		12,580			18,562
Purchase obligations:
FPL(c)	5,985		3,810		2,900		2,545		2,295		9,415			26,950
NEER(d)	1,970		475		140		110		100		520			3,315
Corporate and Other(e)	250		15		—		—		—		—			265
Asset retirement activities:(f)
FPL(g)	—		—		—		—		—		7,106			7,106
NEER(h)	2		—		—		—		—		11,564			11,566
Other Commitments:
NEER(i)	142		76		78		103		115		557			1,071
Total	$	10,245	$	7,849	$	6,044	$	5,485	$	4,003	$	59,535		$	93,161

Contractual Obligations and Estimated Planned Capital Expenditures

~~___________________________~~NEE’s and FPL’s commitments at December 31, 2012 were as follows:

(a) Includes principal, interest and interest rate swaps. Variable rate interest was computed using December 31, 2011 rates.



	2013		2014		2015		2016		2017		Thereafter			Total
	(millions)
Long-term debt, including interest:^(a)
FPL	$	860	$	750	$	450	$	451	$	751	$	14,362	^(b)	$	17,624
NEER	1,027		1,342		668		757		600		3,843			8,237
Corporate and Other	2,261		1,833		2,240		755		1,592		13,696			22,377
Purchase obligations:
FPL^(c)	5,175		4,480		3,115		2,700		2,545		8,635			26,650
NEER^(d)	855		320		95		110		65		520			1,965
Corporate and Other^(e)	45		10		15		10		10		10			100
Asset retirement activities:^(f)
FPL^(g)	38		—		—		—		—		6,989			7,027
NEER^(h)	—		—		—		—		—		12,849			12,849
Other Commitments:
NEER⁽ⁱ⁾	76		79		103		114		134		517			1,023
Total	$	10,337	$	8,814	$	6,686	$	4,897	$	5,697	$	61,421		$	97,852

(b) Includes $633 million of tax exempt bonds that permit individual bond holders to tender the bonds for purchase at any time prior to maturity. In the event bonds are tendered for purchase, they would be remarketed by a designated remarketing agent in accordance with the related indenture. If the remarketing is unsuccessful, FPL would be required to purchase the tax exempt bonds. As of December 31, 2011, all tax exempt bonds tendered for purchase have been successfully remarketed. FPL’s bank revolving line of credit facilities are available to support the purchase of tax exempt bonds.______________________

(ca) ~~Represents~~Includes ~~required~~principal, ~~capacity~~interest and ~~minimum~~interest ~~charges~~rate ~~under~~swaps. ~~long-term~~Variable ~~purchased~~rate ~~power~~interest ~~and~~was ~~fuel~~computed ~~contracts~~using ~~(see~~December ~~Note 14 - Contracts)~~31, ~~and~~2012 ~~projected capital expenditures through 2016 (see Note 14 - Commitments)~~rates.

(db) ~~Represents~~Includes ~~firm~~$633 ~~commitments~~million ~~primarily~~of tax exempt bonds that permit individual bond holders to tender the bonds for purchase at any time prior to maturity. In the event bonds are tendered for purchase, they would be remarketed by a designated remarketing agent in ~~connection~~accordance with ~~construction~~the ~~activities~~related ~~and~~indenture. ~~fuel-related~~If ~~contracts~~the remarketing is unsuccessful, FPL would be required to purchase the tax exempt bonds. ~~See~~As ~~Note~~of 14December -31, ~~Commitments~~2012, ~~and~~all ~~Contracts~~tax exempt bonds tendered for purchase have been successfully remarketed. FPL’s bank revolving line of credit facilities are available to support the purchase of tax exempt bonds.


(c)	Represents required capacity and minimum charges under long-term purchased power and fuel contracts (see Note 13 - Contracts), and projected capital expenditures through 2017 (see Note 13 - Commitments).


(d)	Represents firm commitments primarily in connection with construction activities and fuel-related contracts. See Note 13 - Commitments and Contracts.


(e)	Represents firm commitments primarily for development and construction activities relating to Lone Star's transmission line and other associated facilities.


(f)	Represents expected cash payments adjusted for inflation for estimated costs to perform asset retirement activities.

(g) At December 31, ~~2011~~2012, FPL had approximately $2,~~612~~845 million in restricted funds for the payment of future expenditures to decommission FPL’s nuclear units, which are included in NEE’s and FPL’s special use funds. See Note 1312.

(h) At December 31, ~~2011~~2012, NEER’s 88.23% portion of Seabrook’s and 70% portion of Duane Arnold’s and its Point Beach’s restricted funds for the payment of future expenditures to decommission its nuclear units totaled approximately $1,~~130~~272 million and are included in NEE’s special use funds. See Note 1312.

(i) Represents estimated cash distributions related to differential membership interests and payments related to the acquisition of certain development rights. For further discussion of differential membership interests, see Note 1 - Sale of Differential Membership Interests.

