1Q15

Financial Results

Conference call and webcast

Date: Friday, 8th May, 2015, 11:30 am (UK/Portuguese time)

Webcast: www.edp.pt

By Phone dial-In number: +44 (0)207 162 0177 Conference ID: 952909Replay: By Phone dial-In number: +44 (0)207 031 4064 Conference ID: 952909

Lisbon, May 7th 2015

Content

in ig h l ig h M H ts a …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… ……	- 2 -
l da d l P fo Co i F ina ia te ns o nc er rm an ce
EB ITD A …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …	- 3 -
f Pro it & Lo be low EB ITD A ss …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …	- 4 -
& Ca Ne Inv t est nts p ex me …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… ….	- 5 -
h F low Ca s …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …	- 6 -
Sta f Co l i da d ina ia l P it ion tem t o te F en nso nc os …… …… …… …… …… …… …… …… …… …… …… …… …… …	- 7 -
bt Ne De t …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… ……	- 8 -
ine Bu Ar s ss ea s
Ov iew be ian lec ic ity d Ga ket I E Ma tr erv : r an s r s …… …… …… …… …… …… …… …… …… …… …… …… ……	10 …- -
d he be ket 1. LT Co Ge ion in I ian M ntr act rat t e ne r ar …… …… …… …… …… …… …… …… …… …… …… ……	- 1 1 -
be l d he be ket 2. L i ise Ac iv it ies in I ian M t t ra r ar …… …… …… …… …… …… …… …… …… …… …… …… …… …	- 12 -
áv 3. ED P R is en ov e …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… ……	- 15 - …
lat d ks be 4. Re Ne in I ia tw g u e or r …… …… …… …… …… …… …… …… …… …… …… …… …… …… ….	- 19 -
l - l 5. Bra i ED P B i z ras …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… ……	- 22 -
Inc Sta & An tem ts om e en ne x
by Inc Sta Bu ine Ar tem ts om e en s ss ea …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… ……	- 26 -
Qu ly Inc Sta art tem t er om e en …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …	- 27 -
l le d d Ge ion As Ins Ca ity Ge ion rat set ta rat ne s: p ac an ne …… …… …… …… …… …… …… …… …… …… ……	- 28 -
lat d Ne ks: Vo lum ist i bu d, C l ien d Ne ks Re tw D te ts tw g u e or es r an or …… …… …… …… …… …… …… ……	- 29 - ……
b l for Su ina i ity Pe sta r ma nc e …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …	- 30 -
ha for ED P S Pe re r ma nc e …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …… …	- 3 1 -

Main Highlights

( ) Inc e S € m tat t om em en	1Q 15	1Q 14	∆ %	bs. ∆ A
Gr Pr fit oss o	1, 42 3	1, 48 3	-4%	-60
Su lies d s ice pp an erv s el c loy s b fits Pe ost rso nn s, e mp ee en e	20 7 16 1	20 2 164	2% -2%	+5 -3
he (ne ) Ot ing rat sts t r o pe co ( ) Ne t O ing 1 rat sts pe co	38 40 6	86 45 3	-56 % -10 %	-48 -47
EB ITD A	1, 01 7	1, 03 0	-1%	-13
Pro vis ion s nd Am isa tio im irm ort t (2 n a pa en ) EB IT	1 33 7 68 0	7 32 4 69 9	-92 % 4% -3%	-6 +1 3 -19
Fin cia l Re sul ts an /as Sh f n fit jo int iat et ntu are o pro ve res soc es fit Pre -ta x p ro	( ) 20 8 ( ) 2 47 1	( ) 14 7 12 56 4	% -42 - -17 %	-61 -13 -94
Inc e t om axe s Ext rd. ibu tio ntr cto rao co n e ne rgy se r	90 15	18 6 15	-52 % 5%	-96 +1
fit for th od Ne eri t p ro e p fit Ne t P ro llin No Int tro st n-c on g ere	36 5 29 7 68	36 4 29 6 68	0% 0% 1%	+2 +1 +1

tio l D Ke Op ata y era na	1Q 15	1Q 14	∆ %	bs. ∆ A
loy Em p ee s	11, 63 2	12, 04 7	-3. 4%	-41 6
tal led ( ) Ins ity MW ca pac	22 43 0 ,	22 08 2 ,	1.6 %	+3 49
Fin cia l D ( ) Ke € m ata y an	1Q 15	1Q 14	∆ %	bs. ∆ A
( fro ) FFO Fu nd tio s m op era ns	62 1	71 7	-13 %	-97

loy Em p ee s	11, 63 2	12, 04 7	-3. 4%	-41 6
( ) Ins tal led ity MW ca pac	22 43 0 ,	22 08 2 ,	1.6 %	+3 49

l D ( ) Ke Fin cia € m ata y an	1Q 15	1Q 14	∆ %
( ) FFO Fu nd fro tio s m op era ns	62 1	71 7	% -13	-97
Ca pex Ma int en an ce Exp sio an n	36 2 10 2 26 0	27 8 11 2 16 6	30 % -8% 57 %	+8 5 -9 +9 4
( ) t in 4 Ne stm ts ve en	37 7	24 5	% 54	+1 32

lan he ( ) Ke Ba S Da € m et ta y ce	r-1 Ma 5	c-1 De 4	∆ %	bs. ∆ A
uit bo ok lue Eq y va	8, 99 5	8, 68 1	4%	+3 13
t d eb Ne t	16, 77 9	17, 04 2	-2%	-26 3
Re lat cei ble gu ory re va s	2, 27 8	2, 50 4	-9%	-22 6
/ t d eb (x ) Ne EB ITD A t	4.1 x	4.7 x	-12 %	-0. 6x
Ad ted t d eb ( ) / (x ) jus 3 EB ITD A t ne	3.6 x	4.0 x	-11 %	-0. 4x

Consolidated EBITDA amounted to €1,017m in 1Q15, 1% lower YoY, impacted by ^a tough comparison basis stemming from outstanding hydro and wind conditions in Iberia during the 1Q14 (compared to below-the-average conditions in1Q15); and more severe drought in Brazil. The performance at our operations in Iberia (EBITDA: -7% YoY to €570m in1Q15) mainly reflected: (i) normalisation of market conditions versus last year's outstanding hydro resources and lowprices, (ii) below-the-average hydro contribution to the production mix stemming from dry quarter; (iii) fewer wholesale trading opportunities in the gas market; and (iv) gain from the sale of gas assets in Murcia, in 1Q15. The performance from our subsidiary EDP Renováveis ('EDPR'; EBITDA +10% YoY to €319m) was propelled by higher average capacity on stream (+6% YoY), higher realised merchant prices in Spain and US; and by ^a 22% appreciation of the USD versus Euro (avg.). The performance of our subsidiary EDP Brasil ('EDPB', EBITDA: +2% YoY to €129m in 1Q15) reflected an increase in hydro generation deficit, from 4% in 1Q14 to 21% in 1Q15, which resulted in ^a €45m decrease YoY, with an impact of -€51m; this was compensated by higher regulated revenues from distribution (mostly reflecting the recent tariff increases).

EDP Group operating costs were broadly stable YoY, at €368m, mainly driven by: (i) -4% YoY in Iberia, driven by headcount reduction (mainly pre-retirements in Portugal); (ii) stability at EDPR (excluding ForEx impact) derived fromtight cost control and larger portfolio; (iii) +6% in Brazil (ex ForEx impact), in line with inflation. Other net operating costs amounted to €38m, reflecting the sale of gas assets in Murcia (€78m gain) and higher generation taxes in Iberia (+€17m YoY, to €43m in 1Q15), prompted by higher generation revenues.

EBIT was 3% lower YoY in 1Q15, at €680m in 1Q15, mainly driven by EBITDA and higher amortisations (+4% YoY mostly reflecting USD appreciation).

Net financial costs totalled €208m in 1Q15, reflecting the impact from the USD appreciation against the Euro on USDdenominated debt and an increase in the average cost of debt from 4.6% in 1Q14 to 4.7% in 1Q15 (stable vs. 2014FY). Income taxes totalled €90m in 1Q15. Additionally, and according to the terms defined in Portugal's ²⁰¹⁵ State Budget, EDP booked ^a €15m cost in 1Q15 on account of the extraordinary tax on the energy sector in Portugal. Noncontrolling interests were flat at €68m in 1Q15, as higher share of minorities at EDPR's net profit pared the lower net profit at the level of EDP Brasil and its generation subsidiaries. Net profit attributable to EDP shareholders was stable YoY, at €297m.

Net debt fell from €17bn in Dec-14 to €16.8bn in Mar-15, despite the +€0.4bn impact from ForEx derived from the 13% appreciation of USD vs. EUR (end of period). Net debt evolution reflected: (i) €0.5bn reduction prompted by funds from operations (FFO), net of maintenance capex; (ii) €0.2bn reduction backed by regulatory receivables, following €0.5bn securitised in Portugal; and (iii) €0.2bn net impact from expansion capex (mainly in hydro and wind), changes in working capital with fixed asset suppliers, net proceeds from TEIs and net divestments. Total cash andavailable liquidity facilities amounted to €5.8bn by Mar-15. This liquidity position allows EDP to cover its refinancing needs beyond 2016.

On April ²¹st, EDP shareholders approved the ²⁰¹⁴ dividend payment amounting to €676m (€0.185/share), to be paidon the next May ¹⁴th (ex-dividend date on May ¹²th).

(1) Net Operating Costs = Operating Costs (Supplies and services + Personnel costs + Costs with social benefits) + Other operating costs (net); (2) Depreciation and amortisation expense net of compensation for depreciationand amortisation of subsidised assets; (3) Net of regulatory receivables; (4) Net investments defined in note (5) of page 5 of this document.

EBITDA Breakdown

( ) ITD A € m EB	1Q 15	1Q 14	∆ %	∆ A bs.	1Q 14	2Q 14	3Q 14	4Q 14	1Q 15	1Q 15	Yo Y ∆ A bs.	1Q 15 ∆ %	Qo Q ∆ A bs.
LT Co ed Ge ion ntr act rat ne	15 3	17 6	% -13	-22	17 6	18 0	15 6	15 9	15 3	% -13	-22	-4%	-6
Lib lise d A s Ib ctiv itie eri era a	10 7	19 2	-44 %	-85	19 2	12 3	52	49	10 7	-44 %	-85	12 0%	59
lat ed ork s Ib Re Ne eri tw gu a	32 4	24 5	32 %	9 +7	24 5	31 4	25 7	22 6	32 4	32 %	79	44 %	98
Wi nd & So lar Po we r	31 9	28 9	10 %	+3 0	28 9	21 8	14 1	25 5	31 9	10 %	30	25 %	63
zil Bra	12 9	12 7	2%	+2	12 7	13 9	10 8	24 5	12 9	2%	2	-47 %	-11 6
Ot he r	( ) 15	2	-	-17	2	( 2 )	( 2 )	( ) 7	( ) 15	-	-17	-10 1%	-7
lid d Co ate nso	1, 01 7	1, 03 0	-1%	-13	1, 03 0	97 2	71 3	92 7	1, 01 7	-1%	-13	10 %	90

Consolidated EBITDA amounted to €1,017m in 1Q15, 1% lower YoY, reflecting outstanding hydro and wind conditions in Iberia during the 1Q14 (compared to below-the-average conditions in1Q15); more severe drought in Brazil (-€45m YoY on EBITDA) and ^a €78m gain from the sale of gas assets in Murcia, both in 1Q15. In Portugal, hydro resources in 1Q15 fell 26% short of LT average (hydro factor: 0.74), compared to ^a 57% premium over LT average in 1Q14 (hydro factor: 1.57). At EDPR level, the average load factor was 3% lower than the P50 scenario in 1Q15, versus +12% in1Q14. In Brazil, the more severe drought in 1Q15 translated into hydro generation deficit of 21%(GSF of 79%) versus 4% in 1Q14 (GSF at 96%). ForEx impact on EBITDA totalled +€24m (+2% of EBITDA), mainly derived from the USD 22% appreciation vs. Euro.

LONG TERM CONTRACTED GENERATION IN IBERIA (15% of EBITDA) - EBITDA was 13% lower YoY (-€22m), at €153m in 1Q15, mainly driven by ^a 50% decrease in the production of mini-hydroplants (-€15m YoY) and by the depreciation of the PPA/CMEC net asset base in ^a context of very low inflation.

LIBERALISED ACTIVITIES IN IBERIA (10% of EBITDA) – EBITDA was €85m lower YoY, at €107m in1Q15, reflecting: (i) -€51m YoY in gross profit from the electricity business, derived from hydro's lower contribution to the production mix (41% in 1Q15 vs. 67% in 1Q14) and fewer opportunities for managing energy markets' volatility; (ii) -€12m YoY in gross profit from gas supply derivedfrom fewer wholesale trading opportunities; and (iii) -€27m YoY on EBITDA, mainly related tohigher generation taxes in Iberia and higher costs with client services related to the ongoing liberalisation process.

REGULATED NETWORKS IN IBERIA (31% of EBITDA) – EBITDA rose by 32% YoY (+€79m), to€324m in 1Q15, impacted by ^a €78m one-off gain booked on the sale of gas assets in Murcia in1Q15. Adjusted for this, EBITDA was broadly stable, as progress on cost efficiency measures offset the impact from lower regulated revenues. Gross profit was 2% lower YoY (-€10m) in 1Q15, driven by the start of the new 2015-17 regulatory period and the lower return on RAB inelectricity distribution in Portugal (6.36% in 1Q15 vs. 8.37% in 1Q14), stemming from the lower Portuguese sovereign yields (YoY).

WIND & SOLAR POWER (31% of EBITDA) – EDPR's EBITDA increased by 10% YoY (+€30m) to€319m in 1Q15, propelled by operations in North America (+€29m YoY), on the back of USDappreciation vs. Euro (+€23m) and higher realised prices in the market. EBITDA in Europe was stable, as higher EBITDA in Spain (+€8m prompted by ^a recovery in average realised price in the pool) was offset by lower EBITDA in Portugal (-€8m, penalised by outstanding wind resources in1Q14 and low inflation context).

BRAZIL (12% of EBITDA) - EDPB's contribution to consolidated EBITDA rose by 2% YoY (+€2m), to€129m in 1Q15, with no material ForEx impact in the period. In local currency, EBITDA fromdistribution advanced 64% YoY (+R\$90m), fuelled by higher regulated revenues (mainly reflecting the recent tariff increases) and by the recognition of regulatory receivables at gross profit level as from Dec-14. Generation and Supply EBITDA fell by 28% YoY (-R\$82m), as higher electricity costs stemming from low GSF in the period (79% in 1Q15 vs. 96% in 1Q14) largely outstood the more favorable seasonal allocation of volumes and lower PLD. Losses due to low GSF amountedR\$165m in 1Q15 vs. R\$19m in 1Q14.

Profit & Loss Items below EBITDA

fit ( ) Pro & Los s It be low EB ITD A € m em s	1Q 15	1Q 14	∆ %	bs. ∆ A	1Q 15	1Q ∆ %	Qo Q 15 ∆ A	bs.
EB ITD A	1, 01 7	1, 03 0	-1%	-13	1, 01 7	10	%	90
Pro vis ion s Am isa tio nd im irm ort t n a pa en	1 33 7	7 32 4	-92 % 4%	-6 13	1 33 7	-98 -12	% %	-30 -46
EB IT	68 0	69 9	-3%	-19	68 0	32	%	16 7
fin l in Ne cia t ter est an fin Ca ita lize d cia l co sts p an for eig xch di ffe d d eri Ne t vat n e an ge ren ces an es inc Inv est nt me om e / p nd n & ed l ca bil Un wi ing sio ica nsi itie w en m re res po s l G / ( ) Ca ita ain Los p s ses he als Ot r F ina nci Fin cia l R lts an esu	( ) 23 8 32 ( ) 40 0 ( ) 11 - 50 ( ) 20 8	( ) 21 6 41 19 0 ( ) 17 ( ) 0 27 ( ) 14 7	-10 % -22 % - 73 5% 33 % - 87 % % -42	-22 -9 -58 0 6 0 23 -61	( ) 23 8 32 ( ) 40 0 ( ) 11 - 50 ( ) 20 8	-5% -28 34 18 13 -76	% % - % - 8% %	-11 -12 20 -0 3 -11 8 29 -90
ha f n fit in j oin d a cia S et t v tur tes re o pro en es an sso	( ) 2	12	-	-13	( ) 2	83	%	8
fit Pre x P -ta ro Inc e T om axe s Ef fec ( ) tiv e T % rat ax e	47 1 90 19 %	56 4 18 6 33 %	-17 % -52 % -	-94 -96 -13 .8 p p	47 1 90 19 %	22 15 10 8%	% 3%	85 54 0.1 pp
rdi Co ibu tio n f he Se Ext ntr t En cto rao na ry or erg r y	15	15	5%	1	15	-1%		-0
áve ED P R is en ov do l Ene ias Br asi rg he Ot r No llin Int tro sts n-c on g ere	44 18 6 68	39 27 2 68	13 % -32 % 22 8% 1%	5 -8 4 1	44 18 6 68	78 -67 -15	% % - %	19 -37 6 -12
fit rib b le t ha ho lde f E Ne t P Att o S DP uta ro re rs o	29 7	29 6	0%	1	29 7	17	%	43

Amortisation and impairment (net of compensation from depreciation and amortisation of subsidisedassets) increased 4% YoY to €337m in 1Q15, mostly reflecting higher depreciations at EDPR level deriving from the new capacity installed over the last ¹² monts and the USD appreciation against the EUR (€11m).

