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•	approximately 45,900 MW of generating capacity with electric generation facilities located in 30 states in the U.S., 4 provinces in Canada and in Spain;

•	approximately 16% of the installed base of U.S. wind power production capacity;

•	approximately 11% of the installed base of U.S. universal solar power production capacity;

•	one of the largest fleets of nuclear power stations in the U.S., with 8 reactors at 5 sites located in 4 states, representing approximately 6% of U.S. nuclear power electric generating capacity;

•	a generation fleet with significantly lower rates of emissions of CO2, SO2 and NOx than the average rates of the U.S. electric power industry with approximately 98% of its 2016 generation, measured by MWh produced, coming from renewable, nuclear and natural gas-fired facilities;

•	approximately 800 substations and 76,700 miles of transmission and distribution lines;

•	more than 5.4 million retail and wholesale electric customer accounts; and

•	approximately 14,700 people employed, primarily in the U.S.

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FPL has firm transportation contracts for existing natural gas pipeline capacity with five different transportation suppliers, which provide for an aggregate maximum delivery quantity of 1,969,000 MMBtu/day with expiration dates ranging from 2017 to 2036. Together, these contracts are expected to satisfy substantially all of the currently anticipated needs for natural gas transportation through mid-2017. To the extent desirable, FPL also purchases interruptible natural gas transportation service from the five transportation suppliers.

•

FPL has 25-year natural gas transportation agreements with each of Sabal Trail and Florida Southeast Connection for a quantity of 400,000 MMBtu/day beginning in mid-2017 and increasing to 600,000 MMBtu/day in mid-2020. These new agreements, when combined with FPL's existing agreements, are expected to satisfy substantially all of FPL's natural gas transportation needs through at least 2020. FPL's firm commitments under the new agreements are contingent upon the occurrence of certain events, including the completion of construction of the pipeline system to be built by Sabal Trail and Florida Southeast Connection. See NEER - Generation and Other Operations - Other Operations below and Note 13 - Contracts.

•	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 2018.

•	FPL has several contracts for the supply of uranium and the conversion, enrichment and fabrication of nuclear fuel with expiration dates ranging from late February 2017 through 2031.

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•	an approximately 1,750 MW natural gas-fired combined-cycle unit in Okeechobee County, Florida (Okeechobee Clean Energy Center), with a planned in-service date of mid-2019; and

•	up to 300 MW annually of new solar generation in each of 2017 through 2020.

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

•	the FERC, which oversees the acquisition and disposition of generation, transmission and other facilities, transmission of electricity and natural gas in interstate commerce, proposals to build and operate interstate natural gas pipelines and storage facilities, and wholesale purchases and sales of electric energy, among other things;

•	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 NRC, which has jurisdiction over the operation of nuclear power plants through the issuance of operating licenses, rules, regulations and orders; and

•	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.

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•	New retail base rates and charges were established resulting in the following increases in annualized retail base revenues:

◦	$400 million beginning January 1, 2017;

◦	$211 million beginning January 1, 2018; and

◦	$200 million when the Okeechobee Clean Energy Center achieves commercial operation, which is expected to occur in mid-2019.

•

In addition, FPL is eligible to receive, subject to conditions specified in the 2016 rate agreement, base rate increases associated with the addition of up to 300 MW annually of new solar generation in each of 2017 through 2020 and may carry forward any unused MW to subsequent years during the term of the 2016 rate agreement. FPL will be required to demonstrate that any proposed solar facilities are cost effective and scheduled to be in service before December 31, 2021. FPL has agreed to an installed cost cap of $1,750 per kW.

•	FPL's allowed regulatory ROE is 10.55%, with a range of 9.60% to 11.60%. If FPL's earned regulatory ROE falls below 9.60%, FPL may seek retail base rate relief. If the earned regulatory ROE rises above 11.60%, any party other than FPL may seek a review of FPL's retail base rates.

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Subject to certain conditions, FPL may amortize, over the term of the 2016 rate agreement, up to $1.0 billion of depreciation reserve surplus plus the reserve amount remaining under FPL's 2012 rate agreement discussed below (approximately $250 million), provided that in any year of the 2016 rate agreement, FPL must amortize at least enough reserve to maintain a 9.60% earned regulatory ROE but may not amortize any reserve that would result in an earned regulatory ROE in excess of 11.60%.

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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 amounts above $400 million.

•	an increase in annualized base revenue requirements as each of three FPL modernized power plants became operational in April 2013, April 2014 and April 2016;

•	the continuation of cost recovery through the capacity clause (reported as retail base revenues) for a generating unit which was placed in service in May 2011 (beginning January 2017, under the 2016 rate agreement, cost recovery will be through base rates);

•	subject to certain conditions, the right to reduce depreciation expense up to $400 million (reserve), provided that in any year of the 2012 rate agreement, FPL was required to amortize enough reserve to maintain an earned regulatory ROE within the range of 9.50% to 11.50% (see below regarding a subsequent reduction in the reserve amount);

•	an interim cost recovery mechanism for storm restoration costs (see Note 1 - Securitized Storm-Recovery Costs, Storm Fund and Storm Reserve); and

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•	an incentive mechanism whereby customers receive 100% of certain gains, including but not limited to gains from the purchase and sale of electricity and natural gas (including transportation and storage), up to a specified threshold; gains exceeding that specified threshold were shared by FPL and its customers.