Credit Ratings

NEE’s and FPL’s liquidity, ability to access credit and capital markets, cost of borrowings and collateral posting requirements under certain agreements are dependent on their credit ratings. At February 27, ~~2012~~2013, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services (S&P) and Fitch Ratings (Fitch) had assigned the following credit ratings to NEE, FPL and NEECH:



	Moody's^(a)	S&P^(a)	Fitch^(a)
NEE:^(b)
Corporate credit rating	Baa1	A-	A-

FPL:^(b)
Corporate credit rating	A2	A-	A
First mortgage bonds	Aa3	A	AA-
Pollution control, solid waste disposal and industrial development revenue bonds	VMIG-1	A	A+
Commercial paper	P-1	A-2	F1

NEECH:^(b)
Corporate credit rating	Baa1	A-	A-
Debentures	Baa1	BBB+	A-
Junior subordinated debentures	Baa2	BBB	BBB
Commercial paper	P-2	A-2	F1

~~____________________~~______________________


(a)	A security rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. The rating is subject to revision or withdrawal at any time by the assigning rating organization.


(b)	The outlook indicated by each of Moody's, S&P and Fitch is stable.

5659

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NEE and its subsidiaries, including FPL, have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt. A change in ratings is not an event of default under applicable debt instruments, and while there are conditions to drawing on the credit facilities noted above, with the exception of the Spain senior secured limited-recourse loan facility, the maintenance of a specific minimum credit rating is not a condition to drawing on these credit facilities.

Commitment fees and interest rates on loans under these credit facilities’ agreements are tied to credit ratings. A ratings downgrade also could reduce the accessibility and increase the cost of commercial paper and other short-term debt issuances and additional or replacement credit facilities. In addition, a ratings downgrade could result in the requirement that NEE subsidiaries, including FPL, post collateral under certain agreements, including those related to fuel procurement, power sales and purchases, nuclear decommissioning funding, debt-related reserves and trading activities. FPL’s and NEECH’s credit facilities are available to support these potential requirements.

Covenants

NEE's charter does not limit the dividends that may be paid on its common stock. As a practical matter, the ability of NEE to pay dividends on its common stock is dependent upon, among other things, dividends paid to it by its subsidiaries. For example, FPL pays dividends to NEE in a manner consistent with FPL's long-term targeted capital structure. However, the mortgage securing FPL's first mortgage bonds contains provisions which, under certain conditions, restrict the payment of dividends to NEE and the issuance of additional first mortgage bonds. Additionally, in some circumstances, the mortgage restricts the amount of retained earnings that FPL can use to pay cash dividends on its common stock. The restricted amount may change based on factors set out in the mortgage. Other than this restriction on the payment of common stock dividends, the mortgage does not restrict FPL's use of retained earnings. As of December 31, ~~2011~~2012, no retained earnings were restricted by these provisions of the mortgage and, in light of FPL's current financial condition and level of earnings, management does not expect that planned financing activities or dividends would be affected by these limitations.

FPL may issue first mortgage bonds under its mortgage subject to its meeting an adjusted net earnings test set forth in the mortgage, which generally requires adjusted net earnings to be at least twice the annual interest requirements on, or at least 10% of the aggregate principal amount of, FPL’s first mortgage bonds including those to be issued and any other non-junior FPL indebtedness. As of December 31, ~~2011~~2012, coverage for the 12 months ended December 31, ~~2011~~2012 would have been approximately 6.5.0 times the annual interest requirements and approximately 32.67 times the aggregate principal requirements. New first mortgage bonds are also limited to an amount equal to the sum of 60% of unfunded property additions after adjustments to offset property retirements, the amount of retired first mortgage bonds or qualified lien bonds and the amount of cash on deposit with the mortgage trustee. As of December 31, ~~2011~~2012, FPL could have issued in excess of $8.9.6 billion of additional first mortgage bonds based on the unfunded property additions and in excess of $5.8 billion based on retired first mortgage bonds. As of December 31, ~~2011~~2012, no cash was deposited with the mortgage trustee for these purposes.

In September 2006, NEE and NEECH executed a Replacement Capital Covenant (September 2006 RCC) in connection with NEECH's offering of $350 million principal amount of Series ~~A Enhanced Junior Subordinated Debentures due 2066 and $350 million principal amount of Series~~ B Enhanced Junior Subordinated Debentures due 2066 (~~collectively,~~ Series ~~A and Series~~ B junior subordinated debentures). The September 2006 RCC is for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt) of NEECH (other than the Series ~~A and Series~~ B junior subordinated debentures) or, in certain cases, of NEE. FPL Group Capital Trust I's 5 7/8% Preferred Trust Securities have been initially designated as the covered debt under the September 2006 RCC. The September 2006 RCC provides that NEECH may redeem, and NEE or NEECH may purchase, any Series ~~A and Series~~ B junior subordinated debentures on or before October 1, 2036, only to the extent that the redemption or purchase price does not exceed a specified amount of proceeds from the sale of qualifying securities, subject to certain limitations described in the September 2006 RCC. Qualifying securities are securities that have equity-like characteristics that are the same as, or more equity-like than, the Series ~~A and Series~~ B junior subordinated debentures at the time of redemption or purchase, which are sold within 180 days prior to the date of the redemption or repurchase of the Series ~~A and Series~~ B junior subordinated debentures.