Share of net profit in joint ventures and associates amounted to -€2m in 1Q15 with the maincontributions to this item coming from: i) EDPR's 40% equity stake in ENEOP in Portugal which fell to €7min 1Q15 (-€2m YoY); ii) our 50% equity stake in Pecém ^I that fell by €3m YoY to -€8m in 1Q15; and iii) our 50% equity stake in Jari with ^a contribution of -€4m vs. €0m in1Q14.

Net financial costs increased 42% YoY to €208m in 1Q15. Net interest expenses rose 10% YoY reflecting ^a higher average cost of debt, up from 4.6% in 1Q14 to 4.7% in 1Q15, and explained by the appreciationof the USD against the EUR and its impact on interest paid on USD denominated debt. Net ForEx differences and derivatives totalled -€40m in 1Q15 (-€58m YoY in 1Q15) and are mostly related to forex and financial operations in energy markets and commodities. Capitalised financial costs reached €32m in1Q15, down €9m YoY, mostly related with the hydro projects in Portugal. Other financials totalled €50min 1Q15, including ^a €32m gain with the tariff securitisation deal (vs. €12m in 1Q14).

Income taxes amounted to €90m in 1Q15, representing an effective tax rate of 19% (vs. 33% in 1Q14). The decrease is partly explained by the gain on the sale of the gas distributions assets not contributing tothe taxable income perimeter. On another note, the fiscal terms in Iberia were eased vs. ²⁰¹⁴ with ^a 2p.p. fall in the corporate tax rate from 31.5% in ²⁰¹⁴ to 29.5% in ²⁰¹⁵ in Portugal and from 30% in ²⁰¹⁴to 28% in 2015. Additionally, and according to what had been defined in Portugal's ²⁰¹⁵ State Budget, in1Q15, EDP contributed with €15m to the extraordinary contribution that is being applied to the energy sector.

Non-controlling interests were flat at €68m in 1Q15, as EDPR's sale of minority stakes in wind farms and the capital gain with the sale of gas assets at Naturgas level (5% minority stake) were offset by lower net profit at the level of EDPB and its generation subsidiaries. All in all, net profit attributable to EDPshareholderswas flat YoY at €297m in 1Q15.

Capital Expenditure & Net Investments

( ) Ca € m pe x	1Q 15	1Q 14	∆ %	∆ A bs.	1Q 14	2Q 14	3Q 14	4Q 14	1Q 15	2Q 15	3Q 15	4Q	CA PEX 1Q 15
LT ed Ibe ria ntr act												15
co ge n.	4	3	% 31	+1	3	7	10	16	4				Ma int en an ce
Lib lise d a s Ib ctiv itie eri era a	93	124	-25 %	-32	124	17 1	11 5	14 8	93				Ca pex
lat ed ork s Ib Re eri tw gu ne a	69	70	-1%	-1	70	89	87	13 6	69				28%
Wi nd & sol ar po we r	16 3	44	27 1%	+1 19	44	69	16 5	43 2	16 3
zil Bra	21	26	-21 %	-6	26	28	39	26	21
he Ot r	14	11	25 %	+3	11	17	15	24	14				72%
ED P G rou p	36 2	27 8	30 %	+8 5	27 8	38 1	43 1	78 2	36 2
Exp sio n C an ap ex	26 0	16 6	57 %	+9 4	16 6	23 3	27 8	57 2					sio Exp an n Ca pex
Ma int Ca en an ce pe x	10 2	2 11	-8%	-9	2 11	8 14	3 15	21 0	10 2

Ge ion Pr oje Un de rat cts ne r ( ) Co tio € m nst ruc n	MW	Ca x 1 pe	Q 15 Ac	( ) c. C 1 ap ex	l i da Co te ns o ity ca p ac	d ca p ex Ma int en an ce	d nte am ou ca p ex wa	€ 3 6 2m to low 8 % s	he in 1 Q 15 t , (- Yo Y € 9m er	bu l k f o ), € 1 0 at	h h ( ic 7 2 w 2m in 1 Q	% ) ly de in ma ly 15 st mo ,	d he f hy dro & ion in te to t nst t vo co ruc o ne w w d lat d ks be in in I ia tra te tw co nc en reg u e ne or r an
dro l Hy Po rtu ga nd ( ) Wi Po 2 we r	1, 44 60	9 1	84	1, 66 8	i l. Bra z hy Ca in p ex	dro ca p ac	de ity un r	ion nst t co ruc	in Po rtu g	l a am ou	d € 8 nte to	4m in 1 Q 15	ho f d he € 1 17 inv in 1 Q 14 is rt est t s o m e as g rou p , ,
l To ta	2, 05	1	174	1, 91 4	h ing ap p roa c	he t en	d f nst o co ruc	ion f t o sev	l hy dro era	lan ts. p	is bu ED P	i l d ing 3 ne	( ) lan d ing i ixo 2 17 3 M W Ba ts at w p an rep ow er s:
					bo Sa r, a ne ); ( ) 2H i i 15	lan t p w w 8 1M W R at	h it p um p / i be ira d io	h h ing ic w , ( i da Erm ne	do str wn ea ) lan du t w p	lan ( 3 t m p in 1H 15 e	) 0 M W sta ( ) i i i 9 6 3 M ;	d in rte up in W rep ow	( he d 1 Q 15 is in t t ect to str res ex p e co me on ea m ing d ion in 2H 15 ect to sta rt t er s, ex p e up op era s
fin l Ne cia t an / ( ) ( ) inv Div €m est nts est nts me me		1Q 14	∆ %	bs. ∆ A	d ( ) iv 2 6 an ( f € 2 1m o w 6 6 U	( 3 M W Fo h h, ic co rre 2 0	Tu z a, ne w p d ing sp on Bra i 14	lan h it t w p U S D to ap Eu	) du ing um p iat ion p rec	in 2H 1 e Eu vs ro t	6. Ca p ex ), Yo Y st mo iss ion	in in ne w w ly l loc ate a	d & lar ity ( ) l le d ED PR € 1 6 3m in 1 Q 15 tot so ca p ac a d he f de 6 0 1M W ity ion to t nst t o ca p ac un r co ruc ha lre ion In t
Fin cia l In stm ts an ve en	15	5	-	0 +1	( % in l, Bra i z ca p	% S, in l le d tot ex a	l, % z € 2 1m in 1	in rop e d Q 15 an wa	), ity ca p ac ly de st s mo	ly rec en co d te to vo	mm d ist i ou r r	d d e an en bu bu ion t s	dy in ity in ts nc em en ca p ac a a op era ine ss.
Fin cia l D ive stm ts an en	18 7	29	-	+1 58	l Ov era an	lu d ex c	hy ing ne w	dro j ect ro	in Bra i z	ha ED	€ en	bn 1. 9 so	far de in 2. 1 G W ion ity t o ne w en era ca ac un
( ) Ga Sp ain ts s a sse Wi nd set as s	18 5 -	- 28	- -	+1 85 -28	l, ion nst t co ruc	d No te t	ha ED P t	p l 's Bra i s co	s ion nst t ruc	l, P ks f wo r o	t s sp ne w g en	ion t era ca p	f g p fu l ly d ho ity in ity tra te et ac are co nc en eq u -m

int Ma Ca en an ce pe x	10 2	11 2		-8%	-9	11 2 14 8
ion oje de Ge Pr Un rat cts ne r tio ( ) Co € m nst ruc n	MW	Ca pe	x 1 Q 15	Ac c. C	( ) 1 ap ex
dro l Hy Po rtu ga ( ) Wi nd Po 2 we r	1, 44 60	9 1	84		1, 66 8	l. Bra i z
l To ta	2, 05	1			1, 91 4
fin cia l Ne t an / inv ( Div ) ( ) €m est nts est nts me me		1Q 14	∆ %		bs. ∆ A
l In Fin cia stm ts an ve en	15	5		-	+1 0	i l, Bra z

Ma int Ca en an ce pe x	10 2	11 2	-8%	-9
ion oje de Ge Pr Un rat cts ne r tio ( ) Co € m nst ruc n	MW	Ca x 1 pe	Q 15 Ac	( ) c. C 1 ap ex
dro l Hy Po rtu ga ( ) Wi nd 2 Po we r	1, 44 60	9 1	84 90	1, 66 8 24 6	l. Bra i z
l To ta	2, 05	1	174	1, 91 4

fin cia l Ne t an / inv ( Div ) ( ) €m est nts est nts me me	1Q 15	1Q 14	∆ %	bs. ∆ A
l In Fin cia stm ts an ve en	15	5		+1 0 -	i l, Bra z
Fin cia l D ive stm ts an en	18 7	29		58 +1 -
( ) Ga Sp ain ts s a sse nd Wi set as s he Ot r	18 5 - 2	- 28 1		+1 85 - -28 - +2 -
l To ta	( ) 17 2	( ) 24		-14 8 -

( ) Ne t In €m stm ts ve en	1Q 15	1Q 14	∆ %	bs. ∆ A
Ca pex l in Fin cia stm ts an ve en 's a ed ED PR ion t ro tat sse pr oce s	36 2 15 -	27 8 5 ( ) 38	30	% +8 5 +1 0 - +3 8 -

( ) Ne t In €m stm ts ve en	1Q 15	1Q 14	∆ %	bs. ∆ A
Ca pex l in Fin cia stm ts an ve en 's a ion ed ED PR t ro tat sse pr oce s	36 2 15 -	27 8 5 ( ) 38	30 % - -	+8 5 +1 0 +3 8
l To ta	37 7	24 5	54 %	+1 32

260 Capex in hydro capacity under construction in Portugal amounted to €84m in 1Q15, short of €117m invested in 1Q14, as the group is approaching the end of construction of several hydro plants. EDP is building ³ new plants and ² repowerings: (i) 173MW at BaixoSabor, ^a new plant with pumping, which downstream plant (30MW) started up in 1Q15 (the rest is expected to come on stream in2H15); (ii) 81MW at Ribeiradio/Ermida (new plant) due in 1H15; (iii) 963MW in repowerings, expected to start up operations in 2H15; and (iv) 263MW (Foz Tua, new plant with pumping) due in 2H16. Capex in new wind & solar capacity (EDPR) totalled €163m in 1Q15(€21m of which, corresponding to USD appreciation vs. Euro YoY), mostly allocated to the 601MW of capacity under construction(66% in US, 20% in Brazil, 14% in Europe), capacity recently commissioned and enhancements in capacity already in operation. InBrazil,capex totalled €21m in 1Q15 and was mostly devoted to our distribution business.

Overall, and excluding new hydro projects in Brazil, EDP has spent €1.9bn so far in 2.1GW of new generation capacity under construction. Note that EDP Brasil's construction works of new generation capacity are fully concentrated in equity-methodaccounted hydro projects: Cachoeira-Caldeirão (219MW), with PPA due in Jan-17, and S. Manoel (700MW), due in May-18.

Net financial divestments totalled €172m in 1Q15. Financial divestments amounted to €187m in 1Q15, mainly driven by the conclusion of the sale to Redexis of our gas distribution assets in Murcia, with proceeds of €185m (the financial closing of the sale of the remaining asset perimeter agreed, for ^a consideration of €51m, is expected occur in 2Q15). Financial investments in 1Q15 mainly related to EDPB's equity contributions to Cachoeira-Caldeirão hydro project.

Overall, net investments amounted to €377m in 1Q15 (vs. €245m in 1Q14), including €362m of capex and €15m of financial investments. Regarding EDPR's asset rotation strategy it is worth to note that: (i) In 1Q15, EDPR agreed on the sale of ^a minority stake in ^a 30MW-solar PV park in US for USD30m, although the respective closing and cash-in is expected to occur only in 2Q15; (ii) In2Q15, EDPR received from Fiera Axium USD348m, following the financial closing of the sale of ^a minority stake in ^a wind far mportfolio of 1,101MW located in the US, agreed in Aug-14.

FFO & Cash Flow Statement

nd fro tio ( ) Fu Op €m s m era ns	1Q 15	1Q 14	∆ %	bs. ∆ A

EB ITD A	01 1, 7	03 0 1,	-1%	-13
Cu inc nt e t rre om ax	( ) 11 2	( ) 75	% -49	-37
fin cia l in Ne t ter est an s	( ) 23 8	( ) 21 6	-10 %	-22
d d ivid ds ed fro Ne t In eiv m A cia tes co me an en rec sso	( ) 2	12	-	-13
ash No ite n-c ms	( ) 45	( ) 34	-33 %	-11
FFO - F ds Fro Op tio un m era ns	62 1	71 7	-13 %	-97

lid d C h F low ( ) - Ind ire ho d Co €m Me ate ct t nso as	1T 15	1T 14	∆ %	bs. ∆ A
	01 7	03	-1%	-13
EB ITD A	1,	0 1,
Cu inc nt e t rre om ax	( ) 11 2	( ) 75	% -49	-37
Ch s in tin ork ing ita l an ge op era g w ca p	37 2	( ) 39 0	-	+7 63
lat ble Re Re cei gu ory va s	22 6	( ) 24 7	-	+4 73
ash No ite n-c ms	( ) 45	( ) 34	-33 %	-11
he ork l Ot ing ita r w ca p	19 1	( ) 10 9	-	+3 00
t C h f Op tin tiv itie Ne Ac as rom era g s	1, 27 8	56 5	12 6%	+7 13

Ca pex	( ) 36 2	( ) 27 8	-30 %	-85
Exp sio an n	( ) 26 0	( ) 16 6	-57 %	-94
Ma int en an ce	( ) 10 2	( ) 11 2	8%	+9
Ch s in ork ing ita l fr uip lier nt an ge ca p om eq me sup p s w	( ) 11 3	( ) 10 5	-7%	-8
/ fin cia l ( inv ) div Ne t est nts est nts an me me	17 2	24	62 0%	+1 48
fin l in aid Ne cia t ter est an s p	( ) 26 0	( ) 25 5	-2%	-5
ide nd d fro Div cei m A cia tes s re ve sso	4	8	-55 %	-4
ide nd aid Div s p	( ) 0	( ) 0	-22 %	-0
ED P S ha reh old ers	-	-	-	-
Ot he r	( ) 0	( ) 0	-	-
ds fro titu tio l Pa hip s in ind Pro Ins US rtn cee m na ers w	( ) 18	( ) 12	-46 %	-6
Eff f e xch flu ati ect rat ctu o an ge e on s	( ) 43 6	( ) 36	-	-40
he ha Ot tin r n on -op era g c nge s	( ) 2	68	-	0 -70
/ ( ) De Inc in Ne t D bt cre ase rea se e	26 3	( ) 21	-	+2 84

lid d C h F low ( ) - Dir ho d Co €m M ate ect et nso as	1Q 15	1Q 14	∆ %	bs. ∆ A

Op tin Ac tiv itie era g s
Ca sh eip fro ts tom rec m cus ers	3, 78 6	4, 02 7	-6%	-24 2
ds fro ari ff a dju ale Pro m t stm ts s cee en s	49 9	15 0	23 4%	+3 50
sh id t lier nd el Ca pa o s up p s a pe rso nn	( ) 3, 11 8	( ) 3, 30 7	6%	+1 89
oth Co ssi & nts nce on re er	65	( ) 29 4	-	+3 58

( ) - Co lid d C h F low €m Dir ho d ate ect M et nso as	1Q 15	1Q 14	∆ %	bs. ∆ A

tin tiv itie Op Ac era g s
sh fro Ca eip ts tom rec m cus ers	3, 78 6	4, 02 7		-24 2
ds fro ff a dju ale Pro ari m t stm ts s cee en s	49 9	15 0	23 4%
Ca sh id t lier nd el pa o s up p s a pe rso nn	( ) 3, 11 8	( ) 3, 30 7	6%	+1 89
Co ssi & oth nts nce on re er	65	( ) 29 4	-	+3 58
h f tio Ne t C Op as rom era ns	1, 23 2	57 6	114 %	+6 56
/ ed (pa id ) Inc eiv e t om ax rec	46	( ) 11	-	+5 7
h f Ne t C Op tin Ac tiv itie as rom era g s	27 8 1,	56 5	12 6%	13 +7
h f sti tiv itie Ne t C In Ac as rom ve ng s	( ) 27 9	( ) 36 2	23 %	+8 3
h f Fi nci tiv itie Ne t C Ac as rom na ng s	( ) 1, 35 2	( ) 68 6	-97 %	-66 6
C ha in Ca h a nd Ca h E iva len ts ng es s s qu	( ) 35 3	( ) 48 2	27 %	30 +1
Eff f e xch flu ati ect rat ctu o an ge e on s	( ) 25	11	-	-36

Funds from operations (FFO) decreased 13% YoY to €621m in 1Q15, including: i) ^a €37m increase in current income taxes, driven by the cashing-in of €500m regarding the securitisation of part of the ²⁰¹⁴ Portuguese tariff deficit; and ii) ^a €22m increase in net financial interests reflecting higher average cost of debt (4.7% in1Q15) and ^a 22% YoY appreciation of the avg. USD vs. the EUR between Mar-14 and Mar-15.

