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•	FPL has firm transportation contracts with seven different transportation suppliers for natural gas pipeline capacity for an aggregate maximum quantity of 2,769,000 MMBtu/day currently, of which 1,969,000 MMBtu/day have expiration dates ranging from 2019 to 2036. The remaining 800,000 MMBtu/day increases to 1,200,000 MMBtu/day starting in mid-2020 through 2042. See Note 15 - Contracts.

•	FPL has several contracts for the supply of uranium and the conversion, enrichment and fabrication of nuclear fuel with expiration dates ranging from March 2019 through 2033.

•	Additionally, FPL enters into 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.

(a)	Excludes 147 MW operated by FPL but owned by non-affiliates.

(b)	In January 2018, FPL filed an application with the NRC to renew the operating licenses for Turkey Point Units Nos. 3 and 4 for an additional 20 years, which license renewals are pending.

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•	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, in some cases delegating authority to state agencies. 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.

•	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 (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. To date, approximately 900 MW of new solar generating capacity has become operational, 600 MW during the first quarter of 2018 and 300 MW during the first quarter of 2019. An additional 300 MW is expected to be operational in 2020. 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

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•	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.

•

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 that remained 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 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. See Note 1 - Storm Fund and Storm Reserve.

•	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 is 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% (the reserve amount was reduced by $30 million to up to $370 million as a result of a settlement in August 2015 related to the acquisition of a 250 MW coal-fired generation facility located in Jacksonville, Florida, which FPL retired in December 2016);

•	an interim cost recovery mechanism for storm restoration costs (see Note 1 - Storm Fund and Storm Reserve); 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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•	Fuel - primarily fuel costs, the most significant of the cost recovery clauses in terms of operating revenues (see Note 1 - Rate Regulation);

•	Capacity - primarily certain costs associated with the acquisition of several electric generation facilities (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 placed in service prior to 2016.

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•	represented approximately 18,938 MW of total net generating capacity;

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•	weighted-average remaining contract term of the power sales agreements and the remaining life of the PTCs associated with repowered wind facilities of approximately 16 years, based on forecasted contributions to earnings and forecasted amounts of electricity produced by the repowered wind facilities; and

•	contracts for the supply of uranium and the conversion, enrichment and fabrication of nuclear fuel have expiration dates ranging from March 2019 through 2033 (see Note 15 - Contracts).

(a)	A NEP 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. Approximately 3.2 Bcf per day of capacity is contracted with firm ship-or-pay contracts that have expiration dates ranging from 2020 to 2035.

(b)	See Note 15 - Contracts for a discussion of transportation contracts with FPL.

(c)	Completion of construction of the natural gas pipeline is subject to final permitting. Also, see Note 15 - Contracts for a discussion of a transportation contract with a NEER subsidiary.

•	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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•	located in 19 states in the U.S. and 4 provinces in Canada;

•	operated a total generating capacity of 15,058 MW at December 31, 2018;

•	ownership interests in a total net generating capacity of 13,529 MW at December 31, 2018;

◦	all MW are from contracted wind assets located primarily throughout Texas and the West and Midwest regions of the U.S. and Canada;

◦	added approximately 1,406 MW of new generating capacity and repowered wind generating capacity totaling 899 MW in the U.S. in 2018 and sold assets to NEP (see Note 1 - Disposal of a Business/Assets).

•	located in 22 states in the U.S. and 1 province in Spain;

•	operated PV and solar thermal facilities with a total generating capacity of 2,322 MW at December 31, 2018;

•	ownership interests in PV and solar thermal facilities with a total net generating capacity of 2,313 MW at December 31, 2018;

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

◦	added approximately 326 MW of generating capacity in the U.S. in 2018 and sold assets to NEP (see Note 1 - Disposal of a Business/Assets).

•	operated natural gas generation facilities with a total generating capacity of 2,180 MW at December 31, 2018;

•	ownership interests in natural gas generation facilities with a total net generating capacity of 1,639 MW at December 31, 2018;

◦	approximately 1,481 MW are contracted and 158 MW are merchant;

◦	located in 3 states in the Northeast region of the U.S. and in Florida;

◦	added ownership interests in two natural gas generation facilities located in Florida with a total generating capacity of approximately 1,451 MW (NEER's net generating capacity of 1,219 MW) (see Note 8 - Other); and

•	operated oil-fired peak generation facilities with a total generating capacity of 878 MW with an ownership or undivided interests in total net generating capacity of 781 MW at December 31, 2018 primarily located in Maine.