In June 2007, NEE and NEECH executed a Replacement Capital Covenant (June 2007 RCC) in connection with NEECH's offering of $400 million principal amount of its Series C Junior Subordinated Debentures due 2067 (Series C junior subordinated debentures). The June 2007 RCC is for the benefit of persons that buy, hold or sell a specified series of covered debt of NEECH (other than the Series C junior subordinated debentures) or, in certain cases, of NEE. FPL Group Capital Trust I's 5 7/8% Preferred Trust Securities have been initially designated as the covered debt under the June 2007 RCC. The June 2007 RCC provides that NEECH may redeem or purchase, or satisfy, discharge or defease (collectively, defease), and NEE and any majority-owned subsidiary of NEE or NEECH may purchase, any Series C junior subordinated debentures on or before June 15, 2037, only to the extent that the principal amount defeased or the applicable redemption or purchase price does not exceed a specified amount raised from the issuance, during the 180 days prior to the date of that redemption, purchase or defeasance, of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the Series C junior subordinated debentures at the time of redemption, purchase or defeasance, subject to certain limitations described in the June 2007 RCC.

In September 2007, NEE and NEECH executed a Replacement Capital Covenant (September 2007 RCC) in connection with NEECH's offering of $250 million principal amount of its Series D Junior Subordinated Debentures due 2067 and $350 million principal amount of Series E Junior Subordinated Debentures due 2067 (collectively, Series D and Series E junior subordinated debentures). The September 2007 RCC is for the benefit of persons that buy, hold or sell a specified series of covered debt of NEECH (other than the 60

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In September 2007, NEE and NEECH executed a Replacement Capital Covenant (September 2007 RCC) in connection with NEECH's offering of $250 million principal amount of its Series D ~~and~~Junior Subordinated Debentures due 2067 (Series ED junior subordinated debentures). The September 2007 RCC is for the benefit of persons that buy, hold or sell a specified series of covered debt of NEECH (other than the Series D junior subordinated debentures) or, in certain cases, of NEE. FPL Group Capital Trust I's 5 7/8% Preferred Trust Securities have been initially designated as the covered debt under the September 2007 RCC. The September 2007 RCC provides that NEECH may redeem, purchase, or defease, and NEE and any majority-owned subsidiary of NEE or NEECH may purchase, any Series D ~~and Series E~~ junior subordinated debentures on or before September 1, 2037, only to the extent that the principal amount defeased or the applicable redemption or purchase price does not exceed a specified amount raised from the issuance, during the 180 days prior to the date of that redemption, purchase or defeasance, of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the Series D ~~and Series E~~ junior subordinated debentures at the time of redemption, purchase or defeasance, subject to certain limitations described in the September 2007 RCC.

In March 2009, NEE and NEECH executed a Replacement Capital Covenant (March 2009 RCC) in connection with NEECH's offering of $375 million principal amount of its Series F Junior Subordinated Debentures due 2069 (Series F junior subordinated debentures). The March 2009 RCC is for the benefit of persons that buy, hold or sell a specified series of covered debt of NEECH (other than the Series F junior subordinated debentures) or, in certain cases, of NEE. FPL Group Capital Trust I's 5 7/8% Preferred Trust Securities have been initially designated as the covered debt under the March 2009 RCC. The March 2009 RCC provides that NEECH may redeem, purchase, or defease, and NEE and any majority-owned subsidiary of NEE or NEECH may purchase, any Series F junior subordinated debentures on or before March 1, 2039, only to the extent that the principal amount defeased or the applicable redemption or purchase price does not exceed a specified amount raised from the issuance, during the 180 days prior to the date of that redemption, purchase or defeasance, of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the Series F junior subordinated debentures at the time of redemption, purchase or defeasance, subject to certain limitations described in the March 2009 RCC.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

NEE’s and FPL’s significant accounting policies are described in Note 1 to the consolidated financial statements, which were prepared in accordance with GAAP. Critical accounting policies are those that NEE and FPL believe are both most important to the portrayal of their financial condition and results of operations, and require complex, subjective judgments, often as a result of the need to make estimates and assumptions about the effect of matters that are inherently uncertain. Judgments and uncertainties affecting the application of those policies may result in materially different amounts being reported under different conditions or using different assumptions.

NEE and FPL consider the following policies to be the most critical in understanding the judgments that are involved in preparing their consolidated financial statements:

Accounting for Derivatives and Hedging Activities

NEE and FPL use derivative instruments (primarily swaps, options, futures and forwards) to manage the commodity price risk inherent in the purchase and sale of fuel and electricity, as well as interest rate and foreign currency exchange rate risk associated with outstanding and forecasted debt issuances. In addition, NEE, through NEER, uses derivatives to optimize the value of power generation assets and engages in power and gas marketing and trading activities to take advantage of expected future favorable price movements.

Nature of Accounting Estimates

Accounting pronouncements require the use of fair value accounting if certain conditions are met, which requires significant judgment to measure the fair value of assets and liabilities. This applies not only to traditional financial derivative instruments, but to any contract having the accounting characteristics of a derivative. Much of the existing accounting guidance related to derivatives focuses on when certain contracts for the purchase and sale of power and certain fuel supply contracts can be excluded from derivative accounting rules, however the guidance does not address all contract issues. As a result, significant judgment must be used in applying derivatives accounting guidance to contracts. In the event changes in interpretation occur, it is possible that contracts that currently are excluded from derivatives accounting rules would have to be recorded on the balance sheet at fair value, with changes in the fair value recorded in the statement of income.