Net cash from operating activities went up €713m YoY to €1,278m in 1Q15. Regulatory receivables decreased€226m vs. Dec-14, reflecting: i) €242m of net cash proceeds from regulated activities in Portugal, including - €465m from the securitisation deal undertaken in 1Q15; ii) ^a €42m increase from Spain, reflecting +€44m fromEDP España share of the gas tariff deficit; and iii) -€26m of regulatory receivables from our electricity distribution activities in Brazil. Other changes in working capital, which amounted to €191m in 1Q15, include ^a €32m gain regarding the mentioned tariff deficit securitisation deal; also, this caption reflects both ^a fall in coal inventories and lower value added tax receivables in both Portugal and Brazil. It is worth recalling that 'other changes in working capital' in 1Q14 were negatively impacted by the recognition of about €120m of contributions from CDE/CCEE to our Brazilian DisCos to be cashed-in later on during the year.

Expansion capex totaled €260m in 1Q15, translating the ongoing construction of new hydro and wind capacity. Note that change in working capital from equipment suppliers relates essentially to the renewable projects construction and development activity at EDPR level.

Net financial divestments amounted to €172m in 1Q15, mostly reflecting the conclusion of the sale to Redexis of our gas distribution assets in Murcia.

EDP AGM held on April ²¹st, 2015, approved ^a gross dividend of 0.185 euros per share (flat vs. the previous year), which corresponds to ^a total amount of €676m, to be paid on May ¹⁴th, 2015.

The €436m negative impact on net debt from effects of exchange rate fluctuations essentially reflects the appreciation of the US Dollar (+13%) against the Euro between Dec-14 and Mar-15. Overall, net debt went down €263m vs. Dec-14 to €16.8bn as of Mar-15.

Looking forward, as part of EDPR's asset rotation strategy, USD348m were cashed-in in Apr-15 regarding the sale to Fiera Axium of ^a 49% stake in ^a 1.1GW portfolio of wind assets located in the US, in accordance with the terms of the agreement signed in Aug-14. Additionally, EDP group agreed on several other transactions withclosing expected for the course of 2015: i) within the scope of EDP's strategic partnership with CTG, the sale of ^a 49% stake in our wind business in Brazil (R\$365m, including R\$101m of estimated future equity contributions) and the execution of the MoU upon the sale of 49% of EDPR's 40% share in ENEOP assets; and ii) the acquisitionof Eneva's 50% stake in Pecém ^I coal facility (R\$300m equity payment), which will result in the full consolidationof Pecém ^I from then onwards.

( ) As € m set s		Ma s. D r. v ec.
	Ma r-1 5	De c-1 4	bs. ∆ A

lan nd Pro uip rty t a nt, t pe , p eq me ne	21 20 2 ,	20 52 3 ,	67 9
ibl Int ts, net an g e a sse	5, 72 3	5, 81 3	-90
od ll Go wi	3, 40 3	3, 32 1	82
l in s h eld fo le, Fin cia nd stm ts a set net an ve en as r sa	21 8 1,	27 2 1,	-55
de fer red d c Tax set t as s, an urr en	51 6	59 0	-74
ies Inv tor en	23 3	26 6	-33
de ble Tra cei et re va s, n	2, 14 0	2, 12 0	21
he Ot ts, net r a sse	5, 76 1	5, 92 3	-16 3
llat l de Co sits era po	27 7	42 9	-15 2
Ca sh d c ash uiv ale nts an eq	2, 23 6	2, 61 4	-37 8
l A To ta ts sse	42 71 0 ,	42 87 3 ,	-16 3

( ) Eq uit € m y	Ma r-1 5	De c-1 4	∆ A bs.

uit ibu tab le t ity ho lde f E Eq ttr DP y a o e qu rs o	8, 99 5	8, 68 1	31 3
ling No In tro ter est n-c on	3, 24 7	3, 28 8	-41
l Eq uit To ta y	12, 24 1	11, 96 9	27 2

( ) Lia bi liti € m es	Ma r-1 5	De c-1 4	bs. ∆ A
Fin cia l de f w ich	19, 50 9	20 29 8	-78 9
bt, an o : diu d lo Me	16 2	, 40 1	-23 9
-te m an ng rm Sh	16, 34 7	16, 89 7	-55 0
ort te rm be fits de l be low	3, 82 8	3, 88 0
loy ( ) Em tai p ee ne	1,	1,	-52
( ) Ins titu tio l pa hip lia bil ity US ind rtn na ers w	1, 184	1, 06 7	11 8
vis ion Pro s	47 5	48 6	-11
lia bil de fer red d c Tax itie t s, an urr en	1, 40 6	1, 22 1	18 5
fer red fro rsh De in ins ips t. p art co me m ne	80 6	73 5	71
he r li ab ilit Ot ies et , n	5, 26 0	5, 21 7	42
l Li bi liti To ta a es	30 46 9 ,	30 90 4 ,	-43 5

l Eq uit nd Lia bi liti To ta y a es	42 71 0 ,	42 87 3 ,	-16 3

( ) ( ) Em loy Be fits €m 1 p ee ne	Ma r-1 5	De c-1 4	bs. ∆ A

( ) Pe nsi 2 on s dic al c d o the Me are an r	88 9 94 0	93 0 95 0	-42 -10
loy fits Em Be p ee ne	1, 82 8	1, 88 0	-52

lat b les ( ) Re Re cei €m gu ory va	Ma r-1 5	De c-1 4	∆ A bs.
( ) l D istr ibu tio nd Ga 3 Po rtu ga n a s l A l C iat ion Po ME C D rtu ga nn ua ev Sp ain zil Bra	1, 91 5 15 9 44 16 1	2, 20 3 11 2 2 18 7	-28 8 46 42 -26
Re lat Re cei b les gu ory va	2, 27 8	2, 50 4	-22 6

Total amount of property, plant & equipment and intangible assets increased €0.6bn vs. Dec-14 to €26.9bn as of Mar-14, mainly reflecting: i) +€0.4bn of capex in the period; ii) -€0.3bn from depreciations in the same period; and iii) +€0.6bnmainly resulting from the +13% change of the US Dollar against the Euro between Dec-14 and Mar-15. As of Mar-15, EDP's balance sheet included €3.6bn of works in progress (14% of total consolidated tangible and intangible assets) largely related to investments already incurred in regulated networks, power plants, wind farms development, equipment or concession rights which are not yet operating.

The book value of financial investments & assets held for sale went down €0.1bn vs. Dec-14, to €1.2bn as of Mar-15, reflecting the conclusion, in Jan-15, of the sale of the gas assets in Spain and the mark-to-market of some of our financial stakes. Note that financial investments essentially refer to our financial stakes in Jari (50%), Cachoeira Caldeirão (50%), Pecém ^I (50%), EDP Asia (50%), which is the owner of ^a 21% stake in CEM, ENEOP (40%), REN (3.5%) and BCP (2.0%).

Tax assets net of liabilities, deferred and current, went down €0.3bn vs. Dec-14, partly due to lower fiscal receivables, related to value added taxes and to the expected extraordinary contribution applied to the energy sector. Trade receivables and other assets (net) decreased €0.1bn vs. Dec-14 to €7.9bn as of Mar-15, driven essentially by the securitisation deal achieved during 1Q15, which was partly offset by regulatory receivables generated during the period.

Total amount of EDP's net regulatory receivables went down €0.2bn vs. Dec-14, to €2.3bn as of Mar-15, reflecting: i) ^a €242m decrease from Portugal; ii) ^a €42m increase from Spain; and iii) ^a €26m decrease from Brazil.

Equity book value went up €0.3bn to €9.0bn as of Mar-15, mainly reflecting €297m of net profit for the period.

Pension fund, medical care and other employee benefit liabilities (gross, before deferred taxes) fell by €52m vs. Dec-14 to€1,828m as of Mar-15, reflecting the recurrent payment of pension and medical care expenses in 1Q15. Institutional partnership liabilities increased €118m vs. Dec-14 to €1,184m as of Mar-15 reflecting the US Dollar appreciation and the benefits paid to the tax equity partners during the period. Note that the referred amount of institutional partnershipliabilities was adjusted by deferred revenues related to tax credits already benefited by the institutional investors and yet due to be recognised in the P&L.

Consolidated Net Financial Debt

( ) No mi l Fi nci l D bt by Co €m na na a e mp an y		Ma r-1	5	De c-1 4	∆ %	bs. ∆ A
d E Fi ED P S .A. DP BV		16, 76	9	17, 67 6		-5% -90 7
an na nce rod ão & he ED P P Ot uç r			124	17 8	-30	% -54
áve ED P R is en ov		93	7	92 8		1% 9
il ED P B ras		1, 11	6	98 8	13	% 12 8
mi l Fi nci l D bt No na na a e		18, 94	6	19, 76 9		-4% -82 3
		31	0	37 1	-17	% -62
ed bt Ac In De ter est cru on alu f H ed d D eb Fai r V t e o		25	3	15 7	61	96 %
ge ( ) De riv ati cia ted ith De bt 2 ve s a sso w		( 20	) 4	( 20 2 )		-2 -1%
Co llat l de sits iat ed ith bt De era po as soc w		( 27	) 7	( ) 42 9	35	15 2 %
l Fi nci l D bt To ta na a e		19, 02	8	19, 66 7		-3% -63 9
h a nd h e len Ca iva ts s ca s		2, 23	6	2, 61 4	-14	% -37 8
qu ED P S .A. ED P F ina BV d O the nce an r		1, 19	9	1, 98 9	-40	% -79 0
, áve is ED P R en ov		53	3	36 9	45	% 164
il ED P B ras		50	5	25 7	97	% 24 8
Fin cia l as fai lue hro h P &L set t t an s a r v a ug			13	11	24	% 3
ED P C lid d N De bt ate et on so		16, 77	9	04 2 17,		-2% -26 3

Cre dit Lin by r-1 5 ( €m ) Ma es	xim Ma um Am nt ou	mb Nu Co ter un	f er o rts pa	ai Av Am	la b le nt ou	Ma ity tur
lvin dit cili Re Cre Fa						Jun -19
ty vo g Re lvin Cre dit Fa cili ty vo	3, 15 0 10 0		21 1		3, 15 0 10	De c-1 6
g stic Cr ed it L ine Do me s	20 0		9		0 20 0	ble Re ne wa
de ritt Un CP Pr rw en og ram me s	10 0		1		10	Oc t-1 6
l C red it L ine To ta s	3, 55 0				0 3, 55 0
bt De Ra tin	S& P		Mo	od 's		Fit h c
gs				y
A & ina ED P S ED P F BV nce	+/ sit BB Po	/ ive B	Ba a3	/ / b le Sta	P3 BB	/ / b B- Sta F3
Las t R ati Ac tio ng n	30 -01 -20	15	13	-02 -20 15	19	-01 -20 15
bt De Ra tio s				Ma	r-1 5	De c-1 4

/ ( ) eb 3 Ne t D EB ITD A t					4.1 x	4.7 x
/ eb dju by Ne t D EB ITD A a Re Re cei t st. g. va	ble ( ) 3 s				3.6 x	4.0 x
bt De Ma	( ) by ity € m tur	Ma r-1 5	( ) 1

EDP's financial debt is essentially issued at holding level (EDP S.A. and EDP Finance B.V.) through both debt capital markets and bank loans. Maintaining access to diversified sources of funding and assuring refinancing needs 12-24months ahead continue to be part of the company's funding strategy. In terms of credit rating, in Jan-15, Fitchaffirmed EDP ^a "BBB-", also maintaining the outlook at Stable, and S&P affirmed its "BB+" credit rating on EDP while revising the outlook from Stable to Positive, essentially reflecting the expectation that the group's financial risk profile will strengthen markedly over the next ² years. In Feb-15, Moody's upgraded EDP's credit rating back toinvestment grade at "Baa3" with Stable outlook. This upgrade was based upon progress on delivery of the group's deleveraging strategy against the background of ^a slowly improving Portuguese economy.

Looking at 1Q15 major debt repayments and refinancing deals, in Jan-15, EDP early repaid the remaining USD250mout of ^a USD1.0bn loan with the Bank of China that was due to mature in Oct-15 and of which USD750m had already been early repaid in Jul-14. In Feb-15, EDP signed ^a €2bn 5-year credit facility with ^a syndicate of ¹⁶ international banks that was used to early repay ^a €1.6bn term loan signed in Jan-13 and which would mature in Jan-17 (50%) and Jan-18 (50%). The new facility pays EURIBOR+1.1% (vs. EURIBOR+4% in the prior facility). In Mar-15, EDP repaid, at maturity, ^a €1bn 3.25% Eurobond that had been swapped to floating rate. In Apr-15, EDP issued ^a €750mEurobond maturing in Apr-2025 with ^a coupon of 2%.

By Mar-15, average debt maturity was 4.4 years. The weight of consolidated financial debt raised through capital markets reached 70%, while the remaining of the debt was raised essentially through bank loans. Refinancing needs until the end of ²⁰¹⁵ amount to €1.5bn, including: i) €0.75bn of bonds maturing in 2Q15; and ii) €0.7bn of several bank loans maturing throughout the year. Total cash and available liquidity facilities amounted to €5.8bn by Mar-15. This liquidity position allows EDP to cover its refinancing needs beyond 2016.

Business Areas

Iberian Electricity and Gas Markets

Ele icit Ba lan ctr y ce		l Po rtu ga			Sp ain			ria ins n P en u	la	Ins lle d C aci in Ele icit ta ty ctr ap y
( h ) TW	1Q 15	1Q 14	∆%	1Q 15	1Q 14	∆%	1Q 15	1Q 14	∆%	( ) GW	1Q 15	1Q 14

dro Hy	3.4	6.4	-47 %	9.1	14 .3	-36 %	12 .5	20 .7	-40 %	dro Hy	22 .2	22 .1
cle Nu ar	-	-	-	15 .8	15 .2	4%	15 .8	15 .2	4%	cle Nu ar	7.0	7.0
al Co	3.1	1.5	10 6%	11 .1	4.3	15 5%	14 .2	5.9	14 2%	al Co	11 .7	11 .7
CC GT	0.5	0.1	7% 28	5.7	4.3	% 34	6.2	4.4	% 41	CC GT	28 .8
/ga / l die sel Fue s	-	-	-	-	-	-	-	-	-	/ga / l die sel Fue s	0.8	0.8
Ow tio n c on sum p n	-	-	-	( ) 1.7	( ) 1.3	33 %	( ) 1.7	( ) 1.3	33 %	tio l R im Co nv en na eg e	70 .4	70 .4
(- ) Pu ing mp	( ) 0.4	( ) 0.3	51 %	( ) 1.6	( ) 2.0	-23 %	( ) 2.0	( ) 2.3	-14 %
l R Co tio im nv en na eg e	6.6	7.8	-15 %	38 .5	34 .8	11 %	45 .1	42 .6	6%	nd Wi	27 .8	27 .5
										he al r Ot eci im r sp eg e	20 .0	19 .7
Wi nd	3.7	4.2	% -12	15 .8	17 .5	-9%	19 .6	21 .7	% -10	Sp eci l R im a eg e	47 .8	47 .2
he Ot r	2.5	2.8	-11 %	12 .0	12 .0	0%	14 .5	14 .8	-2%
eci l R im Sp a eg e	6.2	7.0	-12 %	27 .9	29 .5	-6%	34 .1	36 .5	-7%	l To ta	11 8.2	11 7.6
/ (ex ) n Im rt rt et po po	0.3	( ) 1.9	-	( ) 1.6	( ) 1.0	61 %	( ) 1.3	( ) 2.9	-56 %
( for ) Gr de nd be rid lo oss ma e g sse s	13 .1	12 .9	% 1.5	64 .8	63 .3	2.3 %	.9 77	76 .3	2.2 %	Ibe ria n E lec tri cit Fo y	( ard M ket OM rw ar	) IP
dju ork ing da A st. tem rat pe ure , w ys			0.0 %			1.5 %			n.a	h
										( / ) € MW
d Ga s D em an		l Po rtu ga			Sp ain		Ibe	ria n P ins en u	la	49. 9 50
( ) TW h	1Q 15	1Q 14	∆%	1Q 15	1Q 14	∆%	1Q 15	1Q 14	∆%
Co nti al d d nve on em an	11 .0	10 .9	1%	79 .9	77 .3	3%	90 .8	88 .2	3%

									50
1Q 15		∆%	1Q	1Q 14	∆%	1Q 15	1Q 14	∆%

1.1	0.3	21 5%	13 .6	10 .4	31 %	14 .7	10 .7	37 %
12 .0	11 .2	7%	93 .5	87 .7	7%	10	98 .9	7%	44. 2 45
	11 .0		1%	15 79 .9	.3 77	3%	90 .8	88 .2	3% 5.5

Electricity demand in Iberia increased 2.2% YoY in 1Q15, thus materialising some recovery from previous decreases. In Spain (83% of Iberia), demand increased 2.3% in 1Q15, and 1.5% when adjusted for temperature and working days. In Portugal (17% of total), demandwas 1.5% higher YoY in 1Q15 (flat when adjusted for temperature and working days), displaying some recovery vs. ^a 1Q14 in whichtemperatures were very mild.