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(a)	Excludes 147 MW operated by NEER but owned by non-affiliates.

(b)	In 2010, NEER filed an application with the NRC to renew Seabrook's operating license for an additional 20 years, which license renewal is pending.

(c)	Excludes 184 MW operated by NEER but owned by non-affiliates.

(d)	NEER sells all of its share of the output of Duane Arnold under an amended long-term contract expiring in December 2020. Operations of Duane Arnold are expected to cease in late 2020, subject to approval by MISO. See Note 5 - Nonrecurring Fair Value Measurements.

(e)	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)	Percentage of eligible project costs that can be claimed as ITC by wind projects that begin construction during the applicable year.

(c)	Percentage of eligible project costs that can be claimed as ITC by solar projects that begin construction during the applicable year. ITC is limited to 10% for solar projects not placed in service before January 1, 2024.

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(a)

Information is as of February 15, 2019. 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. 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); and from June 2013 to June 2015, he served as a professional accounting fellow in the Office of the Chief Accountant of the SEC. 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. 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 and was the chief executive officer of FPL from May 2012 to May 2014. Mr. Silagy has been president of FPL since December 2011.

(b)

The following information was announced January 25, 2019 and is effective March 1, 2019. Mr. Pimentel will retire as President and Chief Executive Officer of NEER. Mr. Ketchum was appointed President and Chief Executive Officer of NEER and will cease to serve as Executive Vice President, Finance and Chief Financial Officer of NEE and FPL. Rebecca Kujawa, age 43, was appointed Executive Vice President, Finance and Chief Financial Officer of NEE and FPL and, in such capacities, will serve as NEE’s and FPL's principal financial officer. Ms. Kujawa has served as Vice President, Business Management of NEER since March 2012. Mr. Crews was appointed Vice President, Business Management of NEER and will cease to serve as Vice President, Controller and Chief Accounting Officer of NEE. James May, age 42, was appointed Vice President, Controller and Chief Accounting Officer of NEE and, in such capacities, will serve as NEE's principal accounting officer. Mr. May has served as Controller of NEER since April 2015 and was Director of Accounting of NEER from July 2013 to April 2015.

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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;

•	risks of property damage, human injury or loss of life from energized equipment, hazardous substances or explosions, fires, leaks or other events, especially where facilities are located near populated areas;

•	potential environmental impacts of gas infrastructure operations;

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

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•	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 2018, 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 2018, 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 May 2017, NEE's Board of Directors authorized repurchases of up to 45 million shares of common stock over an unspecified period.

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14.

(b)	See Note 1 - NextEra Energy Partners, LP for a discussion of the deconsolidation of NEP in January 2018.

(c)

2018 includes an after-tax gain of approximately $3.0 billion related to the deconsolidation of NEP (see Note 1 - NextEra Energy Partners, LP). 2017 includes approximately $1.8 billion ($1.9 billion attributable to NEE) of net favorable tax reform impacts (see Note 6). 2017 and 2016 include after-tax gains on sale of the fiber-optic telecommunications business and natural gas generation facilities of $685 million and $219 million, respectively (see Note 1 - Disposal of a Business/Assets). Also, on an after-tax basis, 2017 includes an impairment charge of $258 million related to Duane Arnold (see Note 5 - Nonrecurring Fair Value Measurements).

(d)	2018 reflects approximately $497 million relating to a reduction of differential membership interests as a result of a change in the federal corporate income tax rate effective January 1, 2018 (see Note 1 - Sales of Differential Membership Interests).

(e)	Includes assets held for sale of approximately $452 million in 2016 related to a fiber-optic telecommunications business and $1,009 million in 2015 related to merchant natural gas generation facilities. See Note 1 - Disposal of a Business/Assets.

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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 and differential membership interests sold by NEER's subsidiaries.

(b)	NEP was deconsolidated from NEER in January 2018. See Note 1 - NextEra Energy Partners, LP.