•	Fuel - fuel costs and energy charges relating to purchased power agreements, the most significant of the cost recovery clauses in terms of operating revenues (see Note 1 - Rate Regulation);

•	Capacity - primarily capacity payments to non-utility generators and other utilities and certain costs associated with the acquisition of the Cedar Bay generation facility (see Note 1 - Rate Regulation);

•	Energy Conservation - costs associated with implementing energy conservation programs; and

•	Environmental - certain costs of complying with federal, state and local environmental regulations enacted after April 1993 and costs associated with three of FPL's solar facilities.

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•	represented approximately 15,994 MW of generating capacity;

•	weighted average remaining contract term of approximately 17 years, based on forecasted contributions to earnings; and

•	contracts for the supply of uranium and the conversion, enrichment and fabrication of nuclear fuel have expiration dates ranging from late February 2017 through 2032 (see Note 13 - Contracts).

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•	represented approximately 3,888 MW of generating capacity, including 781 MW of oil-fired peak generation facilities;

•	primarily located in Texas and the Northeast regions of the U.S.;

•	contracts for the supply of uranium and the conversion, enrichment and fabrication of nuclear fuel have expiration dates ranging from August 2017 through 2029 (see Note 13 - Contracts); and

•	utilize swaps, options, futures and forwards to lock in pricing and manage the commodity price risk inherent in power sales and fuel purchases.

(a)	A portfolio of seven natural gas pipelines, of which a third party owns a 10% interest in a 120 mile pipeline with a daily capacity of approximately 2.3 Bcf. The pipelines have a total existing capacity of approximately 4 Bcf per day, of which 3 Bcf per day is contracted with firm ship-or-pay contracts that have a weighted-average remaining contract life of approximately 14 years.

(b)	See FPL - FPL Sources of Generation - Fuel Sources - Significant Fuel Contracts and Note 13 - Commitments and - Contracts.

(c)	Construction of the natural gas pipeline is subject to certain conditions, including FERC approval. See Note 13 - Commitments.

•	manages risk associated with fluctuating commodity prices and optimizes the value of NEER's power generation and gas infrastructure production assets through the use of swaps, options, futures and forwards;

•	sells output from NEER's plants that is not sold under long-term contracts and procures fossil fuel for use by NEER's generation fleet;

•	provides full energy and capacity requirements to customers; and

•	markets and trades energy-related commodity products and provides a wide range of electricity and fuel commodity products as well as marketing and trading services to customers.

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•	ownership interests in and operated a total net generating capacity of 13,852 MW at December 31, 2016;

•	located in 20 states in the U.S. and 4 provinces in Canada;

•	approximately 12,008 MW is from contracted wind assets located primarily throughout the West and Midwest regions of the U.S. and Canada;

•	approximately 1,844 MW is from merchant wind assets located in Texas;

•	added approximately 1,465 MW in the U.S. in 2016; and

•	expects to add new contracted wind generation of approximately 2,400 to 4,100 MW and approximately 1,600 MW of additional repowering generation within the existing U.S. wind portfolio in 2017 to 2018 (see Policy Incentives for Renewable Energy Projects below for additional discussion of NEER's expectations regarding wind development, construction and retrofitting).

•	ownership interests in and operated the majority of PV and solar thermal facilities with a total net generating capacity of 2,108 MW at December 31, 2016;

•	located in 11 states in the U.S., 1 province in Canada and 1 province in Spain;

•	essentially all MW is from contracted solar facilities located primarily throughout the West region of the U.S.;

•	added approximately 980 MW in the U.S. in 2016; and

•	expects to add new contracted solar generation of approximately 400 to 1,300 MW in 2017 to 2018.

•	ownership interests in and operated natural gas generation facilities with a total net generating capacity of 420 MW at December 31, 2016; approximately 262 MW is contracted and 158 MW is merchant; located in 3 states in the Northeast region of the U.S.;

•	completed the sales of its ownership interests in merchant natural gas generation facilities located in Texas with a total generating capacity of 2,884 MW and in natural gas generation facilities located primarily in Pennsylvania with a total generating capacity of 840 MW (see Note 1 - Assets and Liabilities Associated with Assets Held for Sale); and

•	owned, or had undivided interests in, and operated oil-fired peak generation facilities with a total generating capacity of 781 MW at December 31, 2016 primarily located in Maine.

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(a)	In 2010, NEER filed an application with the NRC to renew Seabrook's operating license for an additional 20 years, which license renewal is dependent on NRC regulatory approvals.

(b)	NEER sells all of its share of the output of Duane Arnold under a long-term contract expiring in December 2025.

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

(a)	Percentage of the full PTC available for wind projects that begin construction during the applicable year.

(b)	ITC is limited to 10% for projects not placed in service before January 1, 2024.