Installed capacity in Iberia was almost flat YoY (+0.6GW). In Portugal, installed capacity was stable as wind capacity additions in the last ¹² months were partly compensated by the shutdown of cogeneration capacity. The downstream dam of Baixo Sabor hydro plant came online (+30MW) in 1Q15. In Spain, ^a slightly higher installed capacity was prompted by the increase of some special regime capacity.

Residual thermal demand in 1Q15 was up by 99% YoY (+10.1TWh), backed mostly by coal generation (+142% vs. 1Q14). The surge in residual thermal demand occurred mostly due to ^a decrease in wind and hydro resources (-10.1TWh in 1Q15 YoY). In fact, hydroresources were 26% below average in Portugal and 10% in Spain. Wind generation was also very strong in 1Q14, having decreased YoY inspite of being 14% above average in Portugal. Nuclear generation was 4% higher YoY and net exports decreased 56%. Overall, the scenario of higher demand and lower hydro and wind resources was tackled mostly by thermal generation. Accordingly, coal's avg. loadfactors improved to 56% (+33p.p. YoY), while CCGT's improved slightly to 10% (+3p.p. YoY).

Average electricity spot price in Spain was 76% higher YoY in 1Q15, at €45.9/MWh (+9% QoQ), and €0.1/MWh lower than in Portugal. Average CO2 prices rose by 19% YoY in 1Q15, to €7/ton. Average electricity final price in Spain stood €15.3/MWh above pool price (48%higher than in 1Q14) as ^a result of the contribution from restrictions market, ancillary services and capacity payments.

In the Iberian gas market, consumption increased by 7% YoY in 1Q15, dragged by ^a 3% surge in conventional demand, on the back of harsher winter temperatures in 1Q15 vs. 1Q14. Consumption for electricity generation purposes was also up by 37%, reflecting ^a 31%increase in Spain and ^a 215% surge in Portugal, due to higher utilisation rates at CCGTs.

			Ibe	ria n P ins en u	la
		( ) GW	1Q 15	1Q 14	∆%

	-40 %		22 .2	22 .1	0%
	4%		7.0		-
	14 2%		11 .7	11 .7	0%
	41 %		28 .8	28 .8	0%
-	-		0.8	0.8	0%
	33 %		70 .4	70 .4	0%
	% -14
	6%		27 .8	27 .5	1%
		he al r Ot eci im r sp eg e	20 .0	19 .7	1%
			47 .8	47 .2	1%
	-2%
			8.2 11	7.6 11	0%

Ma in Dri ve rs	1Q 15	1Q 14	∆%
fic ( ) Hy dro ien 1.0 t co e avg . ye ar =
l Po rtu ga	0.7 4	1.5 7	-53 %
ain Sp	0.9 0	1.4 0	-36 %
nd fic ( ) Wi ien 1.0 t co e avg . ye ar =
l Po rtu ga	1.1 4	1.4 0	-19 %
Ele / h ( ) icit rice € MW 1 ctr t p y s po ,
l Po rtu ga	46 .0	24 .7	86 %
Sp ain	45 .9	26 .1	76 %
/ Ele fin al p h ( ) ( ) icit rice € MW 1 2 ctr y ,
Sp ain	61 .2	41 .3	48 %
llow ( ), / ( ) CO 2 a EU A € 1 ton an ces	7.0	5.9	% 19
/ al ( I2 C ), US ( ) Co AP IF A RA D 1 t	60 .6	78 .5	-23 %
/ h ( ) Ga s N BP € MW 1 ,	22 .0	24 .8	-12 %
/ bb l ( ) Bre US D 1 nt,	.0 54	10 8.2	-50 %
/ ( ) EU R US D 1	1.1 3	1.3 7	-18 %

LT Contracted Generation in Iberian Market: PPA/CMEC & Special Regime

( ) Inc e S € m tat t om em en	1Q 15	1Q 14	∆%	bs. ∆ A

/ PP A CM EC Re ve nu es	25 3	21 6	17 %	+3 7
he rke ( ) Re in t i t ve nu es ma al d ii	22 7	17 2	31 %	4 +5
( ) An iat ion nu ev / CM ECs ed in iii PPA	64	77	% -17	-13
( ) s ac cru co me / Dir PP A CM EC Co ect sts	( ) 38	( ) 34	13 %	-4
al Co	83	39	114 %	+4 4
l o il Fue	52 1	33 1	57 %	+1 9 -1
nd he (ne ) CO 2 a ot sts t r co	30	4	-65 % 63 9%	+2
/ Gr Pr fit PP A CM EC oss o	17 0	17 7	-4%	6 -7

Th al (co bio ) ste erm ge n., wa ma ss ,	3	4	-31 %	-1
hy dro Mi ni-	13	27	-52 %	-14
fit l R Gr Pr Sp eci im oss o a eg e	15	30	-49 %	-15

( ) t O ing 1 Ne rat sts pe co	33	32	2%	+1
EB ITD A	15 3	17 6	-13 %	-22
t d d p Ne iat ion isio ep rec an rov n	39	44	-11 %	-5
EB IT	114	13 2	-13 %	-18
lts: dg ( ) ( ) At Fin . R He ing Ga ins Los 2 esu ses	( ) 0	1	-	-1
loy ( ) Em # p ee s	1, 15 3	1, 19 8	-4%	-45

/ PP A CM EC : K Da ta ey	1Q 15	1Q 14	∆ %	bs. ∆ A

/ l ed ai la bi lity Re Co Av ntr act a
dro H y	1.0 4	1.0 5	-1%	-0. 0
l C oa	1.0 7	1.0 4	3%	+0 .0
( ) Ins lle d C aci MW ta ty ap	4, 47 0	4, 47 0	-	-
dro Hy	3, 29 0	3, 29 0	-	-
al Co	1, 18 0	1, 18 0	-	-

loy ( ) Em # p ee s	1, 15 3	1, 19 8	-4%	-45

/ PP A CM EC : K Da ta ey	1Q 15	1Q 14	∆ %	bs. ∆ A

/ l ed la bi lity Re Co Av ai ntr act a
dro H y	1.0 4	1.0 5	-1%	-0. 0
C l oa	1.0 7	1.0 4	3%	+0 .0
lle d C aci ( ) Ins MW ta ty ap	4, 47 0	4, 47 0	-	-
dro Hy	3, 29 0	3, 29 0	-	-
al Co	1, 18 0	1, 18 0	-

( ) Ou GW h tpu t	4, 15 1	5, 00 2	% -17	-85 1
dro Hy	1, 90 3	3, 73 9	-49 %	-1, 83 6
al Co	2, 24 8	1, 26 3	78 %	+9 85
l R eci im	15	14	∆ %	∆ A bs.
Sp Ke Da ta a eg e: y	1Q	1Q
( ) Ou GW h tpu t	22 2	41 4	-46 %	-19 1
hy dro l Mi ni- Po rtu ga	13 8	27 8	-50 %	-14 0
Th al P l ort erm uga	52	69	-25 %	-17
Th al S in erm pa	33	67	-51 %	-34

( / ) Av Gr fit € MW h Pr era ge oss o
Mi ni- hy dro l Po rtu ga	94	96	-2%	-2
Th al P l ( ) 3 ort erm uga	22	21	3%	+1
Th al S in erm pa	43	51	-16 %	-8
( ) Ca € m pe x	1Q 15	1Q 14	∆ %	bs. ∆ A

/ PPA CM EC Ge ion rat ne	3	2	36 %	+1
al R Sp eci im eg e	0	0	-6%	-0

l To ta	4	3	31 %	+1

EBITDA from LT contracted generation fell by 13%, to €153m in 1Q15, impacted by the lower volumes of mini-hydro special regime generation and by ^a PPA/CMEC gross profit decrease due to the ongoing depreciation of the asset base.

Gross profit from PPA/CMEC was €7m lower YoY in 1Q15, at €170m, following the natural depreciation of the asset base in ^a context of very low inflation.

The annual deviation between market gross profit under CMECs assumptions and gross profit under actual market conditions totalled €64m in 1Q15 (o.w. €4m adjustment from 2014), reflecting essentially the hydro volumes below the CMEC's reference for hydro generation. This amount is due to be received in up to ²⁴ months through access tariffs. Deviation at hydro plants totalled €56m as the impact from ^a production 40% below CMEC's reference and of an avg. realised price 2% below CMEC's reference. In turn, market gross profit at our Sines coal plant stood €4m below the CMEC's reference, since higher volumes (+8%) were offset by avg. clean dark spread 13% below the CMEC's reference.

Gross profit from special regime was €15m lower YoY, at €15m in 1Q15, driven by the ^a 50% decrease in mini-hydrogeneration, on the back of lower than average hydro resources in Portugal vs. ^a strong 1Q14. Thermal generation in Iberia decreased, mostly due to the sale of idle capacity in Spain.

Net operating costs(1) increased by 2%, to €33m in 1Q15, reflecting annual OpEx adjustments.

Net amortisation charges and provisions were 11% lower YoY, at €39m in 1Q15, reflecting lower asset base at PPA/CMEC, andthe one-off provisions on thermal special regime plants in Spain in 1Q14.

Capexin LT contracted generation was €1m higher in 1Q15, at €4m, due to several pluri-annual maintenance works.

Explanatory note on PPA/CMEC:

In June ²⁰⁰⁷ the long term contracts that EDP had with the Portuguese electricity regulated system (PPA) were replaced by the CMEC (Cost of Maintenance of Contractual Equilibrium) financial system to conciliate: (1) the preservation of the NPV of PPA, based on real pre-tax ROA of 8.5%, and ^a stable contracted gross profit over the next ¹⁰ years; and (2) the need to increase liquidity in the Iberian electricity wholesale market. In terms of EDP's P&L, the total gross profit resulting fromCMECs' financial system will keep the same profile over the next ¹⁰ years as the former PPA.

PPA/CMEC gross profit has ³ components:

(i) Revenues in the market, resulting from the sale of electricity in the Iberian wholesale market and including both ancillary services and capacity payments. (ii) Annual deviation ('revisibility'), equivalent to the difference between CMEC's initial assumptions made in ²⁰⁰⁷ (outputs, market prices, fuel and CO² costs) and real market data. This annual deviation will be paid/received by EDP, through regulated tariffs, up to two years after occurring.

(iii) PPA/CMEC Accrued Income, reflecting the differences in the period between PPA and CMEC assumed at the beginning of the system in July 2007.

( ) Inc e S € m tat t om em en			1Q 15	1Q 14	∆%	∆ A bs.
Gr fit Pr oss o			23 3	29 1	% -20	-57
Ele icit tio ctr y g en era n			16 5	22 4	-26 %	-58
l Po rtu ga			85	11 3	-25 %	-28
Sp ain			82	11 2	-27 %	-30
Ad jus tm ts en			( ) 2	( ) 2	% -16	+0
Ele ly icit ctr y s up p			47	40	18 %	+7
ly Ga s s up p			21	33	-36 %	-12
Ad jus tm ts en			( ) 0	( ) 6	-95 %	+5
( ) Ne t O ing 1 rat sts pe co			12 6	98	% 28	+2 7
EB ITD A			10 7	19 2	-44 %	-85
Pro vis ion s			( ) 1	1	-	-3
nd Am isa tio im irm ort t n a pa en EB IT			50 59	49 14 2	1% -58 %	+1
						-83
Ele icit rfo ctr Pe rm an ce y	1Q 15	1Q 14	∆%	1Q 15	1Q 14	∆%
	Ou	( h ) GW tpu t		ria b le C Va	/ ( € MW ost	h ) ( ) 2
Ge ion Ou rat tpu t ne	69 8 4,	15 4, 7	13 %	27 .3	13 .8	98 %
Ele icit rch Pu ctr y ase s	8, 95 0	9, 09 9	-2%	55 .8	34 .3	63 %
Ele icit So ctr y urc es	13, 64 7	13, 25 6	3%	47 .1	28 .4	66 %
	lum Vo	ld ( So GW es	h )	Av era ge	( / Pri € MW ce	h ) ( ) 3

id Gr Los ses	36 0	28 0	29 %	n.a	n.a	-
ail l cl Ret - F ina ien ts	8, 65 5	8, 83 1	-2%	63 .7	56 .9	12 %
Wh ole sal ark et e m	4, 63 2	4, 14 5	% 12	58 .7	47 .9	% 22
Ele icit Us ctr y es	13, 64 7	13, 25 6	3%	60 .3	52 .9	14 %
Ele fit ( ) icit Gr Pr € m ctr y oss o			1Q 15	1Q 14	∆%	∆ A bs.

( / ) for e h ed ing € h Be MW g			13 .3 0.5	24 .5 7.0	% -46	-11 .2
/ dg ing ( h ) ( ) Fro He € MW 4 m h Un it m in € MW			( ) 12 .8	( ) 17	93 % -27 %	+6 .5 -4. 7
/ ( ) arg tal lum ( h ) To Vo TW e			13 .6	.5 13 .3	3%	+0 .4
bto l Su ta			17 5	23 2	-25 %	-57
( ) Ot he 5 rs			38	31	% 20	+6
l To ta			21 2	26 3	% -19	-51
( h ) Ga s U TW ses			1Q 15	1Q 14	∆%	∆ A bs.

Co d b lan ts nsu me y o wn po we r p ld in w ho les ale ark So ets m			1.3 3.4	1.2 4.8	6% -28 %	+0 .1 -1. 3
So ld t o C lien ts			4.7	5.5	% -14	-0. 7

EBITDA from liberalised activities was €85m lower YoY, at €107m in 1Q15, driven by: (i) ^a lower contribution fromhydro production (41% weight in generation mix in 1Q15 vs. 68% in 1Q14); (ii) lower results derived from fewer opportunities for managing energy markets' volatility; and (iii) -€12m YoY of gross profit from gas supply andtrading activities, on the back of fewer wholesale trading opportunities. Higher thermal generation and improvedgross profit in the electricity supply business partly mitigated these effects.

Hydro output decreased 33% YoY, helped by ^a 1Q15 in which hydro resources were 26% below average inPortugal (vs. 57% above average in 1Q14). The lower contribution from hydro justified ^a 98% surge in the avg. generation cost. Capacity payments in Portugal were re-installed (+€6m YoY, o.w. €3m concerning 2014), while capacity payments in Spain, which in unitary terms are higher than in Portugal, were flat YoY. At net operating costs level, higher volumes generated in Spain led to ^a surge in generation taxes (+€15m YoY).

Gross profit in the electricity business fell by 19% in 1Q15, to €212m, driven by ^a lower avg. unit margin (downfrom €24.5/MWh in 1Q14 to €13.3/MWh in 1Q15). ^A lower level of opportunities for enhanced energy management gains also impacted YoY comparison in 1Q15.

Unit margin (2)(3): Avg. electricity spread was €11.2/MWh lower in 1Q15, at €13.3/MWh, mainly propelled by ^a less cheap mix of electricity sources vs. 1Q14. Avg. sourcing cost increased by 66% YoY supported by lower hydrovolumes in the generation mix and more expensive electricity purchases derived from higher pool prices vs. 1Q14. Avg. selling price was 14% higher in 1Q15, as ^a result of: (i) ^a 12% increase in avg. selling prices to final clients derived from higher cost of electricity; and (ii) ^a 22% surge in the average selling prices in the wholesale market (supported by higher pool prices and partly offset by lower revenues from ancillary services). Note that the Dispatch 4694/2014, aiming at reducing potential distortions in the ancillary services market in Portugal, addressed the price of the secondary regulation, obliging it to be no greater than in Spain.