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(a)

For 2018, 2017 and 2016, approximately $40 million of gains, $46 million of gains and $233 million of losses, respectively, are included in NEER's net income; the balance is included in Corporate and Other. The change in non-qualifying hedge activity is primarily attributable to changes in forward power and natural gas prices, interest rates and foreign currency exchange rates, as well as the reversal of previously recognized unrealized mark-to-market gains or losses as the underlying transactions were realized. In 2017, net losses associated with non-qualifying hedge activity were partly offset by approximately $95 million of tax reform impacts.

(b)

For 2018, approximately $420 million of favorable tax reform-related impacts relates to NEER and the balance relates to Corporate and Other. For 2017, approximately $1,929 million of net favorable tax reform impacts and $50 million of net unfavorable tax reform impacts relate to NEER and FPL, respectively; the balance relates to Corporate and Other. See Note 1 - Rate Regulation and - Sales of Differential Membership Interests and Note 6.

(c)	Approximately $2,885 million relates to NEER; the balance relates to Corporate and Other. See Note 1 - NextEra Energy Partners, LP and - Disposal of a Business/Assets.

(d)	For 2018, 2017 and 2016, approximately $127 million of losses, $2 million of gains and $2 million of losses, respectively, are included in NEER's net income; the balance for 2018 and 2016 is included in Corporate and Other.

(e)	See Note 1 - Merger-Related.

(f)	See Note 1 - Disposal of a Business/Assets for a discussion of the sale of the fiber-optic telecommunications business.

(g)	Approximately $276 million of the gains is included in NEER's net income; the balance is included in Corporate and Other. See Note 1 - Disposal of a Business/Assets for a discussion of the sale of the natural gas generation facilities.

(h)	Approximately $246 million of the impairment charge is included in NEER's net income; the balance is included in Corporate and Other. See Note 5 - Nonrecurring Fair Value Measurements.

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(a)

Reflects after-tax project contributions, including PTCs, ITCs and deferred income taxes 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 - Sales of Differential Membership Interests and Note 6), 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 and pipelines are included in new investments during the first twelve months of operation or ownership. Project results are included in existing assets and pipeline results are included in gas infrastructure beginning with the thirteenth month of operation or ownership.

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

(c)	Includes differential membership interest costs. Excludes unrealized mark-to-market gains and losses related to interest rate derivative contracts, which are included in change in non-qualifying hedge activity.

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

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•	lower revenues of approximately $718 million related to the deconsolidation of NEP,

•	higher revenues of $193 million from the customer supply and proprietary power and gas trading business,

•	favorable unrealized mark-to-market activity of $115 million from non-qualifying hedges, and

•	higher revenues from new investments of $105 million.

•	higher revenues from new investments of approximately $318 million,

•	lower unrealized mark-to-market losses from non-qualifying hedges ($71 million for 2017 compared to $273 million in 2016), and

•	higher revenues of $125 million from the customer supply and proprietary power and gas trading business,

•	lower revenues from existing assets of $291 million primarily reflecting the sale of certain natural gas generation facilities in 2016, and

•	lower revenues from the gas infrastructure business of $89 million.

•	the absence of approximately $412 million of operating expenses related to NEP, which is no longer consolidated, and

•	the absence of the Duane Arnold impairment charge of approximately $420 million (see Note 5 - Nonrecurring Fair Value Measurements),

•	higher O&M expense at the gas infrastructure and customer supply and proprietary power and gas trading businesses, and

•	higher operating expenses associated with new investments of approximately $55 million.

•	the absence of the 2016 gain on the sale of natural gas generation facilities of approximately $445 million,

•	the Duane Arnold impairment charge of approximately $420 million, and

•	higher operating expenses associated with new investments of approximately $167 million,

•	lower depreciation expense on existing assets of approximately $98 million primarily related to the change in the estimated useful lives of certain equipment (see Note 1 - Electric Plant, Depreciation and Amortization) and lower depletion rates, and

•	lower fuel expense of approximately $85 million primarily related to the sale of certain natural gas generation facilities in 2016 offset in part by higher fuel purchases for the proprietary power and gas trading business.

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14.

(b)	2018 includes cash restricted for the acquisition of Gulf Power on January 1, 2019. See Note 8 - Gulf Power Company.