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(a)

Information is as of February 23, 2017. 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/her present position for five years or more and his/her employment history is continuous. Mr. Arechabala was president of NextEra Energy España, S.L., an indirect wholly owned subsidiary of NEE, from February 2010 to December 2013. Ms. Caplan was vice president and chief operating officer of FPL from May 2011 to April 2013. Mr. Crews served as NEE’s Vice President, Finance from April 2016 to September 2016. From July 2015 to April 2016, he was a Partner in the national office of Deloitte & Touche LLP (Deloitte); from June 2013 to June 2015, he served as a professional accounting fellow in the Office of the Chief Accountant of the SEC; and from June 2010 to June 2013, he was an audit service senior manager at Deloitte. Mr. Ketchum served as NEE’s Senior Vice President, Finance from February 2015 to March 2016, and Senior Vice President, Business Management and Finance from December 2013 to February 2015. From December 2012 to December 2013, he was Senior Vice President, Business Management of NEER and Vice President, General Counsel & Secretary of NEER from June 2009 to December 2012. Mr. Nazar has been chief nuclear officer of NEE and FPL since January 2010 and was executive vice president, nuclear division of NEE and FPL from January 2010 to May 2014. Mr. Robo has been president and chief executive officer of NEE since July 2012. Mr. Robo was the chief executive officer of FPL from May 2012 to May 2014 and president and chief operating officer of NEE from December 2006 to June 2012. Mr. Silagy has been president of FPL since December 2011. Mr. Yeager was vice president, engineering, construction and integrated supply chain services of NEE and FPL from October 2012 to December 2012 and vice president, integrated supply chain of NEE and FPL from May 2011 to October 2012.

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

•	make some of NEE's and FPL's electric generation 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.

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•	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 and natural disasters, including, but not limited to, hurricanes, tornadoes, icing events, floods, earthquakes and droughts;

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

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

•	availability of replacement equipment;

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

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

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

•	use of new or unproven technology;

•	risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation, and lack of available alternative fuel sources;

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

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

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(a)

Includes: (1) in November 2016, 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 2011 Long Term Incentive Plan; and (2) in December 2016, 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 NextEra Energy, Inc. Amended and Restated Long-Term Incentive Plan (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.

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(a)	Includes net unrealized mark-to-market after-tax gains (losses) associated with non-qualifying hedges of approximately $(92) million, $183 million, $153 million, $(53) million and $(34) million, respectively. Also, on an after-tax basis, 2013 includes impairment and other charges of approximately $342 million related to solar projects in Spain.

(b)	2013 includes an after-tax gain from discontinued operations of $231 million related to the sale of hydropower generation plants.

(c)	Includes assets held for sale of approximately $452 million in 2016, $1,009 million in 2015 and $335 million in 2012. See Note 1 - Assets and Liabilities Associated with Assets Held for Sale.

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

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(a)	For 2016, 2015 and 2014, approximately $233 million of losses, $175 million of gains and $171 million of gains, respectively, are included in NEER's net income; the balance is included in Corporate and Other.

(b)	For 2016, 2015 and 2014, approximately $2 million of losses, $14 million of losses and $1 million of income, respectively, are included in NEER's net income; the balance is included in Corporate and Other.

(c)	Approximately $276 million of the gains is included in NEER's net income; the balance is included in Corporate and Other. See Note 1 - Assets and Liabilities Associated with Assets Held for Sale and Note 5.

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(a)

Investment in plant in service grew FPL's average retail rate base by approximately $2.4 billion and $1.0 billion in 2016 and 2015, respectively. For 2016, the increase primarily reflects the modernized Port Everglades Clean Energy Center that was placed in service in April 2016 and ongoing transmission and distribution additions. For 2015, the increase primarily reflects ongoing transmission and distribution additions and the modernized Riviera Beach Clean Energy Center placed in service in April 2014.

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(a)

Includes PTCs, ITCs and deferred income tax and other benefits associated with convertible ITCs for wind and solar projects, as applicable, (see Note 1 - Electric Plant, Depreciation and Amortization, - Income Taxes and - Sale of Differential Membership Interests and Note 5), as well as income tax benefits related to the Canadian tax restructuring, but excludes allocation of interest expense or corporate general and administrative expenses. Results from projects are included in new investments during the first twelve months of operation or ownership. Project results are included in existing assets beginning with the thirteenth month of operation.

(b)	Excludes allocation of interest expense and corporate general and administrative expenses.

(c)	Includes differential membership interest costs.

(d)	See Overview - Adjusted Earnings for additional information.

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•	higher earnings of approximately $223 million, including deferred income tax and other benefits associated with ITCs and convertible ITCs, related to the addition of approximately 2,819 MW of wind generation and 1,226 MW of solar generation during or after 2015, and

•	higher earnings of approximately $70 million related to the acquisition of the Texas pipelines in October 2015 and additional investments in other natural gas pipeline projects.

•	higher earnings of approximately $146 million related to the addition of approximately 2,571 MW of wind generation and 910 MW of solar generation during or after 2014, and

•	higher earnings of approximately $16 million related to the acquisition of the Texas pipelines and the development of three additional natural gas pipelines,

•	lower deferred income tax and other benefits associated with convertible ITCs of $21 million and ITCs of $3 million.