Volumes: Total volume sold rose by 3% to 13.6TWh in 1Q15, reflecting increases in sales in the wholesale market (+12%). Our generation output met 54% of electricity sales to final clients.

Our gas sourcing activity in 1Q15 was based on an annual c.3.6bcm portfolio of long term contracts, whose flexibility has been enhanced through several contract renegotiations (including take or pay flexibility). In 1Q15, wholesale market opportunities decreased vs. 1Q14 and, as ^a result, gas supply decreased 18% YoY to 9TWh(0.8bcm) in 1Q15, as sales in wholesale markets decreased 28% YoY, while sales to final clients decreased 14%. The 6% increase in consumption at our gas fired power plants partly offset these effects.

EDP is adapting its hedging strategy to the current market conditions, making use of flexibility stemming from the integrated management of gas and electricity operations in Iberia. As a result, EDP has maximised gas sales between the wholesale and retail markets, having so far secured spreads for around 90% of its gas sourcing commitments for 2015. Also, EDP has so far forward contracted costs for close to 60% of the expected coal output for 2015. For 2015, EDP has already forward contracted electricity sales with clients of 26TWh at an avg. price of c.€55/MWh.

(1) Net Operating Costs = Operating Costs (Supplies and services + Personnel costs + Costs with social benefits) + Other operating costs (net); (2) Variable cost: fuel cost, CO2 cost net of free allowances, hedging costs (gains), system costs;(3) Average selling price: includes selling price (net of TPA tariff), ancillary services and others; (4) Includes results from hedging on electricity;

(5) Includes capacity payments, services rendered and others.

Liberalised Electricity Generation in the Iberian Market

$\mathcal{L}(\mathcal{L})$ and $\mathcal{L}(\mathcal{L})$ and $\mathcal{L}(\mathcal{L})$ ۰,

( ) Inc e S € m tat t om em en	1Q 15	1Q 14	∆%	bs. ∆ A
fit Gr Pr oss o	16 5	22 4	% -26	-58
l Po rtu ga	85	11 3	-25 %	-28
Sp ain	82	11 2	-27 %	-30
Ad jus tm ts en	( ) 2	( ) 2	-16 %	+0
lies d s Su ice pp an erv s	15	19	-19 %	-3
Pe el c ost rso nn s	13	11	% 20	+2
ith cia l be fits Co sts w so ne	0	0	-	+0
he (ne ) Ot ing rat sts t r o pe co	46	23	10 1%	+2 3
ing ( ) Ne t O 1 rat sts pe co	74	52	41 %	+2 2
EB ITD A	91	17 1	% -47	-80
vis ion Pro s	( ) 2	1	-	-3
nd Am isa tio im irm ort t n a pa en	48	47		+1
EB IT	45	12 3	-63 %	-77

nd Am isa tio im irm ort t n a pa en EB IT	48 45	47 12 3	1% -63 %	+1 -77
loy ( ) Em # p ee s	59 3	62 9	-6%	-37
		14	∆%	bs. ∆ A
Ke Op tin Da ta y era g	1Q 15	1Q
ion ( h ) Ge Ou GW rat tpu t ne	4, 70 9	4, 18 6	12 %	+5 23
CC GT	41 1	15 8	16 0%	+2 53
al Co	2, 05 8	86 2	13 9%	+1 19 6 ,
dro Hy	1, 91 0	2, 83 4	-33 %	-92 5
Nu cle ar	33 1	33 2	-0%	-1
( / ) ( ) Ge ion Co € MW h 2 rat sts ne	27 .3	13 .8	98 %	+1 3.5
CC GT	99 .9	15 0.3	-34 %	-50 .4
al Co	37 .2	35 .9	4%	+1 .3
Hy dro	4.8	0.4	70 % 11	+4 .5
cle Nu ar	4.4	4.5	-3%	-0. 2
d F ( ) Loa % act ors
CC GT	5%	2%	-	3p .p.
al Co	65 %	27 %	-	38 p.p
Hy dro	36 %	% 54	-	-18 p.p
cle Nu ar	% 99	% 99	-	0p .p.
mi ssi (m ) CO 2 E n t on s on es
tal ( ) To iss ion 3 em s	2.8	1.3	10 7%	+1 .4

( ) Ca € m pe x	1Q 15	1Q 14	∆%	bs. ∆ A
Exp sio an n	87	11 9	-27 %	-32
Ma int en an ce	4	3	% 15	+0
l To ta	91	12 2	-26 %	-31

Our liberalised generation & supply activities are jointly managed as most of our production is sold to our supply units at fixedprices.

Output from our generation plants (unadjusted for hydro pumping) was 12% higher in 1Q15, mainly prompted by ^a higher contribution from thermal generation, in the wake of below average hydro resources. The decrease in hydro output was more than offset by higher production at our coal (+1.2TWh) and CCGTs (+0.3TWh). Avg. production cost was 98% higher YoY, at €27.3/MWh in 1Q15, reflecting the lower contribution from the cheaper technology, hydro (41% of total output in 1Q15 vs. 68% in1Q14).

Coal: Output was up 1.2TWh YoY in 1Q15, backed by higher thermal demand. Avg. load factor reached 65% in 1Q15 (+38p.p. YoY). Domestic coal incentives in Spain ended in 2014. Avg. production cost increased by 4%, to €37.2/MWh.

CCGTs: Output rose by 160% YoY in 1Q15, driven by higher thermal demand, implying ^a 3p.p. increase in avg. load factor, to 5% in1Q15. Avg. production cost reached €100/MWh in 1Q15, driven by low dilution of gas procurement fixed costs, as plants had still low avg. load-factors.

Hydro & Nuclear: Hydro generation fell by 33% in 1Q15, given the lower than average hydro resources. The avg. cost of hydroproduction increased from €0.4/MWh in 1Q14 to €4.8/MWh in 1Q15, reflecting ^a more intensive pumping activity derived from ^a lower level of hydro reserves in the 1Q15. Pumping activity is concentrated at our Alqueva plant, at an avg. cost correspondent to^a c33% discount to the avg. pool price (vs. c42% in 1Q14). Our 15.5% share in the production of Trillo plant (nuclear) correspondedto an avg. load factor of 99% in 1Q15 (flat YoY).

Net operating costs(1) increased by 41% YoY, to €74m in 1Q15, driven by an increase in generation taxes in Spain given the higher volumes generated in Spain (+€15m YoY) and the nuclear eco-tax recovered in 1Q14 (+€6m YoY). The sum of the transitory levy charged in Portugal on production and the generation taxes in Spain amounted to €35m. Amortisations and impairment charges increased by €1m, to €48m.

Capex totalled €91m in 1Q15, mostly devoted to new hydro capacity in Portugal (under construction and development). EDP is currently building ⁵ hydro projects (1,449MW): Ribeiradio, expected start-up in 2Q15, Baixo Sabor, Venda Nova III and Salamonde II, expected to start operations in 2H15; and Foz-Tua, due in 2H16. Baixo Sabor's downstream dam came online in the 1Q15 with 30MW.

(1) Net Operating Costs = Operating Costs (Supplies and services + Personnel costs + Costs with social benefits) + Other operating costs (net);(2) Includes fuel costs, CO2 emission costs net of free allowances, hedging results; (3) Includes CO2 emissions from Aboño plant, which burns blast furnace gases.

Liberalised Electricity and Gas Supply in the Iberian Market

	En in ain
( ) Inc e S € m tat t om em en	1Q 15	Su erg y pp 1Q	ly Sp ∆% 14
				bs. ∆ A
Gr fit Pr oss o	37	46	-19 %	-9
lies d s Su ice pp an erv s	14	15	-2%
el c Pe ost rso nn s	3	3	2%	-0 +0
ith l be fits Co cia sts w so ne	0	0	-9%	-0
he (ne ) Ot ing rat sts t r o pe co	9	8	% 17	+1
( ) Ne t O ing 1 rat sts pe co	27	25	5%	+1

EB ITD A	10		-49 %	-10
Pro vis ion s	0	21( ) 0	-	+0
nd Am isa tio im irm ort t n a en	1	1	-11 %
pa IT EB	10	20	% -52	-0 -10

( ) Inc e S € m tat t om em en	En	ly Su erg y pp	in Po rtu ga	l
	1Q 15	1Q 14	∆%	bs. ∆ A

fit Gr Pr oss o	31	27	16 %	+4
Su lies d s ice pp an erv s	18	14	% 29	+4
el c Pe ost rso nn s	3	3	0%
ith l be fits Co cia sts w so ne	-	-	-	+0 -
he (ne ) Ot ing rat sts t r o pe co	5	4	10 %	+0
ing ( ) Ne t O 1 rat sts pe co	25	21	21 %	+4

EB ITD A	6	6	-4%	-0
Pro vis ion s	-	-		-
t d d a Ne iat ion rtiz ati ep rec an mo on	1	1	- 12 %	+0
EB IT	5	5	-6%	-0

da Ke ta y	1Q 15	1Q 14	∆%	bs ∆ A

ly in ain En Su Sp erg y pp
Ele rke icit Fr ctr t y - ee ma
lum old ( h ) Vo e S GW	3, 43 1	4, 39 7	-22 %	-96 5
( ) Ma rke t S ha % re	7%	% 10	-	-2p .p.
Cli ( th. ) ts en	73 0	66 4	10 %	+6 6
Ele icit ly La ctr st ort y - res su pp
lum old ( h ) Vo e S GW	14 9	16 1	-8%	-12
Cli ( th. ) ts en	24 5	25 2	-3%	-7
ket ly Ga Fre & Las t re t s s - e m ar sor up p
( ) Vo lum e S old GW h	6, 82 8	9, 17 3	% -26	-2, 34 5
rke ha ( % ) ( ) Ma t S 2 re	4%	5%	-	-1p .p.
Cli ( th. ) ts en	83 0	80 8	3%	+2 3

ly l En Su in Po rtu erg y pp ga
Ele icit Fr rke ctr t y - ee ma
lum e S old ( GW h ) Vo	4, 64 4	3, 85 4	20 %	+7 90
rke ha ( % ) Ma t S re	47 %	46 %	-	1p .p.
Cli ( th. ) ts en	3, 30 3	2, 25 6	46 %	+1 04 7 ,
ket Ga Fre s - e m ar
lum old ( h ) Vo e S GW	33 1, 7	07 3 1,	25 %	26 4
	% 10	% 11	-	-1p .p.
( ) ( ) rke t S ha % 2 Ma re
Cli ( th. ) ts en	43 0	26 9	60 %	+1 61

( ) Ca €m pe x loy ( )	2	3	-16 %	-0

Our electricity and gas supply activities in Portugal and Spain are managed in single energy platforms, ensuring ^a responsive and competitive commercial structure. EDP Group's subsidiaries that operate in this business segment have intra-groupelectricity and gas procurement contracts with our generation and energy trading divisions.

Energy Supply in Spain

Gross profit at our supply activities in Spain decreased by €9m YoY, to €37m in 1Q15, driven mainly by ^a €12m decrease in gross profit from gas wholesale trading activities, which was partly offset by previous years' recoveries.

Net operating costs increased by €1m YoY, in 1Q15, on the back of higher costs servicing ^a higher number of clients.

Electricity volume supplied to our clients in the free market decreased by 22% YoY to 3.4TWh, in 1Q15, accompanied by ^a 10% increase in the number of clients supplied, in line with EDP's strategy to focus on the most attractive customer segments. Market share, reflecting solely retail volumes, fell 2p.p. YoY, to 7% in 1Q15.

Gas volume supplied declined by 26%, to 6.8TWh in 1Q15, as ^a result of lower wholesale trading opportunities and in line withEDP's strategy to focus on the most attractive customer segments. The client portfolio expanded by 3%. Market share, reflecting solely retail volumes, fell by 1p.p. to 4% in 1Q15.

Energy Supply in Portugal

Market Environment – In line with the rules and calendar defined for the liberalisation of electricity supply in Portugal, the electricity last resort supplier (EDP Serviço Universal) can no longer contract new customers (with the exception of consumers entitled to the social tariff, or living in areas where other suppliers don't operate). Additionally, all the remaining consumers with regulated tariff will gradually move to the free market. During this transitory period, the regulator has the ability to apply quarterly updates to the transitory tariff thus promoting the switch to the free market. In this context, the switching of electricity consumers to the free market over ²⁰¹⁴ and 1Q15 was very strong: by the end of Mar-15, the number of consumers in the free market soared to 3.9 million, elevating the total consumption in the free market to 86% of the total market.

Gross profit at our supply activities in Portugal advanced €4m YoY, to €31m in 1Q15, driven by higher volume of electricity supplied.

Net operating costs rose by €4m, to €25m in the 1Q15, driven by higher supplies and services, namely of costs with client services (call center, billing, etc), in line with the ongoing liberalisation process and the expansion of our clients base.

Electricity volume supplied to EDP clients in the free market in Portugal advanced 20% YoY, to 4.6TWh in 1Q15, propelled by ^a 46% expansion of our client base. EDP's market share in the free market rose by 1p.p. YoY in 1Q15, to 47%, in line with EDP's strategy to focus on the most attractive residential/SMEs segments.

Gas volume supplied to EDP clients in Portugal rose by 25% YoY to 1.3TWh, in 1Q15, reflecting ^a volume increase in the residential segment following the gas market liberalisation. The strong pace of gas supply liberalisation, along with our successful dual offer (electricity ⁺ gas) to residential clients, prompted ^a surge in the number of clients to 430k in Mar-15, corresponding to +161k YoY.

(1) Net Operating Costs = Operating Costs (Supplies and services + Personnel costs + Costs with social benefits) + Other operating costs (net).(2) Market-share for retail market; excludes wholesale. For Portugal, based on the regulator's declared market-share (Dec-14 and Mar-14 figures).

EDP Renováveis: Financial Performance

Inc e S	ED	áve P R en ov	( ) is € m		l O Op tio rvi era na ve ew	1Q 15	1Q 14	∆ %	bs. ∆ A	uit rke ED PR Eq Ma t D ata y	1Q 15	1Q 14	∆ %	bs. ∆ A
tat t om em en	1Q 15	1Q 14	∆ %	∆ A bs.
					( ) Ins lle d C aci MW ta ty ap	8, 9 14	76 2 7,	5%	+3 87	f p ( /s ) Sh ice d o eri od € ha at are pr en re	0 5.4	3.8 6	40 %	1.5
Gr fit Pr oss o	37 5	34 5	9%	+3 0	Eu rop e	4, 23 1	4, 17 3	1%	+5 8	(m ) mb f S ha d illio Nu Iss er o res ue n	87 2.3	87 2.3	-	-
					rth eri No Am ca	3, 83 5	3, 50 6	9%	+3 29	ke d b ( % ) Sta Ow ED P ne y	77 .5%	77 .5%	-	-
lies d s Su ice pp an erv s	65	59	10 %	+6	zil Bra	84	84	0%	-
el c Pe ost rso nn s	17	18	-2%	-0
he (ne ) Ot ing rat sts t r o pe co	( ) 26	( ) 21	24 %	-5	( h ) Ou GW tpu t	78 6 5,	6, 11 2	-5%	-32 6	lan he ( ) ED PR Ke Ba S Fig € m et y ce ure s	1Q 15	1Q 14	∆ %	∆ A bs.
( ) Ne t O ing Co 1 rat sts pe	56	56	1%	+1	( ) Av Loa d F % act g. or	% 34	% 38	-	-4 p.p
					( / ) Ele ice € h Av Pr MW ct. g.	65	57	15 %	+9	nk d O the ( ) Ba Loa Ne t ns an r	33 4	55 7	-40 %	-22 4
EB ITD A	31 9	28 9	10 %	+3 0						h E ( ) Loa wit DP Gr Ne t ns ou p	3, 18 8	2, 76 3	15 %	+4 25
					( ) EB ITD A €m	31 9	28 9	10 %	+3 0	ina nci l D bt Ne t F a e	3, 52 2	3, 23 1	9%	+2 91
Pro vis ion s	-	-	-	-	( ) Eu 3 rop e	18 8	18 5	1%	+2	llin No int tro sts n-c on g ere	55 7	42 9	30 %	+1 28
Am isa tio nd im irm ort t n a pa en	124	0 11	12 %	3 +1	rth No Am eri ca	13 2	10 3	29 %	+2 9	l Pa hip bi lity ( ) Ne t In sti ion Lia 4 tut rtn a ers	184 1,	81 0	46 %	+3 74
					zil Bra	3	3	% -14	-	uit k V lue Eq Bo o a y	5, 89 7	5, 73 7	3%	+1 60
EB IT	19 5	17 9	9%	+1 6	he r & Ad jus Ot tm ts en	( ) 4	( ) 2	71 %	-2
										/ d o f P od EU R US D - En eri Ra te	1.0 8	1.3 8	28 %	-0. 30
l Re sul Fin cia ts an	( ) 72	( ) 62	16 %	-10	( ) EB IT €m	19 5	17 9	9%	+1 6
Sh f P fit fro oci ate are o ro m ass s	9	12	-27 %	-3	( ) Eu 3 rop e	13 1	12 6	4%	+5
					No rth Am eri ca	67	54	% 25	+1 3	( ) ED PR Fi nci l R lts € m na a esu	1Q 15	1Q 14	∆ %	bs. ∆ A
fit Pre -ta x p ro	13 2	12 8	3%	+3	zil Bra	1	2	-26 %	-
					he r & Ad Ot jus tm ts en	( ) 4	( ) 3	55 %	-2	Ne t In Co ter est sts	( ) 53	( ) 48	-9%	-4
										l Pa hip (no ash ) Ins titu tio rtn sts na ers co n-c	( ) 20	( ) 15	-31 %	-5
					( ) Ca €m pe x	16 3	44	27 1%	+1 19	lise d C Ca ita ost p s	7	7	2%	+0
rfo Op Pe ex rm an ce	1Q 15	1Q 14	∆ %	bs. ∆ A	( ) Eu 3 rop e	20	14	% 41	+6	ffe Fo Di d D eri ive vat rex ren ces an s	2	( ) 3	-	+5
					rth Am eri No ca	11 6	28	8% 31	+8 8	Ot he r	( ) 8	( ) 3	n.m	-6
/ ( h ) ( ) Op Av MW € t 2 ex g.	13 .6	13 .6	0%	-0	zil Bra	27	2	n.m	+2 5
loy ( ) Em # p ee s	93 8	89 8	4%	+4 0	he r & Ad Ot jus tm ts en	-	0	-	-	Fin cia l R lts an esu	( ) 72	( ) 62	-16 %	-10

EDP Renováveis ('EDPR') owns, operates and develops EDP Group's wind and solar capacity. As of Mar-15, EDPR operates 9.0GW, of which 886MW equity-method accounted. EDPR's EBITDA is mainly derived fromPPA-contracted and regulated tariff schemes (90% of output), geographically widespread: 41% in NorthAmerica, 24% from Spain, 15% from Portugal and the rest derived in France, Poland, Romania, Belgium, Italy and Brazil.