~~Assumptions and Accounting Approach~~61

NEE's and FPL’s derivative instruments, when required to be marked to market, are recorded on the balance sheet at fair value. Fair values for some of the longer-term contracts where liquid markets are not available are derived through internally developed models which estimate the fair value of a contract by calculating the present value of the difference between the contract price and the forward prices. Forward prices represent the price at which a buyer or seller could contract today to purchase or sell a commodity at a future date. The near-term forward market for electricity is generally liquid and therefore the prices in the early years of the forward curves reflect observable market quotes. However, in the later years, the market is much less liquid and forward price curves must be developed using factors including the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of power plants in converting fuel to electricity) in the region where the purchase or sale takes place, and a fundamental forecast of expected spot prices based on modeled supply and demand in the region. NEE estimates the fair value of interest rate and foreign currency derivatives using a discounted cash flows valuation

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~~technique~~Assumptions ~~based on the net amount of estimated future cash inflows~~ and ~~outflows~~Accounting ~~related to the derivative agreements. The assumptions in these models are critical since any changes therein could have a significant impact on the fair value of the derivative.~~Approach

At FPL, substantially all changes in the fair value of energy derivative transactions are deferred as a regulatory asset or liability until the contracts are settled, and, upon settlement, any gains or losses are passed through the fuel clause or the capacity clause. See Note 3.

In NEE’s non-rate regulated operations, predominantly NEER, all changes in the derivatives’ fair value for power purchases and sales and trading activities are recognized on a net basis in operating revenues; fuel purchases and sales are recognized on a net basis in fuel, purchased power and interchange expense; and the equity method investees’ related activity is recognized in equity in earnings of equity method investees in NEE’s consolidated statements of income~~, unless the criteria for hedge accounting are met and the company elects to account for the derivative as a hedge~~.

For those transactions accounted for as cash flow hedges, much of the effects of changes in fair value are reflected in OCI, a component of common shareholders’ equity, rather than being recognized in current earnings. For those transactions accounted for as fair value hedges, the effects of changes in fair value are reflected in current earnings offset by changes in the fair value of the item being hedged.

Certain hedging transactions at NEER are entered into as economic hedges but the transactions do not meet the requirements for hedge accounting or hedge accounting treatment is not elected. Changes in the fair value of those transactions are marked to market and reported in the consolidated statements of income, resulting in earnings volatility. These changes in fair value are captured in the non-qualifying hedge category in computing adjusted earnings. This could be significant to NEER’s results because the economic offset to the positions, ~~which are required to be marked to market (~~such as the physical assets from which power is generated), are not marked to market. As a consequence, NEE's net income reflects only the movement in one part of economically-linked transactions. For this reason, NEE’s management views results expressed excluding the unrealized mark-to-market impact of the non-qualifying hedges as a meaningful measure of current period performance. For additional information regarding derivative instruments, see Note 3, Overview and Energy Marketing and Trading and Market Risk Sensitivity.

Accounting for Pensions and Other Postretirement Benefits

NEE sponsors a qualified noncontributory defined benefit pension plan for substantially all employees of NEE and its subsidiaries. NEE also has a supplemental executive retirement plan (SERP) which includes a non-qualified supplemental defined benefit pension component that provides benefits to a select group of management and highly compensated employees. The impact of the SERP component is included within the pension plan as discussed below. Management believes that, based on actuarial assumptions and the well-funded status of the pension plan, NEE will not be required to make any cash contributions to the qualified pension plan in the near future.

In addition to pension benefits, NEE sponsors a contributory postretirement plan for health care and life insurance benefits (other benefits plan) for retirees of NEE and its subsidiaries meeting certain eligibility requirements. The qualified pension plan has a fully funded trust dedicated to providing the benefits under the plan. The other benefits plan has a partially funded trust dedicated to providing benefits related to life insurance. NEE allocates net periodic benefit income or cost associated with the pension and other benefits plans to its subsidiaries annually using specific criteria.

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Nature of Accounting Estimates

For the pension plan, the benefit obligation is the actuarial present value as of the December 31 measurement date, of all benefits attributed by the pension benefit formula to employee service rendered to that date. The amount of benefit to be paid depends on a number of future events incorporated into the pension benefit formula, including estimates of the average life of employees/survivors and average years of service rendered. The projected benefit obligation is measured based on assumptions concerning future interest rates and future employee compensation levels. For the other benefits plan, the benefit obligation is the actuarial present value as of the December 31 measurement date of all future benefits attributed under the terms of the other benefits plan to employee service rendered to that date. NEE derives pension income and the cost of the other benefits plan from actuarial calculations based on each plan’s provisions and management’s assumptions regarding discount rate, rate of increase in compensation levels and expected long-term rate of return on plan assets and, in the case of the other benefits plan, health care cost trend rates.

Assumptions and Accounting Approach

~~NEE’s~~Accounting ~~regulatory assets and liabilities are established in association with accounting~~ guidance ~~which~~ requires recognition of the funded status of benefit plans in the balance sheet, with changes in the funded status recognized in other comprehensive income within shareholders’ equity in the year in which the changes occur. Since NEE is the plan sponsor, and its subsidiaries do not have separate rights to the plan assets or direct obligations to their employees, this accounting guidance is reflected at NEE and not allocated to the subsidiaries. The portion of previously unrecognized actuarial gains and losses, prior service costs or credits and transition obligations that are estimated to be allocable to FPL as net periodic benefit (income) cost in future periods and that otherwise would be recorded in AOCI are classified as regulatory assets and liabilities at NEE in accordance with regulatory treatment.