•	lower results from wind and solar assets of approximately $40 million primarily due to lower state tax credits, PTC roll off, higher project O&M expenses and an increase in the amount of earnings attributable to noncontrolling interest, offset in part by higher wind generation and income tax benefits related to the Canadian tax restructuring, and

•	lower results of $6 million related to the sale of certain natural gas generation facilities (see Note 1 - Assets and Liabilities Associated with Assets Held for Sale).

•	lower results from wind assets of $122 million primarily due to weaker wind resource offset in part by a favorable ITC impact related to changes in state income tax laws and favorable pricing,

•	the absence of a $45 million non cash income tax charge associated with structuring Canadian assets and $22 million in NEP IPO transaction costs recorded in 2014, and

•	higher results from merchant assets in the ERCOT region of approximately $27 million primarily due to the absence of a 2014 outage.

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•	unrealized mark-to-market losses from non-qualifying hedges of $273 million for 2016 compared to $275 million of gains on such hedges for 2015, and

•	lower revenues from existing assets of $409 million reflecting lower revenues from the natural gas generation facilities sold in 2016, offset in part by higher wind generation due to stronger wind resource and higher revenues at Seabrook reflecting the absence of a 2015 refueling outage,

•	higher revenues from new investments of approximately $384 million.

•	higher revenues from new investments of approximately $225 million,

•	higher revenues from the customer supply business and proprietary power and gas trading business of $218 million reflecting favorable market conditions, and

•	higher revenues from the gas infrastructure business of $96 million primarily reflecting gains recorded upon exiting the hedged positions on a number of future gas production opportunities and the acquisition of the Texas pipelines,

•	lower unrealized mark-to-market gains from non-qualifying hedges ($275 million for 2015 compared to $372 million of gains on such hedges for 2014), and

•

lower revenues from existing assets of $195 million reflecting lower wind generation due to weaker wind resource, lower revenues at the natural gas generation facility in Pennsylvania and in the ERCOT region due to lower gas prices and lower revenues at Seabrook reflecting a refueling outage, offset in part by higher revenues at Point Beach due to the absence of a 2014 outage and price escalation under the power sales agreement, higher dispatch in Maine due to 2015 weather conditions and higher revenues from the solar projects in Spain.

•	gains of approximately $446 million primarily related to the sale of natural gas generation facilities in 2016 and the profit sharing liability amortization related to ownership interests sold to NEP, and

•	lower fuel expense of approximately $284 million primarily reflecting lower fuel expense from the natural gas generation facilities sold in 2016,

•	higher operating expenses associated with new investments of approximately $208 million,

•	higher O&M expenses reflecting higher costs associated with growth in the NEER business, and

•	higher depreciation of $49 million on existing assets primarily reflecting an increase of $111 million of depreciation from the gas infrastructure business primarily related to higher depletion rates and increased production, partly offset by lower depreciation on the natural gas generation facilities sold in 2016.

•	higher operating expenses associated with new investments of approximately $123 million,

•	higher O&M expenses reflecting higher costs associated with growth in the NEER business, higher taxes other than income taxes and other reflecting the absence of 2014 gains on the sale of investments in certain wells in the gas infrastructure business and the absence of the 2014 reimbursement by a vendor of certain O&M-related costs, and

•	higher depreciation associated with the gas infrastructure business of $50 million primarily related to higher depletion rates and increased production,

•	lower fuel expense of approximately $146 million primarily in the ERCOT region and at the natural gas generation facility in Pennsylvania.

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(a)

Provide for the funding of loans up to $7,880 million ($2,916 million for FPL) and the issuance of letters of credit up to $3,050 million ($670 million for FPL). The entire amount of the credit facilities is available for general corporate purposes 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 $778 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. Approximately $2,315 million of FPL's and $3,730 million of NEECH's bank revolving line of credit facilities expire in 2022.

(b)	As of January 31, 2017.

(c)	Only available for the issuance of letters of credit.

(d)	Excludes two variable rate bi-lateral term loan agreements totaling $7.5 billion discussed below.

(a)

NEP OpCo and one of its direct subsidiaries are required to comply with certain financial covenants on a quarterly basis and NEP OpCo's ability to pay cash distributions to its unit holders is subject to certain other restrictions. The revolving credit facility includes borrowing capacity for letters of credit and incremental commitments to increase the revolving credit facility up to $1 billion in the aggregate. Borrowings under the revolving credit facility are guaranteed by NEP OpCo and NEP.

(b)

A certain NEP subsidiary (borrower) is required to satisfy certain conditions, including among other things, meeting a leverage ratio at the time of any borrowing that does not exceed a specified ratio. Borrowings under this revolving loan facility are secured by liens on certain of the borrower's assets and certain of the borrower's subsidiaries' assets, as well as the ownership interest in the borrower. The revolving loan facility contains default and related acceleration provisions relating to, among other things, failure of the borrower to maintain a leverage ratio at or below the specified ratio and a minimum interest coverage ratio.