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(a)

Provide for the funding of loans up to $7,940 million ($2,943 million for FPL) and the issuance of letters of credit up to $2,450 million ($575 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 $893 million of pollution control, solid waste disposal and industrial development revenue bonds (tax exempt bonds) in the event they are tendered by individual bondholders and not remarketed prior to maturity, as well as, the repayment of approximately $193 million of floating rate notes in the event an individual noteholder requires repayment prior to maturity. Approximately $2,389 million of FPL's and $3,871 million of NEECH's bank revolving line of credit facilities expire in 2023.

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

(c)	Excludes short-term borrowings to purchase Gulf Power. See Note 8 - Gulf Power Company.

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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, 2018 rates. See Note 12.

(b)

Includes tax exempt bonds of approximately $9 million in 2020, $46 million in 2021, $96 million in 2022, $15 million in 2023 and $727 million thereafter that permit individual bondholders 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, 2018, all tax exempt bonds tendered for purchase have been successfully remarketed. Also includes floating rate notes of approximately $193 million maturing after 2023 that permit individual noteholders to require repayment prior to maturity. FPL’s bank revolving line of credit facilities are available to support the purchase of tax exempt bonds and the repayment of floating rate notes.

(c)	Represents required minimum payments primarily under long-term fuel transportation contracts and projected capital expenditures through 2023 (see Note 15 - Commitments and - Contracts).

(d)	See Note 15 - Contracts.

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

(f)	At December 31, 2018, FPL had approximately $3,987 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 13.

(g)	At December 31, 2018, NEER had approximately $1,831 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 13.

(h)	Includes lease payment obligations. See Note 14.

(i)	Includes payments related to the acquisition of certain development rights.

(j)	2019 includes cash consideration required for the acquisition of Gulf Power. See Note 8 - Gulf Power Company.

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(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)	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)	See Note 5.

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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 noncash 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)	Amounts have been retrospectively adjusted as discussed in Note 14 and Note 3 - Amendments to Presentation of Retirement Benefits.

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14.

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(a)	Prior period amounts have been retrospectively adjusted as discussed in Note 14.

(b)	Dividends per share were $4.44, $3.93 and $3.48 for the years ended December 31, 2018, 2017 and 2016, respectively.

(c)	See Note 1 - NextEra Energy Partners, LP.

(d)	See Note 1 - NextEra Energy Partners, LP and - Sales of Differential Membership Interests, Note 2, Note 5 - Financial Instruments Accounting Standards Update and Note 6.

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14.

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

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14.

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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. To date, approximately 900 MW of new solar generating capacity has become operational, 600 MW during the first quarter of 2018 and 300 MW during the first quarter of 2019. An additional 300 MW is expected to be operational in 2020. 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 that remained 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. See Storm Fund and Storm Reserve below.

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•	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 cost recovery clause (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 is 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% (the reserve amount was reduced by $30 million to up to $370 million as a result of a settlement in August 2015 related to the acquisition of a 250 MW coal-fired generation facility located in Jacksonville, Florida, which FPL retired in December 2016);

•	an interim cost recovery mechanism for storm restoration costs (see 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)	Relates to fully funded pension obligations acquired in 2018, see Note 8.

(b)	Reflects enhanced early retirement programs.

(c)	NEE's accumulated pension benefit obligation, which includes no assumption about future salary levels, at December 31, 2018 and 2017 was approximately $2,479 million and $2,548 million, respectively.

(d)	Reflects FPL's allocated benefits under NEE's pension plan.

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(a)	The method of estimating the interest cost component of net periodic benefit costs uses a full yield curve approach by applying a specific spot rate along the yield curve.

(a)	See Note 5 for discussion of fair value measurement techniques and inputs.

(b)	Includes foreign investments of $459 million.

(c)	Includes foreign investments of $193 million.

(d)	Includes foreign investments of $77 million.

(e)	Includes foreign investments of $30 million.

(f)	Includes foreign investments of $214 million.

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(a)	See Note 5 for discussion of fair value measurement techniques and inputs.

(b)	Includes foreign investments of $480 million.

(c)	Includes foreign investments of $287 million.

(d)	Includes foreign investments of $73 million.

(e)	Includes foreign investments of $2 million.

(f)	Includes foreign investments of $35 million.

(g)	Includes foreign investments of $233 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.

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(a)	Reflects the netting of approximately $124 million in margin cash collateral received from counterparties.

(b)	Reflects the netting of approximately $65 million in margin cash collateral received from counterparties.

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(a)	Reflects the netting of approximately $39 million in margin cash collateral received from counterparties.