59Pension income and the cost of the other benefits plan are included in O&M expenses, and are calculated using a number of actuarial assumptions. Those assumptions for the years ended December 31, 2012, 2011 and 2010 include:

~~Table~~• an expected long-term rate of ~~Contents~~return on qualified plan assets of 7.75% for the pension plan and 8.00% for the other benefits plan,

~~treatment~~• assumed increases in salary of 4.00%,

~~Pension~~• ~~income~~weighted-average ~~and~~discount ~~the~~rates ~~cost~~ of ~~the~~4.65%, ~~other~~5.00% ~~benefits~~and ~~plan~~5.50% ~~are~~for ~~included~~the inpension ~~O&M~~plan ~~expenses,~~ and ~~are~~4.53%, ~~calculated~~5.25% ~~using~~and a5.50% ~~number~~for ofthe ~~actuarial~~other ~~assumptions. Those~~benefits ~~assumptions~~plan, ~~include:~~respectively, and

• anhealth ~~expected~~care ~~long-term~~cost ~~rate~~trend ofrates ~~return~~(as onrelated ~~qualified~~to ~~plan~~other ~~assets~~benefits) for those under age 65 of 7.7530% for ~~all~~medical ~~years~~and 7.90% for ~~the~~prescription ~~pension~~drug ~~plan~~benefits and 8for those age 65 and over of 7.00% for ~~all~~medical and 7.50% for prescription drug benefits. These rates are assumed to decrease over the next 6 years for medical benefits and 8 years for prescription drug benefits to the ~~other~~ultimate trend rate of 5.50% and remain at that level thereafter. The ultimate trend rate is assumed to be reached in 2018 for medical benefits ~~plan,~~and 2020 for prescription drug benefits.

• assumed increases in salary of 4.00% for all years,

• weighted-average discount rates of 5.00%, 5.50%, and 6.90% for the pension plan and 5.25%, 5.50%, and 6.90% for the other benefits plan for the years ended December 31, 2011, 2010 and 2009, respectively, and

• health care cost trend rates (as related to other benefits) for those under age 65 of 7.60% for medical and 8.20% for prescription drug benefits and for those age 65 and over of 7.25% for medical and 7.75% for prescription drug benefits. These rates are assumed to decrease over the next 7 years for medical benefits and 9 years for prescription drug benefits to the ultimate trend rate of 5.50% and remain at that level thereafter. The ultimate trend rate is assumed to be reached in 2018 for medical benefits and 2020 for prescription drug benefits.

In developing these assumptions, NEE evaluated input from its actuaries and consultants, as well as information available in the marketplace. For the expected long-term rate of return on fund assets, NEE considered different models, capital market return assumptions and historical returns for a portfolio with an equity/bond asset mix similar to its funds, as well as its funds' historical compounded returns. NEE also considered input, including other qualitative and quantitative factors, from its actuaries and consultants as well as information available in the marketplace. NEE believes that 7.75% and 8.00% are reasonable long-term rates of return on its pension plan and other benefits plan assets, respectively. NEE will continue to evaluate all of its actuarial assumptions, including its expected rate of return, at least annually, and will adjust them as necessary.

NEE bases its determination of pension and other benefits plan expense or income on a market-related valuation of assets, as prescribed by accounting guidance. This market-related valuation reduces year-to-year volatility and recognizes investment gains or losses over a five-year period following the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return realized on those assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be affected as previously deferred gains or losses are recognized. Such gains and losses together with other differences between actual results and the estimates used in the actuarial valuations are deferred and recognized in determining pension income and other benefits plan expense only to the extent they exceed 10% of the greater of projected benefit obligations or the market-related value of assets.

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The following table illustrates the effect on net periodic benefit income of changing the critical actuarial assumptions discussed above, while holding all other assumptions constant:

				Increase (Decrease) in 2011Net Periodic Benefit Income
			Increase (Decrease) in 2012Net Periodic Benefit Income
	Change inAssumption		NEE	~~NEE~~			FPL	~~FPL~~
Expected long-term rate of return	(0.5	)%		$	(16	)		$	(11	)
			(millions)
Discount rate	(0.5	)%		$	2			$	1
Expected long-term rate of return	(0.5)%		$	(16	)		$	(11	)
Salary increase	0.5	%		$	(2	)		$	(1	)
Discount rate	(0.5)%		$	2			$	1
Health care cost trend rate(a)	1.0	%		$	—			$	—
Salary increase	0.5%		$	(2	)		$	(1	)
Health care cost trend rate(a)	1.0%		$	—			$	—

~~___________________~~______________________


(a)	Assumed health care cost trend rates can have a significant effect on the amounts reported for postretirement plans providing health care benefits. However, this effect is somewhat mitigated by the retiree cost sharing structure incorporated in NEE’s other benefits plan.

See Note 2.

Carrying Value of Long-Lived Assets

NEE evaluates onlong-lived ~~an ongoing basis the recoverability of its~~ assets for impairment ~~whenever~~when events or changes in circumstances indicate that the carrying amount may not be recoverable.

Nature of Accounting Estimates

The amount of future net cash flows, the timing of the cash flows and the determination of an appropriate interest rate all involve estimates and judgments about future events. In particular, the aggregate amount of cash flows determines whether an impairment exists, and the timing of the cash flows is critical in determining fair value. Because each assessment is based on the facts and circumstances associated with each long-lived asset, the effects of changes in assumptions cannot be generalized.