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(a)	Includes principal, interest, interest rate contracts and payments by NEE under stock purchase contracts. Variable rate interest was computed using December 31, 2016 rates. See Note 11.

(b)

Includes tax exempt bonds of approximately $9 million in 2020, $46 million in 2021 and $723 million thereafter 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, 2016, 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.

(c)	Represents required capacity and minimum charges under long-term purchased power and fuel contracts, projected capital expenditures through 2021 and the purchase price of the Indiantown generation facility (see Note 13 - Commitments and - Contracts).

(d)	See Note 13 - Contracts.

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

(f)	At December 31, 2016, FPL had approximately $3,665 million in restricted funds for the payment of its portion of future expenditures to decommission the Turkey Point and St. Lucie nuclear units, which are included in NEE’s and FPL’s special use funds. See Note 12.

(g)	At December 31, 2016, NEER had approximately $1,769 million in restricted funds for the payment of its portion of future expenditures to decommission Seabrook, Duane Arnold and Point Beach nuclear units which are included in NEE’s special use funds. See Note 12.

(h)	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.

(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.

(c)	Short-term ratings are presented as all bonds outstanding are currently paying a short-term interest rate. At FPL's election, a portion or all of the bonds may be adjusted to a long-term interest rate.

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(a)	In 2016 and 2015, an expected long-term rate of return of 7.75% is presented net of investment management fees.

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(a)	Included in noncurrent regulatory liabilities on NEE’s and FPL’s consolidated balance sheets.

(b)	Represents total amount accrued for ratemaking purposes.

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(a)	Non-qualifying hedges are employed to reduce the market risk exposure to physical assets or contracts which are not marked to market. The VaR figures for the non-qualifying hedges and hedges in FPL cost recovery clauses category do not represent the economic exposure to commodity price movements.

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(a)	Primarily estimated using a market approach based on quoted market prices for these or similar issues.

(b)	Primarily estimated using an income approach utilizing a discounted cash flow valuation technique based on certain observable yield curves and indices considering the credit profile of the borrower.

(c)	Estimated using either a market approach based on quoted market prices for the same or similar issues or an income approach utilizing a discounted cash flow valuation technique, considering the current credit profile of the debtor.

(d)	Modeled internally using an income approach utilizing a discounted cash flow valuation technique and applying a credit valuation adjustment.

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•	Operations are primarily concentrated in the energy industry.

•	Trade receivables and other financial instruments are predominately with energy, utility and financial services related companies, as well as municipalities, cooperatives and other trading companies in the U.S.

•	Overall credit risk is managed through established credit policies and is overseen by the EMC.

•	Prospective and existing customers are reviewed for creditworthiness based upon established standards, with customers not meeting minimum standards providing various credit enhancements or secured payment terms, such as letters of credit or the posting of margin cash collateral.

•	Master netting agreements are used to offset cash and non-cash gains and losses arising from derivative instruments with the same counterparty. NEE’s policy is to have master netting agreements in place with significant counterparties.

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(a)	Dividends per share were $3.48, $3.08 and $2.90 for the years ended December 31, 2016, 2015 and 2014, respectively.

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(a)	FPL's comprehensive income is the same as reported net income.

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•	New retail base rates and charges were established resulting in the following increases in annualized retail base revenues:

◦	$400 million beginning January 1, 2017;

◦	$211 million beginning January 1, 2018; and

◦	$200 million when a new approximately 1,750 MW natural gas-fired combined-cycle unit in Okeechobee County, Florida achieves commercial operation, which is expected to occur in mid-2019.

•

In addition, FPL is eligible to receive, subject to conditions specified in the 2016 rate agreement, base rate increases associated with the addition of up to 300 MW annually of new solar generation in each of 2017 through 2020 and may carry forward any unused MW to subsequent years during the term of the 2016 rate agreement. FPL will be required to demonstrate that any proposed solar facilities are cost effective and scheduled to be in service before December 31, 2021. FPL has agreed to an installed cost cap of $1,750 per kilowatt (kW).

•	FPL's allowed regulatory return on common equity (ROE) is 10.55%, with a range of 9.60% to 11.60%. If FPL's earned regulatory ROE falls below 9.60%, FPL may seek retail base rate relief. If the earned regulatory ROE rises above 11.60%, any party other than FPL may seek a review of FPL's retail base rates.

•

Subject to certain conditions, FPL may amortize, over the term of the 2016 rate agreement, up to $1.0 billion of depreciation reserve surplus plus the reserve amount remaining under FPL's 2012 rate agreement discussed below (approximately $250 million), provided that in any year of the 2016 rate agreement, FPL must amortize at least enough reserve to maintain a 9.60% earned regulatory ROE but may not amortize any reserve that would result in an earned regulatory ROE in excess of 11.60%.

•

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 kilowatt-hour (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 amounts above $400 million.