EDPR's EBITDA increased by 10% YoY (+€30m) to €319m in 1Q15, propelled by operations in North America (+€29m YoY), mainly driven by the USD 22% appreciation vs. Euro and by higher realised prices in merchant capacity in US. EBITDA in Europe was stable, as higher EBITDA in Spain (+€8m prompted by ^a recovery in average realised price in the pool) was mostly offset by lower EBITDA in Portugal (-€8m, penalised by outstanding wind resources in 1Q14 and low inflation context). ForEx impact on EBITDA YoY change was +€23m, mainly stemming from the appreciation of USD vs. th Euro.

Electricity output decreased 5% YoY, to 5.8TWh in 1Q15, as lower average load factor (-4pp YoY to 34%) following outstanding wind resources in 1Q14 outstood the impact from higher average capacity on streamin 1Q15 (+6% YoY). Avg. selling price advanced by 15% YoY to €65/MWh, driven by stronger USD vs. Euro, higher US spot and REC prices in US; and higher realised prices in the pool, in Spain.

Operating costs (Supplies and services ⁺ Personnel costs) rose by 8% (+€6m) YoY, reflecting ForEx impact (€7m), portfolio expansion and strict cost control.

Other operating costs (net) include the 7% generation tax on sales in Spain (€7m in 1Q15), which increased by 34% YoY as result of higher pool prices.

EBIT advanced by 9% YoY, to €195m in 1Q15. Amortization and impairments reflect the ForEx impact (+€11m YoY) and, to ^a lower extent, portfolio expansion.

Capex amounted to €163m in 1Q15: 71% of total was devoted to the US market, the main growthregion in 2015E-17E; 12% to Europe and 16% to Brazil.

EDPR's net debt in Mar-15 amounted to €3.5bn (vs.€3.3bn in Dec-14), mainly reflecting USD 13%appreciation YTD (42% of debt is USD-denominated), which translated into ^a €179m increase in debt. Additionally, net debt evolution translates the investments done in the period and proceeds from tax equity partnerships (€38m in 1Q15). Liabilities with Institutional Partnerships amounted to €1,184min Mar-15, reflecting USD appreciation and tax benefits paid to these entities. Non-controlling interests amount to €557m, reflecting non-controlling interests in North America (c45%), Europe (c50%) and Brazil (c5%).

Net financial costs rose by 16%, to €72m in 1Q15. Net interest cost were 9% higher YoY supported by USD appreciation vs. Euro and an average net debt €92m higher YoY. Share of profit from associates was €3m lower YoY, at €9m in 1Q15, reflecting outstanding conditions in Portugal and US during 1Q14. ENEOP contribution in 1Q15 amounted to €7m (vs. €10m in1Q14).

(1) Net Operating Costs = Operating Costs (Supplies and services + Personnel costs + Costs with social benefits) + Other operating costs (net); (2) Opex excluding Other Operating Income; Ratio calculated considering average MW in operation (3) Includes Holding costs and adjustments at the level of EDPR Europe; (4) Net of deferred revenue;

h A ric No rt me a	1Q 15	1Q 14	∆ %	bs. ∆ A
/ f p od US D EU R - Av eri te g. o ra	1.1 3	1.3 7	22 %	-0. 2
( ) Ins lle d c aci MW ta ty ap	3, 83 5	3, 50 6	9%	+3 29
/ / 's dg ed d-i ari ff PPA He Fee n t	3, 28 4	2, 91 8	13 %	+3 66
rch Me ant	55 1	58 7	-6%	-37
d F ( ) Av Loa % act g. or	34 %	39 %	-	-5 p.p
( ) Ele icit Ou GW h ctr tpu t y	2, 80 8	2, 93 0	-4%	-12 2
/ / 's dg ed d-i ari ff PPA He Fee n t	2, 35 7	2, 44 5	-4%	-89
rch Me ant	45 1	48 5	-7%	-34
l Se llin ( / h ) Av Fin Pri US D MW g. a g ce	52 .7	48 .1	10 %	.6 +4
/ / PPA 's He dg ed Fee d-i ari ff n t	53 .5	52 .0	3%	+1
rch Me ant	48 .3	28 .3	71 %	.5 +2 0
Ad jus ted fit ( ) Gr Pr US D m oss o	19 3	18 8	3%
fit ( ) Gro Pro US D m ss	14 5	13	5%	+6 +7
the ( ) PTC Re & O US D m ve nu es r	48	8	-2%	-1
( ) ITD A US EB D m	14 9	49 14 1	6%	+8
( ) EB IT US D m	76	74	3%
				+2
tal led ( ) Ins ity MW Eq uit ca pac y	17 9	17 9	0%	-
( ) Ne t C US D m ap ex	13 1	38	4% 24	+9 3
Gro Ca ss pex	13 1	38	24 4%	+9 3
sh ed Ca eiv nt gra rec	-	-	-	-
nd ( ) Ca cit tio MW nst pa y u er co ruc n	39 9	23 0	73 %	+1 69
zil Bra	1Q 15	1Q 14	∆ %	bs. ∆ A
/ al - f p od Eu Re Av eri te ro era ge o ra	3.2 2	3.2 4	1%	-0. 02

lle d C ( ) Ins aci MW ta ty ap	84	84	-	-
( ) Av Loa d F % act g. or	% 25	% 27	-	-2 p.p
Ele icit ( h ) Ou GW ctr tpu t y	46	49	-7%	-3
\$ / al S ell ( h ) Av Fin ing Pr ice R MW g.	37 0	34 1	8%	+2 8
\$ m fit ( ) Gro Pro R ss	16	16	0%	+0
\$ m ( ) EB ITD A R	9	10	% -15	-2
( \$ m ) EB IT R	4	6	% -26	-2
\$ m ( ) Ca R pe x	86	6	n.m	+8 0
nd ( ) Ca cit tio MW nst pa y u er co ruc n	12 0	-	-	+1 20

In North America, installed capacity totalled 3.835MW (MW EBITDA) in Mar-15, the bulk of which LT Contracted schemes (86% of total) and in US (3,805MW in US, 30MW in Canada). Additionally, EDPR owns an equity position in other wind projects, equivalent to 179MW. New capacity additions in the last ¹² months (+329MW) were fully concentrated in US and in 4Q14.

EBITDA advanced 6% YoY (+USD8m), to USD149m in 1Q15, driven by ^a 10% increase in the average selling price and ^a 4% fall in output. Higher avg. selling price was prompted by ^a recovery in realised prices in the market (+71% YoY and +13% QoQ following ^a recovery from last years's adverse impact from extreme weather conditions and higher revenues from the sale of Renewable Energy Credits) and ^a 3% increase in LT contracted prices, both in driven by US. Lower wind production reflected: (i) weak wind resources vis-a-vis ^a strong 1Q14, particularly in west and central US (avg. load factor was ⁵ p.p. YoY, at 34%); and (ii) higher avg. capacity in operation (+10% YoY) in North America.

EDPR's growth plans in US grounds on PPA-contracted projects, reinforcing the group's low risk profile. As of Mar-15, EDPR had 399MW of new wind capacity under construction in US, due to be commissioned in ²⁰¹⁵ (200MW at Waverly in Kansas; 99MWfrom Rising Tree South in California; 100MW from Arbuckle in Oklahoma). In 2013-14, EDPR secured PPAs for 1.3GW, thereby reinforcing the visibility over future cash flow power of existing projects and forthcoming new installations. PPAs secured for upcoming new installations include: 200MW due to be commissioned in ²⁰¹⁵ (20-year PPA for Waverly park), 150MW due in ²⁰¹⁶(15-year PPA for 100MW and ^a 20-year PPA for 50MW, in Texas); 155MW for ²⁰¹⁷ (20-year PPA for RECs in New York).

In the 1Q15, EDPR signed an asset rotation transaction with DIF III for the sale of ^a minority stake in ^a 30MW solar PV power plant: proceeds from this transaction (USD30m) are expected to be received in 1Q15. In 2Q15, EDPR received from Fiera AxiumUSD348m, following the financial closing of the sale of ^a minority stake in ^a wind farm portfolio of 1,101MW located in the US, agreed in Aug-14. Additionally, in respect to institutional equity financing structures signed in 2014, EDPR cashed in USD43m in 1Q15 relative to the sale of an interest in the 99MW-park Rising Tree North (remaining amount out of ^a total of USD110m).

In Brazil, EDPR's EBITDA fell by 15%, to R\$9m in 1Q15, reflecting ^a lower load factor derived from weak wind resources in 1Q15 (- 2pp, to 25%) and an 8% increase in the avg. selling price, to BRL370/MWh, mainly driven by PPA's inflation indexation.

In Dec-14, EDPR agreed to sell to ^a CTG's subsidiary in Brazil (CWEI Brasil) ^a 49% equity stake in 84MW in operation and 237MWunder development: CWEI Brasil will invest R\$365m (including R\$100.8m of estimated future equity contributions), subject toadjustments, and the financial closing, pending regulatory approvals, is expected to occur in 2015. EDPR's 236MW under development in Brazil are PPA-contracted for ²⁰ years: ¹²⁰ MW already under construction with ^a PPA due in Jan-16, with ^a price of R\$97/MWh; 117MW starting in Jan-18, with price of R\$109/MWh; both prices are due to be inflation updated over the PPAperiod. In the 1Q15, EDPR closed ^a project finance transaction for ^a total of 120MW of new wind capacity in Brazil, in ^a total amount of R\$306m.

•Energy is sold either under PPAs (up to 20 years), Hedges or Merchant prices; Green Certificates (Renewable Energy Credits, REC) subject to each state regulation

Tax Incentive: (i) PTC collected for 10-years since COD (\$23/MWh in 2013); (ii) Wind farms beginning construction in 2009-10 could opt for 30% cash grant in lieu of PTC

•Feed-in Tariff for 20 years (Ontario)

•

Installed capacity under PROINFA program

•Competitive auctions awarding 20-years PPAs

Sp ain	1Q 15	1Q 14	∆ %	bs. ∆ A
lle d c aci ( ) Ins MW ta ty ap	2, 194	2, 194	0%
loa d fac ( ) Av % tor g.	32 %	38 %	-	- -6 p.p
du ( h ) Pro cti GW on	1, 49 9	1, 0 75	-14 %	-25 1
/ca ( ) Pro d. lem GW h t w pac . co mp en	1, 39 2	1, 37 0
( ) Sta nd ard od ion GW h uct pr	1, 13 7	98
/ Ab ( be low ) s td. od ( h ) GW ov e pr	25 5	2 38
/o d. lem ( h ) Pro GW t w cap . co mp en	10 7	7 38 0
( / h ) Av Pri € MW g. ce	70 .9	56 .3	26 %	+1 5
( / ) To tal GW h: lise d p l € MW h rea oo	+4 1	+2 1	1% 10	+2 1
lat ad j. o td. GW h ( ) Re €m gu ory n s	-	17 .4
lem ( ) Co €m t mp en	44	42 .3
/ dg ( los ) ( ) He ing ins €m ga ses	0.7	2.9
fit ( ) Gro 1 ss pro	10 6		8%
( ) 1 EB ITD A	77	98	12 %	+8
( ) EB IT 1	44	68 35	24 %	+8 +8
tal led ( ) Ins ity MW Eq uit ca pac y	174	174	0%	-
( ) Ca €m pe x cit nd tio ( ) Ca MW nst pa y u er co ruc n	1 2	2 2	% -53 0%	-1 -

's by ( ), In Sp in, ED PR EB ITD A 1 2 % +€ 8m € 77 Yo Y in 1 Q 15 to a ros e m	dr by h he l d h d he ket ive ig ise ice iev in t n r rea p r ac e ma r ,
( / / ). € 1 h in 1 Q 15 fro € 2 1 h in 1 Q 14 4 M W M W up m ,

Installed capacity in Spain is stable at 2,194MW in 1Q15 (MW EBITDA), to which accrues 174MW, equivalent to EDPR's equity position in other wind projects (equity-method consolidated).

Electricity output in Spain fell by 14% YoY, to 1.5TWh in 1Q15, reflecting outstanding wind conditions in 1Q14. Avg. price advanced by 26% YoY, to €71/MWh, propelled by ^a doubling of realised pool price (€41/MWh in 1Q15) and €44m revenue from capacity complement. In 1Q15, 91% of EDPR's installed capacity in Spain is entitled to receive capacity complement per MW.

As ^a way to reduce its exposure to merchant prices in Spain, EDPR hedged 1.8TWh at €47/MWh for the rest of ²⁰¹⁵ and 1.3TWh at €48/MWhfor ²⁰¹⁶.

l Po rtu ga	1Q 15	1Q 14	∆ %	∆ A bs.
( ) lle d c aci Ins ta ty MW ap	62 4	62 1	0%	+2
d fac ( % ) Av Loa tor g.	38 %	43 %	-	-6 p.p
Ele ( h ) icit GW ctr utp ut y o	50 5	58 0	-13 %	-75
ell ( / h ) Av ing ice € MW g. s pr	10 8	10 9	-1%	-1
Gro fit ss pro	55	64	% -14	-9
EB ITD A	47	56	-15 %	-8
EB IT	41	49	-17 %	-9
tal led ( ) Ins ity MW Eq uit ca pac y	53 3	46 4	15 %	+6 9
( ) Ca €m pe x	5	2	13 8%	+3
cit nd tio ( ) Ca MW nst pa y u er co ruc n	6	-	-	+6

In Portugal, EDPR owns ^a portfolio with 624MW: 622MW of wind capacity (51% owned by EDP and 49% owned by CTG) and2MW of solar PV (installed in Mar-14). Also in the wind business, EDPR holds ^a 40% equity stake in ENEOP consortium (equity consolidated), with 533MW attributable to EDPR's 40% interest in ENEOP. In line with MoU signed by EDPR and CTG in Dec-13, once ENEOP's assets are split between its shareholders, EDPR will sell 49% of its share in ENEOP – execution of the MoU is expected to occur in 2015.

EDPR's EBITDA in Portugal fell by 15% YoY, to €47m in 1Q15, reflecting lower output derived from outstanding windresources in 1Q14 and low inflation scenario in Portugal. Wind production in 1Q15 was 13% lower YoY, as the above-the average wind resources in 1Q15 (wind factor: 1.14) fell short of the exceptionally strong wind resources in 1Q14 (wind factor: 1.41). Accordingly, avg. load factor fell 6pp YoY, to 38% in 1Q15. Avg. selling price in 1Q15 stood 1% below the 1Q14, penalised by ^a low inflation scenario.