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Assumptions and Accounting Approach

An impairment loss is required to be recognized if the carrying value of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying value of the long-lived asset exceeds the asset’s fair value. In most instances, the fair value is determined by discounting estimated future cash flows using an appropriate interest rate. See Note 4 - Nonrecurring Fair Value Measurements.

~~Nuclear~~ Decommissioning and ~~Fossil/Solar~~ Dismantlement

The components of NEE’s and FPL’s decommissioning of nuclear plants, dismantlement of plants and other accrued asset removal costs are as follows:

	FPL
	NuclearDecommissioning						Fossil/SolarDismantlement						Interim RemovalCosts and Other								NEER				NEE
	December 31,						December 31,						December 31,								December 31,				December 31,
	2011			2010			2011			2010			2011				2010				2011		2010		2011		2010
	2012			2011			2012			2011			2012				2011				2012		2011		2012		2011
	(millions)
AROs	$	1,~~114~~173		$	1,~~057~~114		$	2729		$	2327		$	34			$	3			$	~~467~~509	$	~~556~~467	$	1,~~611~~715	$	1,~~639~~611
Less capitalized ARO asset net of accumulated depreciation	—			—			711			47			—				—				—		—		711		47
Accrued asset removal costs(a)	~~216~~234			~~207~~216			~~337~~338			~~336~~337			1,~~644~~378				1,~~701~~644				—		—		21,~~197~~950		2,~~244~~197
Asset retirement obligation regulatory expense difference(a)	1,~~618~~787			1,~~571~~618			2327			2223			(1		)		(1		)		—		—		1,~~640~~813		1,~~592~~640
Accrued decommissioning, dismantlement and other accrued asset removal costs	$	23,~~948~~194	(b)	$	2,~~835~~948	(b)	$	~~380~~383	(b)	$	~~377~~380	(b)	$	1,~~646~~381		(b)	$	1,~~703~~646		(b)	$	~~467~~509	$	~~556~~467	$	5,~~441~~467	$	5,~~471~~441

~~____________________~~______________________


(a)	Regulatory liability on NEE’s and FPL’s consolidated balance sheets.


(b)	Represents total amount accrued for ratemaking purposes.

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Nature of Accounting Estimates

The calculation of the future cost of retiring long-lived assets, including nuclear decommissioning and ~~fossil~~plant ~~and solar~~ dismantlement costs, involves estimating the amount and timing of future expenditures and making judgments concerning whether or not such costs are considered a legal obligation. Estimating the amount and timing of future expenditures includes, among other things, making projections of when assets will be retired and ultimately decommissioned and how costs will escalate with inflation. In addition, NEE and FPL also make interest rate and rate of return projections on their investments in determining recommended funding requirements for nuclear decommissioning costs. Periodically, NEE and FPL are required to update these estimates and projections which can affect the annual expense amounts recognized, the liabilities recorded and the annual funding requirements for nuclear decommissioning costs. For example, an increase of 0.25% in the assumed escalation rates would increase NEE’s and FPL’s asset retirement obligations and conditional asset retirement obligations (collectively, AROs) as of December 31, ~~2011~~2012 by $~~126~~134 million and $8792 million, respectively.

Assumptions and Accounting Approach

NEE and FPL each account for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as part of the carrying amount of the long-lived assets.

FPL - For ratemaking purposes, FPL accrues and funds for nuclear plant decommissioning costs over the expected service life of each unit based on studies that are filed with the FPSC ~~at least every five years~~. The studies reflect, among other things, the expiration dates of the operating licenses for FPL’s nuclear units. The most recent studies, filed in 2010, indicate that FPL’s portion of the future cost of decommissioning its four nuclear units, including spent fuel storage above what is expected to be refunded by the DOE under the spent fuel settlement agreement, is approximately $6.2 billion, or $2.34 billion expressed in ~~2011~~2012 dollars.

FPL accrues the cost of dismantling its fossil and solar plants over the expected service life of each unit based on studies filed with the FPSC. Unlike nuclear decommissioning, dismantlement costs are not funded. The most recent studies became effective January 1, 2010. At December 31, ~~2011~~2012, FPL’s portion of the ultimate cost to dismantle its fossil and solar units is approximately $~~860~~782 million, or $~~421~~369 million expressed in ~~2011~~2012 dollars. The majority of the dismantlement costs are not considered AROs. FPL accrues for interim removal costs over the life of the related assets based on depreciation studies approved by the FPSC. Any differences between the ARO amount recorded and the amount recorded for ratemaking purposes are reported as a regulatory liability in accordance with regulatory accounting.

61NEER - NEER records a liability for the present value of its expected decommissioning costs which is determined using various internal and external data and applying a probability percentage to a variety of scenarios regarding the life of the plant and timing of decommissioning. The liability is being accreted using the interest method through the date decommissioning activities are expected to be complete. At December 31, 2012, the ARO for nuclear decommissioning of NEER’s nuclear plants totaled approximately $408 million. NEER’s portion of the ultimate cost of decommissioning its nuclear plants, including costs associated with spent fuel storage above what is expected to be refunded by the DOE under the spent fuel settlement agreement, is estimated to be approximately $11.9 billion, or $1.9 billion expressed in 2012 dollars.