•	a regulatory ROE of 10.50% with a range of plus or minus 100 basis points;

•	an increase in annualized base revenue requirements as each of three FPL modernized power plants became operational in April 2013, April 2014 and April 2016;

•	the continuation of cost recovery through the capacity clause (reported as retail base revenues) for a generating unit which was placed in service in May 2011 (beginning January 2017, under the 2016 rate agreement, cost recovery will be through base rates);

•	subject to certain conditions, the right to reduce depreciation expense up to $400 million (reserve), provided that in any year of the 2012 rate agreement, FPL was required to amortize enough reserve to maintain an earned regulatory ROE within the range of 9.50% to 11.50% (see Rate Regulation above regarding a subsequent reduction in the reserve amount);

•	an interim cost recovery mechanism for storm restoration costs (see Securitized Storm-Recovery Costs, Storm Fund and Storm Reserve below); and

•	an incentive mechanism whereby customers receive 100% of certain gains, including but not limited to, gains from the purchase and sale of electricity and natural gas (including transportation and storage), up to a specified threshold; gains exceeding that specified threshold were shared by FPL and its customers.

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(a)	NEE's accumulated pension benefit obligation, which includes no assumption about future salary levels, at December 31, 2016 and 2015 was approximately $2,439 million and $2,366 million, respectively.

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(a)	Beginning in 2017, NEE changed its method of estimating the interest cost component of net periodic benefit costs and will use a full yield curve approach by applying a specific spot rate along the yield curve rather than a single weighted-average discount rate. Such change is not expected to have a material impact on the pension and postretirement plans' net periodic benefit costs.

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(a)	See Note 4 for discussion of fair value measurement techniques and inputs.

(b)	Includes foreign investments of $370 million.

(c)	Includes foreign investments of $261 million.

(d)	Includes foreign investments of $67 million.

(e)	Includes foreign investments of $31 million.

(f)	Includes foreign investments of $282 million.

(a)	See Note 4 for discussion of fair value measurement techniques and inputs.

(b)	Includes foreign investments of $384 million.

(c)	Includes foreign investments of $249 million.

(d)	Includes foreign investments of $68 million.

(e)	Includes foreign investments of $23 million.

(f)	Includes foreign investments of $283 million.

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(a)

In developing the expected long-term rate of return on assets assumption for its pension plan, NEE evaluated input, including other qualitative and quantitative factors, from its actuaries and consultants, as well as information available in the marketplace. NEE considered different models, capital market return assumptions and historical returns for a portfolio with an equity/bond asset mix similar to its pension fund. NEE also considered its pension fund's historical compounded returns.

(b)	In 2016 and 2015, an expected long-term rate of return of 7.75% is presented net of investment management fees.

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(a)	Reflects the netting of approximately $96 million in margin cash collateral received from counterparties.

(b)	Reflects the netting of approximately $71 million in margin cash collateral received from counterparties.

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(a)	Reflects the netting of approximately $279 million in margin cash collateral received from counterparties.

(b)	Reflects the netting of approximately $151 million in margin cash collateral received from counterparties.

(c)	Reflects the netting of approximately $46 million in margin cash collateral paid to counterparties.

(d)	Reflects the netting of approximately $13 million in margin cash collateral paid to counterparties.

(a)	Included in interest expense.

(b)	For 2015 and 2014, losses of approximately $11 million and $8 million, respectively, are included in interest expense and the balances are included in other - net.

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(a)	For the years ended December 31, 2016, 2015 and 2014, FPL recorded gains (losses) of approximately $203 million, $(326) million and $(289) million, respectively, related to commodity contracts as regulatory liabilities (assets) on its consolidated balance sheets.

(a)	Megawatt-hours

(b)	One million British thermal units

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(a)

Includes the effect of the contractual ability to settle contracts under master netting arrangements and the netting of margin cash collateral payments and receipts. NEE and FPL also have contract settlement receivable and payable balances that are subject to the master netting arrangements but are not offset within the consolidated balance sheets and are recorded in customer receivables - net and accounts payable, respectively.

(b)	Includes restricted cash of approximately $164 million ($120 million for FPL) in other current assets on the consolidated balance sheets.

(c)	Excludes investments accounted for under the equity method and loans not measured at fair value on a recurring basis. See Fair Value of Financial Instruments Recorded at Other than Fair Value below.

(d)	Primarily invested in commingled funds whose underlying securities would be Level 1 if those securities were held directly by NEE or FPL.

(e)	See Note 3 - Fair Value of Derivative Instruments for a reconciliation of net derivatives to NEE's and FPL's consolidated balance sheets.

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(a)

Includes the effect of the contractual ability to settle contracts under master netting arrangements and the netting of margin cash collateral payments and receipts. NEE and FPL also have contract settlement receivable and payable balances that are subject to the master netting arrangements but are not offset within the consolidated balance sheets and are recorded in customer receivables - net and accounts payable, respectively.

(b)	Includes restricted cash of approximately $61 million ($36 million for FPL) in other current assets on the consolidated balance sheets.

(c)	Excludes investments accounted for under the equity method and loans not measured at fair value on a recurring basis. See Fair Value of Financial Instruments Recorded at Other than Fair Value below.

(d)	Primarily invested in commingled funds whose underlying securities would be Level 1 if those securities were held directly by NEE or FPL.