•Premium calculation is based on standard assets (standard load factor, production and costs); Capacity complement per MW is paid for a 20-year period and varies with the year of commissioning

MW EBITDA: Feed-in Tariff updated with inflation and inversely correlated with load factor. Duration: 15 years (Feed-in tariff updated with inflation) + 7 years (extension cap/floor system: €74/MWh - €98/MWh). The 7-year extension of tariff as from 16thyear was secured in exchange for an annual payment between 2013 and 2020 (€4m/year for EDPR).

ENEOP (MW Equity): price defined in a international competitive tender and set for 15 years (or the first 33 GWh per MW). Tariff for first year established at c.€74/MWh and CPI monthly update for following years

EDP Renováveis: Rest of Europe

f E Re st o uro pe	1Q 15	1Q 14	∆ %	bs. ∆ A
tal led Ins MW	41 3	35	4%	6 +5
( ) ity ca pac ( ) Av loa d fac % tor	1, % 33	1, 7 % 32	-	1 p
g. Ele icit ( GW h ) ctr ut	92	80	16 %	.p. +1 25
utp y o / ell ( h ) Av ing ice € MW g. s pr	8 88	2 97	-9%	-9
lan d Po
tal led ( ) Ins ity MW ca pac	39 2	37 4	5%	8 +1
( ) Av loa d fac % tor g.	% 34	% 34	-	-1 p.p
Ele icit ( h ) GW ctr utp ut y o	27 3	26 7	3%	+7
/ ell ( h ) Av ing ice PLN MW g. s pr	40 1	40 7	-1%	-5
/ d EU R PLN - A . R in rio ate vg pe	4.1 9	4.1 8	0%	+0
Ro nia ma
( ) tal led ity Ins MW ca pac	52 1	52 1	0%	-
loa d fac ( % ) Av tor g.	33 %	24 %		9 p .p.
Ele ( h ) icit GW ctr utp ut y o	31 7	19 0	- 67 %	+1 27
ell ( / h ) Av ing ice RO N MW g. s pr	31 1	42 1	-26 %	-11 0
/ od EU R RO N - Av Rat e i eri g. n p	4.4 5	0 4.5	1%	-0
Fra nce
tal led ( ) Ins ity MW ca pac	34 0	32 2	5%	+1 8
loa d fac ( ) Av % tor g.	32 %	38 %	-	-6 p.p
Ele ( h ) icit GW ctr utp ut y o	23 4	25 6	-9%	-23
( / ) Av ell ing ice € MW h g. s pr	91	91	0%	+0
lg ium & ly Be Ita
tal led ( ) Ins ity MW ca pac	16 1	14 1	14 %	+2 0
loa d fac ( ) Av % tor g.	35 %	33 %	-	2 p .p.
Ele ( h ) icit GW ctr utp ut y o	104	89	16 %	+1 4
( / ) Av ell ing ice € MW h g. s pr	11 1	11 2	-1%	-1
fit Gro ss pro	80	76	5%	+4
EB ITD A	66	61	8%
EB IT	51	42	19 %	+5 +8
( ) Ca €m pe x	19	10	% 86	+9
cit nd tio ( ) Ca MW nst pa y u er co ruc n	75	18	32 1%	+5 7

In European markets outside of Iberia, EBITDA rose by 8% YoY (+€5m), to €66m in 1Q15, driven by higher avg. capacity on stream(+10% YoY), higher avg. load factor (+1pp YoY) and lower avg. selling price (-9% YoY, due to lower avg. prices in Romania derivedfrom lower green certificate). As of Mar-15, EDPR has 75MW under construction: 53MW in Poland, 12MW in France and 10MWin Italy.

In Poland, EDPR installed 18MW of new wind capacity over the last ¹² months (fully concentrated in 4Q14). As ^a result, EDPRcurrently operates 392MW of wind capacity under different remuneration schemes: 70MW at Korsze, through ^a 10-year PPA; 120MW at Margonin, receiving 'wholesale market ⁺ GC' (GC long term contracted for ¹⁵ years); and 184MW receiving 'Regulatedprice ⁺ GCs'. Wind output rose by 3% in 1Q15, to 273GWh in 1Q15, mainly reflecting higher avg. capacity on stream and stable load factor (at 34%). Avg. selling price was 1% lower YoY, at PLN401/MWh.

In Romania, EDPR operates 521MW of wind (471MW) and solar PV (50MW). Output surged by 67%, to 317GWh in 1Q15(305GWh wind-based), propelled by higher average MW in operation and ^a 9pp increase in the avg. load factor, to 33%. In turn, avg. selling price fell by 26% YoY to RON311/MWh, as green certificate ("GC") were sold at the floor of the regulated collar.

In France, EDPR added 18MW of new wind capacity in the last ¹² months (fully concentrated in 2H14), raising total installedcapacity in the market to 340MW. Wind output in 1Q15 fell by 9% YoY, to 234GWh as the 6pp YoY drop in load factor derivedfrom low wind resources was partially compensated by portfolio expansion. Avg. tariff in the period was broadly stable YoY, reflecting low inflation context.

In Belgium, the 71MW in operation delivered ^a 5% increase in output backed by higher average capacity on stream and ^a 1%decrease in avg. selling price, to €111/MWh in 1Q15, reflecting ^a lower PPA price for the capacity added in 3Q14. In Italy, where EDPR installed 20MW of new wind capacity in the last ¹² months (in 4Q14), output advanced 26%, driven by capacity additions and ^a 8pp YoY increase in avg. load factor, to 38%. Avg. selling tariff was 2% lower YoY, at €120/MWh in 1Q15, reflecting the lower price of capacity added under the new regime (vs. the old regime).

• Price set either through bilateral contracts or selling to distributor at regulated price (PLN163.6/MWh in 2015); Wind receive 1 GC/MWh which can be traded in the market. Electric suppliers have a substitution fee for non compliance with GC obligation (2014: PLN300/MWh)

• Wind and solar production are sold at 'market price + GC'. Wind assets receive 2 GC/MWh until 2017 and 1 GC/MWh after 2017 until completing 15 years. 1 out of the 2 GC earned until Mar-17 can only be sold from Jan-18. Solar assets receive 6 GC/MWh for 15 years. 2 out of the 6 GC earned until Mar-2017 can only be sold after Apr-2017. GC are tradable on market under a cap and floor system (cap €59.9 / floor €29.4).

•Feed-in tariff for 15 years: (i) €82/MWh up to 10th year, inflation updated; (ii) Years 11-15: €82/MWh @ 2,400 hours, decreasing to €28/MWh @3,600 hours

•Wind & solar energy sold at 'Market price + green certificate (GC)'; Separate GC prices with cap and floor for Wallonia (€65/MWh-100/MWh) and Flanders (€90/MWh-100/MWh); Option to negotiate long-term PPAs

•Projects online before 2013 receive: (i) For 2015, GC price from GSE will be €97.4; (ii) As from 2016, 'pool + premium' (premium = 1 x (€180/MWh - "P-1") x 0.78). New assets: competitive auctions awarding 20-years PPAs

Regulated Networks & Regulatory Receivables in Iberia

( ) Inc e S € m tat t om em en	1Q 15	1Q 14	∆ %	bs. ∆ A
fit Gr Pr oss o	43 1	44 1	-2%
				-10
lies d s Su ice pp an erv s	86 32	93 38	-8% % -17	-7 -7
Pe el c ost rso nn s Co ith cia l be fits sts so ne w	5	5	1%	+0
he ing (ne ) Ot rat sts t r o pe co	( ) 16	59	-	-75
ing ( ) Ne t O Co 1 rat sts pe	10 7	19 6	-45 %	-89
EB ITD A	32 4	24 5	32 %	9 +7
vis ion Pro s	0	( ) 1	-	+1
isa tio nd im irm Am ort t n a pa en	82	83	-1%	-1
EB IT	24 2	16 3	48 %	+7 9
Ca x & Op rfo Pe pe ex rm an ce	1Q 15	1Q 14	∆ %	bs. ∆ A

lla b le O ing ( ) Co Co 5 ntr rat sts o pe /c lien ( /c lien ) Co € nt. sts t t co	11 8 15	13 2	-10 % -10 %	-14 -2
/ km f n ork ( / ) Co € Km nt. sts etw co o	45 8	16 51 0	-10 %	-52
( ) Em loy # p ee s	3, 87 5	3, 92 2	-1%	-47
( f S bsi die ) ( ) Ca Ne €m t o pe x u s	69	70	-1%	-1
ork ( '00 ) Ne 0 K tw m	25 7	25 8	-0%	-1


( ) lat cei b les € m Re Re gu ory va	1Q 15	1Q 14	∆ %	bs. ∆ A
l N Ibe ria lat cei b les To Re Re ta et gu ory va	2, 11 7	2, 93 3	-28 %	-81 6
ff d fic Sp ain - T ari it e

inn ing f P eri od Be g o vio rio ds iff de fic its Pre 4 tar us	2	26 4	-99 % -	-26 2
( ) pe riff de fic he d Ta it i rio n t pe	42 -	( ) 23 17	-	+6 5
he ( ) Ot 3 r	-	-	-	-17 -
d o f P od En eri	44	25 9	-83 %	-21 5
l - rt S lie Di ibu tio Po rtu Las t R str ga eso up p r + n +	Ga s

inn ing f P eri od Be g o ds iff de Pre vio rio via tio 2 tar us n	2, 20 3	2, 04 5	8%	+1 58
( ) pe riff de he d Ta via tio n i rio n t pe	( ) 68 6 37 5	( ) 33 8 72 1	-10 3% -48 %	-34 9 -34 6
( ) Ot he 3 r	23	39	% -40
d o f P eri od En	1, 91 5	2, 46 7	-22 %	-15 -55 3
l - 's Po CM EC rtu ga
f P Be inn eri od o
ing g in th eri od Re Ret e P cov urn	11 2 18	37 7 24 7	% -70 93	-26 5 +2
( ) / ery via tio n i he rio d De n t pe	( ) 64	( ) 77	% -17 %	29 -13
he Ot r d o f P od En eri	0	0	n.m	+0

Regulated networks in Iberia include our activities of distribution of electricity and gas, in Portugal and Spain.

EBITDA from regulated networks rose by 32% YoY (+€79m), to €324m in 1Q15, impacted by ^a €78m one-off gain booked onthe sale of assets held by Gas Energía Distribución Murcia to Redexis on 30-Jan-15. Adjusted for this impact, EBITDA fromregulated networks in Iberia was relatively stable, owing to lower regulated revenues which were offset by lower operating costs. Gross profit declined by 2% YoY (-€10m) in 1Q15, reflecting: (i) in Portugal, ^a lower return on RAB in electricity distribution derived from the lower sovereign risk and fast clients' switching to free market; (ii) in Spain, higher regulatedrevenues in electricity distribution offset by lower gas regulated revenues impacted by the disposal of distribution assets.

Controllable operating costs fell by 10% YoY (-€14m), reflecting essentially ^a decrease in supplies and services (due to lower maintenance/repair works and lower client services stemming from clients switching from LRS to the liberalized market) andheadcount reduction (-1% YoY). Capex in 1Q15 stood relatively stable, amounting to €69m.

In Portugal, the total debt owed by the electricity system to EDP and to financial investors was nearly flat, amounting to €5.3bn in Mar-15.

Regulatory receivables owed to EDP in Iberia decreased by €200m in 1Q15, from €2,317m in Dec-14 to €2,117m in Mar-15, driven by ^a €242m decrease in Portugal and ^a €42m increase in Spain.

EDP's regulatory receivables from electricity distribution, last resort supply and gas distribution in Portugal decreased from€2,203m in Dec-14 to €1,915m in Mar-15 driven by: (1) -€465m following the sale without recourse of the right to receive part of the ²⁰¹⁴ tariff deficit; (2) +€375m regarding the ex-ante tariff deficit for 2015, to be fully recovered through 2016-2019tariffs and remunerated at 3.01% annual return; (3)-€220m recovered through tariffs related to negative previous years' deviations and to past tariff deficits; (4) +€15m of new electricity tariff deviations created in 1Q15; and (5) -€15m of deviations returned to the system in the gas distribution. The main drivers for new tariff deviations generated during the 1Q15, focused inelectricity distribution and LRS, were: (i) +€69m boosted by higher-than-expected special regime production (16% ahead of ERSE assumption) and from higher-than-expected overcost with special regime production (€64/MWh in 1Q15 vs. €61/MWhassumed by ERSE in the calculation of ²⁰¹⁵ tariffs); (ii) -€15m (amount to return to the tariffs) mainly propelled by cheaperthan-expected electricity purchases; and (iii) -€39m tariff deviation generated in electricity distribution activity (higher demand and deviations on consumption mix).

Regulatory receivables from CMECs increased from €112m in Dec-14 to €159m in Mar-15 due to: (1) €18m recovered in 1Q15through tariffs, related to ²⁰¹³ negative deviations and (2) €64m negative deviation in 1Q15, reflecting ^a €4m adjustment from2014, due to be received in 2016-2017 (more details on page 11).

According to ERSE's final version for ²⁰¹⁵ tariffs, released on 15-Dec-14, Portuguese electricity system's regulatory receivables are expected to stay flat over 2015.

Regulatory receivables in Spain amount to €44m in Mar-15, derived from booking EDP España portion of the gas tariff deficit in Spain, which has been estimated at €700m for the whole systemas of 31-Dec-14.

(1) Net Operating Costs = Operating Costs (Supplies and services + Personnel costs + Costs with social benefits + Concession fees) + Other operating costs (net)

(2) Includes the assignment to a third party of the right to tariff deficits/adjustments and recovery or pay-back through the tariffs of previous years' tariff deviations. (3) Includes interests on tariff deviations.

(4) Includes the recovery/payment of previous periods tariff deficits. (5) Supplies & services and personnel costs.

Electricity Distribution and Last Resort Supply in Portugal

( ) Inc e S € m tat t om em en	1Q 15	1Q 14	∆ %	bs. ∆ A

fit Gr Pr oss o	31 5	32 6	-3%	-11
Su lies d s ice pp an erv s	66	70	-6%	-4
el c Pe ost rso nn s	24	29	-17 %	-5
ith l be fits Co cia sts w so ne	5	5	-0%	-0
fe Co ssi nce on es	63	63	-1%	-0
he (ne ) Ot ing rat sts t r o pe co	-2	-3	-	+1
( ) Ne t O ing Co 1 rat sts pe	6 15	16 5	-5%	-9
EB ITD A	15 8	16 1	-2%	-3
Pro vis ion s	1	-1	-	+1
nd Am isa tio im irm ort t n a pa en	59	59	0%	+0
EB IT	98	10 3	-4%	-4

fit rfo Gr Pr Pe oss o rm an ce	1Q 15	1Q 14	∆ %	bs. ∆ A

fit Gr Pr €m oss o	31 5	32 6	-3%	-11
( ) lat ed fit Re gu gr oss pr o	31 3	32 4	-3%	-11
ula ted fit No n-r eg gr oss pr o	2	2	-6%	-0
bu rid Dis tri tio n G
lat ed ( ) Re € m gu re ve nu es	29 7	30 4	-2%	-7
	68 7	47 0	2%	+2 17
Ele icit dis tri bu ted ( h ) GW ctr y ly ( th ) Su Po int pp s	11, 6, 08 2	11, 6, 07 0	0%	+1 2

ly Las t R rt S eso up p ( ) Re lat ed € m gu re ve nu es	16	20	-20 %	-4
Cli lied th ts s en	2, 174	3, 43 1	-37 %	-1, 25 7
( ) up p Ele old ( h ) icit GW ctr y s	1, 84 5	3, 07 4	-40 %	-1, 22 9

rfo Ca x & Op Pe pe ex rm an ce	1Q 15	1Q 14	∆ %	bs. ∆ A
lla b le O ing ( ) Co Co 2 ntr rat sts o pe /c /c lien ( lien ) Co € nt. sts t t co / / km f n ork ( ) Co € Km nt. sts etw co o loy ( ) Em # p ee s	91 14 .9 40 5 3, 34 0	10 0 16 .4 44 7 3, 35 9	-9% -9% -9% -1%	-9 -2 -42 -19
( ) ( ) Ca f S bsi die €m Ne t o pe s x u ork ( '00 ) Ne 0 K tw m al. (m ) ( ) Eq uiv int tio im in. 3 n t err up e	55 22 4 12	56 22 3 23	-0% 0% -49 %	-0 +1 -11

EBITDA from electricity distribution and last resort supply (LRS) in Portugal decreased by 2% (-€3m), to €158m in 1Q15, mainly impacted by ^a lower return on RAB partially offset by lower operating costs.

On 15-Dec-14, ERSE released ²⁰¹⁵ tariffs and the parameters underlying the next regulatory period (2015-17) for our electricity distribution and last resort supply activities in Portugal setting ^a 3.3% tariff increase for normal low voltage (NLV) segment, applicable to clients in the regulated market (out of the Social Tariff) and ^a 14% reduction in the social tariff, whichconveys no additional costs for the electricity system.