See Note 1 - Asset Retirement Obligations, Note 1 - Decommissioning of Nuclear Plants, Dismantlement of Plants and Other Accrued Asset Removal Costs and Note 12.

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NEER - NEER records a liability for the present value of its expected decommissioning costs which is determined using various internal and external data and applying a probability percentage to a variety of scenarios regarding the life of the plant and timing of decommissioning. The liability is being accreted using the interest method through the date decommissioning activities are expected to be complete. At December 31, 2011, the ARO for nuclear decommissioning of NEER’s nuclear plants totaled approximately $383 million. NEER’s portion of the ultimate cost of decommissioning its nuclear plants, including costs associated with spent fuel storage above what is expected to be refunded by the DOE under the spent fuel settlement agreement, is estimated to be approximately $11.4 billion, or $1.9 billion expressed in 2011 dollars.

See Note 1 - Asset Retirement Obligations, Note 1 - Decommissioning of Nuclear Plants, Dismantlement of Plants and Other Accrued Asset Removal Costs and Note 13.

Regulatory Accounting

NEE’s and FPL’s regulatory assets and liabilities are as follows:

	NEE				FPL
	December 31,				December 31,
	2011		2010		2011		2010
	2012		2011		2012		2011
Regulatory assets:	(millions)
Current:
Deferred clause and franchise expenses	$	~~112~~75	$	~~368~~112	$	~~112~~75	$	~~368~~112
Derivatives	$	~~502~~16	$	~~236~~502	$	~~502~~16	$	~~236~~502
Other	$	8497	$	8284	$	8090	$	7680
Noncurrent:
Securitized storm-recovery costs	$	~~517~~461	$	~~581~~517	$	~~517~~461	$	~~581~~517
Other	$	~~621~~582	$	~~329~~621	$	~~395~~351	$	~~293~~395
Regulatory liabilities:
Current, included in other current liabilities	$	2165	$	5221	$	2465	$	4724
Noncurrent:
Accrued asset removal costs	$	21,~~197~~950	$	2,~~244~~197	$	21,~~197~~950	$	2,~~244~~197
Asset retirement obligation regulatory expense difference	$	1,~~640~~813	$	1,~~592~~640	$	1,~~640~~813	$	1,~~592~~640
Other	$	~~419~~309	$	~~423~~419	$	~~416~~309	$	~~377~~416

Nature of Accounting Estimates

Regulatory assets and liabilities represent probable future revenues that will be recovered from or refunded to customers through the ratemaking process. All regulatory assets and liabilities are included in rate base or otherwise earn (pay) a return on investment during the recovery period.

Assumptions and Accounting Approach

Accounting guidance allows regulators to create assets and impose liabilities that would not be recorded by non-rate regulated entities. If FPL were no longer subject to cost-based rate regulation, the existing regulatory assets and liabilities would be written off unless regulators specify an alternative means of recovery or refund. In addition, the FPSC has the authority to disallow recovery of costs that it considers excessive or imprudently incurred. Such costs may include, among others, fuel and O&M expenses, the cost of replacing power lost when fossil and nuclear units are unavailable, storm restoration costs and costs associated with the construction or acquisition of new facilities. The continued applicability of regulatory accounting is assessed at each reporting period. ~~See Note 1 for a discussion of NEE’s and FPL’s other significant accounting policies.~~

Energy Marketing and Trading and Market Risk Sensitivity

NEE and FPL are exposed to risks associated with adverse changes in commodity prices, interest rates, equity prices and currency exchange rates. Financial instruments and positions affecting the financial statements of NEE and FPL described below are held primarily for purposes other than trading. Market risk is measured as the potential loss in fair value resulting from hypothetical reasonably possible changes in commodity prices, interest rates, equity prices or currency exchange rates over the next year. Management has established risk management policies to monitor and manage such market risks, as well as credit risks.

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Commodity Price Risk

NEE and FPL use derivative instruments (primarily swaps, options, futures and forwards) to manage the commodity price risk inherent in the purchase and sale of fuel and electricity. In addition, NEE, through NEER, uses derivatives to optimize the value of power generation assets and engages in power and gas marketing and trading activities to take advantage of expected future favorable price movements. See Critical Accounting Policies and Estimates and Note 3.

~~During 2010 and 2011, the changes in the fair value of NEE’s consolidated subsidiaries’ energy contract derivative instruments were as follows:~~66

				Hedges on Owned Assets
	Trading				Non-Qualifying			OCI			FPL CostRecoveryClauses			NEE Total
	(millions)
Fair value of contracts outstanding at December 31, 2009	$	39			$	126		$	131		$	(64	)	$	232
Reclassification to realized at settlement of contracts	(98		)		(126		)	(102		)	492			166
Inception value of new contracts	108				(45		)	-			-			63
Effective portion of changes in fair value recorded in OCI	-				-			20			-			20
Ineffective portion of changes in fair value recorded in earnings	-				1			-			-			1
Changes in fair value excluding reclassification to realized	76				457			-			(664		)	(131		)
Fair value of contracts outstanding at December 31, 2010	125				413			49			(236		)	351
Reclassification to realized at settlement of contracts	2				(96		)	(41		)	381			246
Inception value of new contracts and contracts sold	11				(11		)	—			—			—
Changes in fair value excluding reclassification to realized	72				403			—			(646		)	(171		)
Fair value of contracts outstanding at December 31, 2011	210				709			8			(501		)	426
Net option premium payments (receipts)	(195		)		11			—			—			(184		)
Net margin cash collateral paid (received)														(24		)
Total mark-to-market energy contract net assets (liabilities) at December 31, 2011	$	15			$	720		$	8		$	(501	)	$	218