(b)	Reflects the netting of approximately $39 million in margin cash collateral paid to counterparties.

(a)	For the years ended December 31, 2018, 2017 and 2016, FPL recorded gains (losses) of approximately $(31) million, $(169) million and $203 million, respectively, related to commodity contracts as regulatory liabilities (assets) on its consolidated balance sheets.

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(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 equivalents of approximately $85 million ($81 million for FPL) in current other 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)	Included in noncurrent other assets in the consolidated balance sheets.

(f)	See Note 4 - 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 equivalents of approximately $159 million ($128 million for FPL) in current other 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)	Included in noncurrent other assets in the consolidated balance sheets.

(f)	See Note 4 - 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 years ended December 31, 2018, 2017 and 2016, $48 million, $379 million and $397 million of realized and unrealized gains are included in the consolidated statements of income in operating revenues and the balance is included in interest expense.

(b)	Included in net unrealized gains (losses) on foreign currency translation in the consolidated statements of comprehensive income.

(c)	See Note 2.

(d)	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.

(e)	For the years ended December 31, 2018, 2017 and 2016, $112 million, $281 million and $283 million of unrealized gains are included in the consolidated statements of income in operating revenues and the balance is included 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 (Level 2).

(b)	Included in noncurrent other assets in the consolidated balance sheets. At December 31, 2017, primarily a note receivable (Level 3) classified as held for sale and under contract, along with debt secured by this note receivable (see Note 9 - NEER).

(c)	At December 31, 2018 and 2017, substantially all is Level 2 for NEE and all is Level 2 for FPL.

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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, 2018 and 2017 were not material to NEE or FPL.

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(a)	Prior period amounts have been retrospectively adjusted as discussed in Note 14.

(a)	Prior period amounts have been retrospectively adjusted as discussed in Note 14.

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(a)	Prior period amounts have been retrospectively adjusted as discussed in Note 14.

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

(a)	Prior period amounts have been retrospectively adjusted as discussed in Note 14.

(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)	2018 amount reflects NEER's interest, as well as third-party interests, in NEP OpCo.

(b)	Primarily associated with NEP OpCo; approximately 70% of the difference between the investment carrying amount and the underlying equity in net assets relates to goodwill and is not being amortized; the remaining balance is being amortized primarily over a period of 22 to 31 years.

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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 in NEE's consolidated statements of income. See Note 4 - 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.

(c)	Reclassified to other net periodic benefit income in NEE's consolidated statements of income.

(d)	Reclassified and included in gain on NEP deconsolidation. See Note 1 - NextEra Energy Partners, LP.

(e)	Reclassified to retained earnings. See Note 5 - Financial Instruments Accounting Standards Update and Note 6.

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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)

Includes approximately $893 million of variable rate tax exempt bonds that permit individual bondholders to tender the bonds for purchase at any time prior to maturity. In the event these variable rate tax exempt 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 variable rate tax exempt bonds. At December 31, 2018, all variable rate 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 the variable rate tax exempt bonds. Variable interest rate is established at various intervals by the remarketing agent.

(c)	Permit individual noteholders to require repayment prior to maturity, of which approximately $94 million can be required to be repaid beginning in June 2019 and the remainder beginning in November 2019. FPL’s bank revolving line of credit facilities are available to support the purchase of the senior unsecured notes.

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

(e)	Interest rate contracts, primarily swaps, have been entered into with respect to certain of these debt issuances. Additionally, foreign currency contracts have been entered into with respect to the Japanese yen denominated debt. See Note 4.

(f)	Includes approximately $483 million in 2017 of debt held by a wholly owned subsidiary of NEER and collateralized by a third-party note receivable held by that subsidiary. See Note 9 - NEER.

(g)	A holder may convert all or any portion of its notes into NEP common units and cash in lieu of any fractional common unit at the conversion rate. At December 31, 2017, the conversion rate, subject to certain adjustments, was 18.9170 NEP common units per $1,000 principal amount of the convertible notes.

(h)	Includes $365 million of debt as a result of events of default under certain financings caused by the bankruptcy filing of a counterparty to several PPAs.

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(a)	Includes approximately $13 million reclassified to liabilities associated with assets held for sale included in other current liabilities in NEE's consolidated balance sheets.