(e)	See Note 3 - Fair Value of Derivative Instruments for a reconciliation of net derivatives to NEE's and FPL's consolidated balance sheets.

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(a)	Applies only to full requirements contracts.

(a)	Assumes the contract is in a gain position.

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(a)

For the year ended December 31, 2016, $397 million of realized and unrealized gains are reflected in the consolidated statements of income in operating revenues and the balance is reflected in interest expense. For the year ended December 31, 2015, $462 million of realized and unrealized gains are reflected in the consolidated statements of income in operating revenues and the balance is primarily reflected in interest expense. For the year December 31, 2014, $79 million of realized and unrealized losses are reflected in the consolidated statements of income in interest expense and the balance is primarily reflected in operating revenues.

(b)	Transfers into Level 3 were a result of decreased observability of market data. Transfers from Level 3 to Level 2 were a result of increased observability of market data and, in 2016, a favorable change to a credit valuation adjustment. NEE's and FPL's policy is to recognize all transfers at the beginning of the reporting period.

(c)	For the years ended December 31, 2016, 2015 and 2014, $283 million, $289 million, and $328 million of unrealized gains are reflected in the consolidated statements of income in operating revenues and the balance is reflected in interest expense.

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(a)	Primarily represents investments accounted for under the equity method and loans not measured at fair value on a recurring basis.

(b)

Primarily classified as held to maturity. Fair values are primarily estimated using an income approach utilizing a discounted cash flow valuation technique based on certain observable yield curves and indices considering the credit profile of the borrower (Level 3). Notes receivable bear interest primarily at fixed rates and mature by 2029. Notes receivable are considered impaired and placed in non-accrual status when it becomes probable that all amounts due cannot be collected in accordance with the contractual terms of the agreement. The assessment to place notes receivable in non-accrual status considers various credit indicators, such as credit ratings and market-related information.

(c)	Excludes debt totaling $373 million and $938 million, respectively, reflected in liabilities associated with assets held for sale on NEE's consolidated balance sheets for which the carrying amount approximates fair value. See Note 1 - Assets and Liabilities Associated with Assets Held for Sale.

(d)

As of December 31, 2016 and 2015, for NEE, approximately $29,804 million and $18,031 million, respectively, is estimated using a market approach based on quoted market prices for the same or similar issues (Level 2); the balance is estimated using an income approach utilizing a discounted cash flow valuation technique, considering the current credit profile of the debtor (Level 3). For FPL, primarily estimated using quoted market prices for the same or similar issues (Level 2).

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(a)	Unrealized losses on available for sale debt securities in an unrealized loss position for greater than twelve months at December 31, 2016 and 2015 were not material to NEE or FPL.

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(a)	Amount relates to a valuation allowance related to the solar projects in Spain, deferred state tax credits and state operating loss carryforwards.

(a)	Includes $60 million of net operating loss carryforwards with an indefinite expiration period.

(b)	Includes $188 million of ITC carryforwards with an indefinite expiration period.

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(a)	Excludes nuclear fuel.

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(a)	Substantially all of the difference between the investment carrying amount and the underlying equity in net assets is being amortized over a 25-year period.

(a)	Calculated using the treasury stock method. Performance share awards are included in diluted weighted-average number of common shares outstanding based upon what would be issued if the end of the reporting period was the end of the term of the award.

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(a)	Based on historical experience.

(b)	Based on historical exercise and post-vesting cancellation experience adjusted for outstanding awards.

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(a)	Reclassified to interest expense and also to other - net in 2014 and 2015 in NEE's consolidated statements of income. See Note 3 - Income Statement Impact of Derivative Instruments.

(b)	Reclassified to gains on disposal of investments and other property - net in NEE's consolidated statements of income.

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(a)	Principal on the storm-recovery bonds is due on the final maturity date (the date by which the principal must be repaid to prevent a default) for each tranche, however, it is being paid semiannually and sequentially.

(b)

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, 2016, 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. Variable interest rate is established at various intervals by the remarketing agent.

(c)	Variable rate is based on an underlying index plus a margin.

(d)	Interest rate contracts, primarily swaps, have been entered into with respect to certain of these debt issuances. Additionally, a foreign currency swap has been entered into with respect to the Japanese yen denominated term loans - variable. See Note 3.

(e)	Excludes debt totaling $373 million reflected in liabilities associated with assets held for sale on NEE's consolidated balance sheets.

(f)	Includes approximately $490 million of debt held by a wholly owned subsidiary of NEER and collateralized by a third-party note receivable held by that subsidiary. See Note 8 - NEER.

(g)	Excludes debt totaling $938 million reflected in liabilities associated with assets held for sale on NEE's consolidated balance sheets. See Note 1 - Assets and Liabilities Associated with Assets Held for Sale.

(h)	See Spain Solar Projects Debt Restructuring below.

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(a)	Primarily reflects the effect of revised cost estimates for decommissioning FPL's nuclear units consistent with the updated nuclear decommissioning studies approved by the FPSC.