NEE’s total energy contract net assets (liabilities) at December 31, 2011 shown above are included on the consolidated balance sheets as follows:

	December 31,2011
	(millions)
Current derivative assets	$	589
Noncurrent derivative assets	931
Current derivative liabilities	(1,024		)
Noncurrent derivative liabilities	(278		)
NEE's total mark-to-market energy contract net assets	$	218

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~~The~~During ~~sources~~2011 ofand 2012, the changes in the fair value ~~estimates~~of ~~and~~NEE’s ~~maturity~~consolidated ofsubsidiaries’ energy contract derivative instruments ~~at December 31, 2011~~ were as follows:

	Maturity
				Hedges on Owned Assets
	2012				2013			2014			2015			2016			Thereafter		Total
	Trading				Non-Qualifying			OCI			FPL CostRecoveryClauses			NEE Total
	(millions)
Trading:
Fair value of contracts outstanding at December 31, 2010	$	25			$	422		$	49		$	(236	)	$	260
Quoted prices in active markets for identical assets	$	(49	)		$	(73	)	$	4		$	—		$	—		$	—	$	(118	)
Reclassification to realized at settlement of contracts	2				(96		)	(41		)	381			246
Significant other observable inputs	(150		)		19			4			10			—			33		(84		)
Inception value of new contracts and contracts sold	11				(11		)	—			—			—
Significant unobservable inputs	129				55			9			11			2			11		217
Net option premium purchases (issuances)	(95		)		2			—			—			(93		)
Total	(70		)		1			17			21			2			44		15
Changes in fair value excluding reclassification to realized	72				403			—			(646		)	(171		)
Owned Assets - Non-Qualifying:
Fair value of contracts outstanding at December 31, 2011	15				720			8			(501		)	242
Quoted prices in active markets for identical assets	(24		)		(6		)	(3		)	(4		)	—			—		(37		)
Reclassification to realized at settlement of contracts	83				(122		)	(8		)	663			616
Significant other observable inputs	160				82			93			85			—			72		492
Inception value of new contracts and contracts sold	6				22			—			—			28
Significant unobservable inputs	(14		)		25			38			40			—			176		265
Net option premium purchases (issuances)	(2		)		3			—			—			1
Total	122				101			128			121			—			248		720
Changes in fair value excluding reclassification to realized	159				51			—			(177		)	33
Owned Assets - OCI:
Fair value of contracts outstanding at December 31, 2012	261				674			—			(15		)	920
Quoted prices in active markets for identical assets	15				—			—			—			—			—		15
Net margin cash collateral paid (received)														(123		)
Significant other observable inputs	(7		)		—			—			—			—			—		(7		)
Total mark-to-market energy contract net assets (liabilities) at December 31, 2012	$	261			$	674		$	—		$	(15	)	$	797
Significant unobservable inputs	—				—			—			—			—			—		—
Total	8				—			—			—			—			—		8
Owned Assets - FPL Cost Recovery Clauses:
Quoted prices in active markets for identical assets	—				—			—			—			—			—		—
Significant other observable inputs	(505		)		—			—			—			—			—		(505		)
Significant unobservable inputs	3				1			—			—			—			—		4
Total	(502		)		1			—			—			—			—		(501		)
Total sources of fair value	$	(442	)		$	103		$	145		$	142		$	2		$	292	$	242

NEE’s total energy contract net assets (liabilities) at December 31, 2012 shown above are included on the consolidated balance sheets as follows:



	December 31, 2012
	(millions)
Current derivative assets	$	487
Noncurrent derivative assets	874
Current derivative liabilities	(318		)
Noncurrent derivative liabilities	(246		)
NEE's total mark-to-market energy contract net assets	$	797

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The sources of fair value estimates and maturity of energy contract derivative instruments at December 31, 2012 were as follows:



	Maturity
	2013			2014			2015		2016		2017		Thereafter		Total
	(millions)
Trading:
Quoted prices in active markets for identical assets	$	(69	)	$	13		$	7	$	—	$	—	$	—	$	(49	)
Significant other observable inputs	34			7			17		31		28		1		118
Significant unobservable inputs	69			42			23		23		18		17		192
Total	34			62			47		54		46		18		261
Owned Assets - Non-Qualifying:
Quoted prices in active markets for identical assets	(1		)	(5		)	2		—		—		—		(4		)
Significant other observable inputs	69			71			69		83		11		3		306
Significant unobservable inputs	49			50			50		51		55		117		372
Total	117			116			121		134		66		120		674
Owned Assets - FPL Cost Recovery Clauses:
Quoted prices in active markets for identical assets	—			—			—		—		—		—		—
Significant other observable inputs	(17		)	—			—		—		—		—		(17		)
Significant unobservable inputs	1			1			—		—		—		—		2
Total	(16		)	1			—		—		—		—		(15		)
Total sources of fair value	$	135		$	179		$	168	$	188	$	112	$	138	$	920

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