(b)	Primarily reflects the effect of the revised cost estimate due to the change in useful life of Duane Arnold. See Note 5 - Nonrecurring Fair Value Measurements.

(c)	Primarily reflects sale of ownership interests to a subsidiary of NEP. See Note 1 - Disposal of a Business/Assets.

(d)	See Note 1 - NextEra Energy Partners, LP.

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(a)	Includes AFUDC of approximately $67 million, $59 million, $74 million, $62 million and $36 million for 2019 through 2023, 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 4,395 MW.

(d)	Includes capital expenditures for new solar projects and related transmission totaling approximately 575 MW.

(e)	Construction of a natural gas pipeline is subject to certain conditions, including FERC approval. In addition, completion of another natural gas pipeline is subject to final permitting.

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(a)

Includes approximately $320 million, $385 million, $415 million, $415 million, $410 million and $7,175 million in 2019 through 2023 and thereafter, respectively, of firm commitments related to the natural gas transportation agreements with Sabal Trail and Florida Southeast Connection, LLC. The charges associated with these agreements are recoverable through the fuel clause and totaled approximately $303 million and $155 million for the years ended December 31, 2018 and 2017, respectively, of which $95 million and $41 million, respectively, were eliminated in consolidation at NEE.

(b)

Includes approximately $15 million, $65 million, $65 million, $65 million, $65 million and $1,020 million in 2019 through 2023 and thereafter, respectively, of firm commitments related to a natural gas transportation agreement with a joint venture, in which NEER has a 31% equity investment, that is constructing a natural gas pipeline. These firm commitments are subject to the completion of construction of the pipeline which is expected at the end of 2019.

(c)	Includes an approximately $55 million commitment to invest in clean power and technology businesses through 2022.

(d)	Excludes approximately $20 million in 2019 of joint obligations of NEECH and NEER which are included in the NEER amounts above.

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14 and Note 3 - Amendments to Presentation of Retirement Benefits.

(b)	Interest expense allocated from NEECH is based on a deemed capital structure of 70% debt and differential membership interests sold by NEER's subsidiaries. Residual NEECH corporate interest expense is included in Corporate and Other.

(c)	NEP was deconsolidated from NEER in January 2018. See Note 1 - NextEra Energy Partners, LP.

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

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14 and Note 3 - Amendments to Presentation of Retirement Benefits.

(b)	Represents primarily FPL and consolidating adjustments.

(a)	Amounts have been retrospectively adjusted as discussed in Note 14.

(b)	Represents primarily FPL and consolidating adjustments.

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14.

(b)	Represents primarily FPL and consolidating adjustments.

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(a)	Amounts have been retrospectively adjusted as discussed in Note 14.

(b)	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)	Prior period amounts have been retrospectively adjusted as discussed in Note 14 and Note 3 - Amendments to Presentation of Retirement Benefits.

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

(d)	First quarter of 2018 includes gain on the deconsolidation of NEP (see Note 1 - NextEra Energy Partners, LP).

(e)	First quarter of 2018 reflects a reduction of differential membership interests as a result of a change in the federal corporate income tax rate effective January 1, 2018, which is included in net loss attributable to noncontrolling interests.

(f)	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.

(g)	First quarter of 2017 includes gain on disposal of a business (see Note 1 - Disposal of a Business/Assets); fourth quarter of 2017 includes impairment charges (see Note 5 - Nonrecurring Fair Value Measurements) and net favorable tax reform impacts (see Note 6).

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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 2,495,630 outstanding options, 1,585,180 unvested performance share awards (at maximum payout), 22,446 deferred fully vested performance shares and 116,825 deferred stock awards (including future reinvested dividends) under the NextEra Energy, Inc. Amended and Restated 2011 Long Term Incentive Plan and former LTIP, and 29,962 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.

(c)	Includes 7,079,865 shares under the NextEra Energy, Inc. Amended and Restated 2011 Long Term Incentive Plan and 485,610 shares under the NextEra Energy, Inc. 2017 Non-Employee Directors Stock Plan.

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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 relate to attestation services.

(c)	Tax fees consist of fees billed for professional services rendered for tax compliance, tax advice and tax planning. In 2018 and 2017, approximately $22,000 and $7,000, respectively, was paid related to tax advice and planning services. All other tax fees in 2018 and in 2017 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 2018 and 2017, these fees related to training.

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