(b)	Primarily reflects the effect of revised cost estimates for decommissioning NEER’s nuclear units and a change in assumptions relating to spent fuel costs, partly offset by increased escalation rates.

(c)	Primarily reflects the effect of revised cost estimates to dismantle certain of NEER’s wind and solar facilities.

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(a)	Includes AFUDC of approximately $81 million, $79 million, $46 million and $6 million for 2017 through 2020, respectively.

(b)	Includes land, generation structures, transmission interconnection and integration and licensing.

(c)	Consists of capital expenditures for new wind projects, repowering of existing wind projects and related transmission totaling approximately 2,760 MW.

(d)	Includes capital expenditures for new solar projects and related transmission totaling approximately 225 MW.

(e)	Includes capital expenditures for construction of three natural gas pipelines, including equity contributions associated with equity investments in joint ventures for two pipelines and AFUDC associated with the third pipeline. The natural gas pipelines are subject to certain conditions. See Contracts below.

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(a)

Capacity charges, substantially all of which are recoverable through the capacity clause, totaled approximately $175 million, $434 million and $485 million for the years ended December 31, 2016, 2015 and 2014, respectively. Energy charges, which are recoverable through the fuel clause, totaled approximately $126 million, $262 million and $299 million for the years ended December 31, 2016, 2015 and 2014, respectively.

(b)	Recoverable through the fuel clause.

(c)	Includes approximately $200 million, $295 million, $290 million, $360 million, $390 million and $7,495 million in 2017, 2018, 2019, 2020, 2021 and thereafter, respectively, of firm commitments, subject to certain conditions as noted above, related to the natural gas transportation agreements with Sabal Trail and Florida Southeast Connection.

(d)	Includes an approximately $30 million commitment to invest in clean power and technology businesses primarily in 2017.

(e)	Excludes approximately $263 million and $148 million in 2017 and 2018, respectively, of joint obligations of NEECH and NEER which are included in the NEER amounts above.

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(a)	Interest expense allocated from NEECH is based on a deemed capital structure of 70% debt. For this purpose, the deferred credit associated with differential membership interests sold by NEER subsidiaries is included with debt. Residual NEECH corporate interest expense is included in Corporate and Other.

(b)	NEER includes PTCs that were recognized based on its tax sharing agreement with NEE. See Note 1 - Income Taxes.

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(a)	Represents primarily FPL and consolidating adjustments.

(a)	Represents primarily FPL and consolidating adjustments.

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(a)	Represents primarily FPL and consolidating adjustments.

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(a)	Represents primarily FPL and consolidating adjustments.

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(a)	In the opinion of NEE and FPL management, all adjustments, which consist of normal recurring accruals necessary to present a fair statement of the amounts shown for such periods, have been made. Results of operations for an interim period generally will not give a true indication of results for the year.

(b)	The sum of the quarterly amounts may not equal the total for the year due to rounding.

(c)	Amounts were restated to reflect the adoption in the second quarter of 2016 of an accounting standards update resulting in an increase to net income and net income attributable to NEE of $17 million, and an increase to earnings per share attributable to NEE, basic and assuming dilution, of $0.04. See Note 10 - Stock-Based Compensation.

(d)	The sum of the quarterly amounts may not equal the total for the year due to rounding and changes in weighted-average number of common shares outstanding.

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(a)	Management's Annual Report on Internal Control Over Financial Reporting

(b)	Attestation Report of the Independent Registered Public Accounting Firm

(c)	Changes in Internal Control Over Financial Reporting

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(a)

Includes an aggregate of 2,505,208 outstanding options, 1,747,538 unvested performance share awards (at maximum payout), 16,564 deferred fully vested performance shares and 183,989 deferred stock awards (including future reinvested dividends) under the NextEra Energy, Inc. Amended and Restated 2011 Long Term Incentive Plan and former LTIP, and 25,740 fully vested shares deferred by directors under the NextEra Energy, Inc. 2007 Non-Employee Directors Stock Plan and its predecessor, the FPL Group, Inc. Amended and Restated Non-Employee Directors Stock Plan.

(b)	Relates to outstanding options only.

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(a)

Audit fees consist of fees billed for professional services rendered for the audit of FPL's and NEE's annual consolidated financial statements for the fiscal year, the reviews of the financial statements included in FPL's and NEE's Quarterly Reports on Form 10-Q during the fiscal year and the audit of the effectiveness of internal control over financial reporting, comfort letters, consents, and other services related to SEC matters and services in connection with annual and semi-annual filings of NEE's financial statements with the Japanese Ministry of Finance.

(b)	Audit-related fees consist of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of FPL's and NEE's consolidated financial statements and are not reported under audit fees. These fees primarily related to agreed-upon procedures and attestation services.

(c)	Tax fees consist of fees billed for professional services rendered for tax compliance, tax advice and tax planning. In 2016 and 2015, approximately $66,000 and $28,000, respectively, was paid related to tax advice and planning services. All other tax fees in 2016 and in 2015 related to tax compliance services.

(d)	All other fees consist of fees for products and services other than the services reported under the other named categories. In 2016 and 2015, these fees related to training.

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