Electricity distribution regulated revenues were set at €1,194m for ²⁰¹⁵ based on: (1) regulated rate of return on assets (RoRAB) set at 6.75% for 2015, on ^a preliminary base (vs. 8.26% in 2014), reflecting an underlying avg. 10-year Portuguese bond yields of 3.6%; the ultimate RoRAB will depend on the daily average of the Portugal's 10Y bond yield between October of year 't-1' and September of year 't', with ^a floor at 6% and ^a cap at 9.5%; (2) an expected electricity demand in Portugal of 44.6 TWh in ²⁰¹⁵ (1.8% above ²⁰¹⁴ electricity distributed); and (3) ^a GDP deflator of 0.9%.

Regarding last resort electricity supply activity regulated revenues were set, for 2015, the following assumptions: (1) regulated revenues set at €61m in 2015; (2) ^a forecast for average electricity procurement price of €55.4/MWh, based on ^a forecast for average pool price of €50.5/MWh; (3) ^a forecast for average special regime premium of €60.8/MWh and (4) ^a forecast of 21.0TWh of special regime generation (4.1% below 2014).

In 1Q15, distribution grid regulated revenues declined by 2% (-€7m), to €297m, which was largely attributable to ^a lower return on RAB (6.36% in 1Q15 vs. 8.37% in 1Q14) driven by lower Portuguese sovereign yield. In 1Q15, electricity distributedrose by 2% YoY, on account of ^a higher demand from industrial clients, in line with some signs of recovery in economic activity during the period.

Last resort supplier (EDP SU) regulated revenues were 20% lower (-€4m), to €16m in 1Q15, mainly reflecting consumers' fast switching to the free market. As part of the rules and calendar defined for the phasing out of regulated tariffs in Portugal, EDP SU can no longer contract new clients (since 1-Jan-13), while the regulator can apply quarterly tariff increases in order toencourage clients' transfer to ^a liberalised supplier. The volume of electricity supplied by our LRS fell by 40% YoY, to 1.8TWh in 1Q15. Total clients supplied declined 1,257 thousands YoY, to 2,174 thousands in Mar-15 (representing 36% of total electricity clients), mostly driven by the residential segment.

Controllable operating costs fell by 9% in the 1Q15 (-€9m), reflecting mostly ^a decline in Supplies & Services (-6% YoY), ^a decrease of our LRS activity due to consumers' switching to the free market and headcount reduction (-1% YoY).

Capex nearly matched the level of 1Q14, amounting to €55m in 1Q15. EIT dropped considerably, from ²³ minutes in 1Q14 to¹² minutes in 1Q15, reflecting favourable weather conditions.

(1) Net Operating Costs = Operating Costs (Supplies and services + Personnel costs + Costs with social benefits + Concession fees) + Other operating costs (net)(2) Supplies & services and personnel costs. (3) Adjusted for non-recurring impacts (rainstorms, high winds and summer fires).

Electricity and Gas Networks in Spain and Gas Networks in Portugal

edo

e S ( € m ) Inc tat t om em en		Ele icit Sp ctr y	ain			Ga s S pa	in			Ga s P ort ug	l a		Ibe lat ed ks				Ab
	1Q 15	1Q 14	% ∆	Ab s. ∆	1Q 15	1Q 14	% ∆	Ab s. ∆	1Q 15	1Q 14	% ∆	Ab s. ∆	ria n R Ne tw eg u or	1Q 15	1Q 14	% ∆	s. ∆
fit Gr Pr oss o	48	41	18 %	7	51	57	-10 %	-6	16	17	-4%	-1	mb ly ( h ) Nu Su Po int t er pp s Ele icit Sp ain ctr y	65 9	65 9	0%	+0
Su lies d s ice pp an erv s el c Pe ost rso nn s	9 5	10 6	% -12 -20 %	-1 -1	7 2	9 2	% -23 -13 %	-2 -0	4 0	3 0	3% 12 %	0 0	Ga s S in pa l Ga s P ort uga	93 6 32 1	1, 02 0 30 9	-8% 4%	-83 +1 2
ith l be fits Co cia sts w so ne he (ne ) Ot ing rat sts t r o pe co ( ) Ne t O ing Co 1 rat sts pe	0 ( ) 0 14	0 ( ) 3 14	- -90 % 1%	0 2 0	0 ( ) 77 ( ) 68	0 1 13	-29 % n.m -	-0 -78 -80	0 0 4	0 0 4	-3% -85 % -3%	-0 -0 -0	Dis tri bu ted ( h ) En GW erg y Ele icit Sp ain ctr y	2, 38 1	2, 36 5	1%	+1 6
EB ITD A	34	27	27 %	7	11 9	44	17 0%	75	12	13	-5%	-1	Ga s S in pa Ga l s P ort uga	8, 84 4 2, 03 1	13, 55 5 1, 97 9	% -35 3%	-4, 71 0 +5 2
Pro vis ion s nd Am isa tio im irm ort t n a pa en	0 9	- 8	- 2%	0 0	( ) 0 10	( ) 0 12	14 1% -19 %	-0 -2	( ) 0 4	0 3	n.m 32 %	-1 1	k ( ) Ne Km tw or Ele icit Sp ain ctr y Ga s S in pa	20 30 9 , 8, 14 7	20 19 6 , 10, 00 8	1% -19 %	+1 13 86 -1, 1
IT EB	26	19	% 37	7	10 9	32	1% 24	77	9	10	% -11	-1	Ga s P l ort uga	4, 67 7	4, 51 3	4%	+1 64
(ne bsi die ) Ca t o pe x s s u s	6	5	27 %	1	5	5	-5%	-0	3	5	-30 %	-1	loy ( #) Em p ees Ele icit Sp ain ctr y	29 7	30 2	-2%	-5
fit Gr Pr oss o lat Re ed Re gu ve nu es ula ted fit No n-r eg gr oss pr o	48 39 9	41 39 2	18 % -1% 40 7%	7 -0 8	51 44 8	57 50 7	-10 % % -13 15 %	-6 -7 1	16 16 1	17 16 1	-4% -5% 3%	-1 -1 0	Ga s S in pa l Ga s P ort uga	17 7 61	19 9 62	-11 % -2%	-22 -1

ELECTRICITY DISTRIBUTION IN SPAIN

EBITDA from our electricity distribution activity in Spain rose by 27% YoY (+€7m), to €34m in 1Q15, supported by revenues related to adjustments from previous years in 1Q15 (+€7m). Electricity distributed by EDP España, mostly in the region of Asturias, grew by 1% in 1Q15, to 2.4TWh.

Gas distribution regulated revenues attributable to our gas distribution subsidiary in Spain amount to €172m in 2015, excluding €14.7m of full year regulated revenues attributable to Gas Energía Distribución Murcia, sold to Redexis on 30-Jan-15, and €4.3m of full year regulated revenues attributed to the remaining asset perimeter expected to be sold to Redexis within the second quarter of 2015.

In Dec-13, Spanish Government approved Law 24/2013 and RD 1048/2013 that establishes the newregulatory framework for electricity distribution assets maintaining the principles announced in Jul-13 by RD9/2013 (return on RAB equivalent to ^a 200bp premium over 10-year Spanish bond yields (equivalent to 6.5%) in 2014-2020). Until the release of concrete measures on the edicts of the law referred to above, the regulated revenues of EDP Spain into force for the year ²⁰¹⁵ are €157m (calculated according to transient remuneration scheme of RDL 9/2013).

GAS REGULATED NETWORKS IN SPAIN

EBITDA of gas distribution in Spain in 1Q15 amounted to €119m (+€75m YoY), reflecting i) ^a €78m one-off gain stemming from the sale of assets held by Gas Energía Distribución Murcia to Redexis on 30-Jan-15 and ii) -€4m derived from the de-consolidation of gas distribution assets. Excluding this one-off impact, EBITDA rose by 3% (+€1m), supported by ^a decrease in operating costs (lower supplies and services). Volume of gas distributed dropped by 35% YoY, to 9TWh, owing to the disposal of distribution gas assets. Excluding this impact, gas distributed rose by 5%, on the back of harsher winter temperatures in 1Q15 vs. 1Q14.

According to ^a Ministerial Order of Dec-14, regulated gas activities will be squared by ^a 6-year regulatory period and subject to possible adjustments every ³ years. The remuneration model for gas distributionactivities is maintained although inflation update factor is eliminated, allowed revenues are cut and returns are more dependent on demand. The impact of these measures on EDP in ²⁰¹⁵ and in the following years is €9m vs. €4.7m in 2014.

GAS REGULATED ACTIVITIES IN PORTUGAL

EBITDA from gas regulated activities in Portugal went down by 5% (-€1m), to €12m in 1Q15, due to lower regulated revenues in the supply business derived from consumers' switching to the free market. Regulatedrevenues from distribution business were flat YoY, reflecting ^a return on RAB of 8.41% in 1Q15 vs. 9.0% in1Q14. Volume distributed rose by 3% in 1Q15, to 2.0TWh, in line with the 4% growth in the number of supply points, prompted by the continuing effort of new client connection in the region operated by EDP.

In Jun-13, ERSE disclosed the regulatory assumptions for the period from Jul-13 to Jun-16, indexing the rate of return on assets to the avg. Portuguese Republic 10-year bond yield between Apr ¹st and Mar ³¹st prior to the beginning of each regulatory year, with ^a floor at 7.83% and cap at 11%. In each of the years of this regulatory period the rate of return on assets is defined at 9% on ^a preliminary basis. Total regulated revenues ondistribution and LRS for EDP in the 2014/15 regulatory year were set at €62m.

On 15-Apr-15, ERSE unveiled ^a proposal for an average -7.3% decrease of last resort tariff for small clients (lowconsumption segment <= ¹⁰ ^m³/year) to be in place from 1-Jul-15 until 30-Jun-16. ^A final decision will be taken until 15-Jun-15.

EDP - Energias do Brasil: Financial Performance

e S Inc tat t om em en		lid Co ate nso	\$ m d ( ) R						ias do asi l En Br erg
	1Q 15	1Q 14	∆ %	bs. ∆ A	1Q 15	1Q 14	∆ %	bs. ∆ A
									\$ /s Sh d o f p od ( ha ) ice eri R at are pr en re
fit Gr Pr oss o	66 2	62 9	5%	+3 2	20 5		6%	+1 1	mb f sh d (m illio ) Nu s Is er o are sue n
									(m ) Tre ck illio sto asu ry n
Su lies d s ice pp an erv s	11 6	11 0	5%	+5	36	34	5%	+2	(m ) mb f sh ed by illio Nu ED P er o are s o wn n
el c nd loy be fits Pe ost rso nn s a em p ee ne	95	88	8%	+7	29	27	8%	+2
he (ne ) Ot ing rat sts t r o pe co	35	21	69 %	+1 4	11	6	70 %	+4	/ al - d o f p od Eu Re En eri te ro ra
ing ( ) Ne t O Co 1 rat sts pe	24 6	21 9	12 %	+2 6	76			+9	/ al - f p od Eu Re Av eri te ro era ge o ra
									Inf lat ( ths ) ion IPC A - 12 te ra m on
EB ITD A	41 6	41 0	1%	+6	12 9	12 7	2%	+2
									/ eb (x ) Ne t D EB ITD A t
Pro vis ion s	7	4	91 %	+3	2	1	92 %	+1	f D eb ( ) Av Co % st o t era ge
nd Am isa tio im irm ort t n a pa en	91	88	3%	+3	28	27	4%	+1	( ) Av Int Rat CD I st era ge ere e
EB IT	31 8	31 9	-0%	-1	99	98	0%	+0	loy ( ) Em # p ee s
Fin cia l re sul ts an	( ) 94	( ) 87	-8%	-7	( ) 29	( ) 27	9%		\$ lan he Fig ( Mi llio Ke Ba S R et ce ure s n
sul fro Re oci ts ate m ass s	( ) 38	( ) 14	-17 4%	-24	( ) 12	( ) 4	-	-2 -8	) y
									fin l de bt Ne cia t an
fit Pre -ta ro	18 5	21 7	-15 %	-32	57	67	-14 %	-10	lat ble Re cei
x p									gu ory re va s No ling In tro ter est
									n-c on s uit bo ok lue Eq y va

x & Fi nci l In Ca stm ts pe na a ve en		\$ m ( R	)			( € m	)		\$ Fin cia l R lts ( Mi llio ) R an esu n
	1Q 15	1Q 14	∆ %	∆ A bs.	1Q 15	1Q 14	∆ %	∆ A bs.
									Ne t In Co ter est sts
Ca pe x	67	85	% -22	-19	21	26	% -21	-6	Ca ita lise d C ost p s
									Di ffe d D eri ive Fo vat rex ren ces an s
Fin cia l In ( ) 2 stm ts an ve en	30	6	-	+2 4	9	2	-	+8	he Ot r

			Co lid ate nso	( ) d € m			1Q 15	1Q 14	∆ %	∆ A bs.
	bs. ∆ A	1Q 15	1Q 14	∆ %	bs. ∆ A
						( \$ /s ) Sh ice d o f p eri od ha at R are pr en re	10 .35	10 .30	0%	+0 .05
5%	+3 2	20 5	194	6%	+1 1		47 6.4	47 6.4	-	-
						ck (m illio ) Tre sto asu ry n	0.8	0.8	-	-
5%	+5	36	34	5%	+2		24 3.0	24 3.0	-	-
	+7	29	27	8%	+2
	+1 4	11	6	% 70	+4		3.5 0	3.1 3	% -11	+0 .37
	+2 6	76	68	13 %	+9		3.2 2	3.2 4	1%	-0. 02
						Inf lat ( ths ) ion IPC A - 12 te ra m on	8.1 %	-	-	-
1%	+6	12 9	12 7	2%	+2
						eb / (x ) Ne t D EB ITD A t	1.4	1.5	-	-0. 1
	+3	2	1	92 %	+1		12 .3	10 .0	-	2.2 p.p
3%	+3	28	27	4%	+1		11 .7	10 .0	-	1.8 p.p
	-1	99	98	0%	+0		2, 60 7	2, 82 2	-8%	-21 5
	-7	( ) 29	( ) 27	9%	-2		1Q 15	1Q 14	∆ %	∆ A bs.
	-24	( ) 12	( ) 4	-	-8
						fin cia l de bt Ne t an	2, 32 1	2, 40 3	-3%	-82
	-32	57	67	-14 %	-10		56 1	21 6	16 0%	+3 45
						ling No In tro ter est n-c on s	1, 69 2	1, 70 0	0%	-8
						bo ok lue Eq uit y va	5, 02 3	4, 73 4	6%	+2 89

			( € m	)			1Q 15	1Q 14	∆ %	bs. ∆ A
	bs. ∆ A	1Q 15	1Q 14	∆ %	bs. ∆ A
						Ne t In Co ter est sts	( ) 89	( ) 94	6%	+5
		21	26	-21 %	-6		0	17	-99 %	-17
						ffe d D Fo Di eri ive vat rex ren ces an s	( ) 24	9	-	-33
-	+2 4	9	2	-	+8		18	( ) 19	-	+3 7
						Fin cia l R lts an esu	( ) 94	( ) 87	-8%	-7

In local currency, EDP Brasil ("EDPB") EBITDA increased 1% YoY (+R\$6m) to R\$416m in 1Q15. EBITDAfrom distribution went up 64% YoY (+R\$90m), driven by higher regulated revenues, essentially reflecting the annual tariff readjustments at both our DisCos (Escelsa: +26.54% from Aug-14 andBandeirante: +22.34% from Oct-14), and by the recognition of regulatory receivables at gross profit level as from Dec-14. Generation and Supply EBITDA went down 28% YoY (-R\$82m), reflecting: i) lowGSF(3) (79% in 1Q15) and the subsequent generators' need to purchase energy at high market prices; which was mitigated by: ii) the seasonal allocation of volumes sold, with ^a significant portion of volumes allocated to the 1Q15 (29%) vs. the 1Q14 (27%). EBITDA performance in Euro terms was most alike – ForEx impact was negligible (1% appreciation of the BRL vs. the EUR).

Net operating costs went up 12% YoY to R\$246m in 1Q15: i) personnel costs and employee benefits increased 8% YoY, reflecting the annual salary update (+7.4%), lower capitalized costs, higher indemnities and lower headcount; and ii) supplies & services went up 5% YoY, translating higher expenses higher expenses with O&M, IT and clients' services.

Net financial costs increased 8% YoY to R\$94m in 1Q15, translating: i) lower net interest costs, reflecting the equity consolidation of Jari and Cachoeira Caldeirão hydro projects (vs. full consolidation in 1Q14) as well as lower average financial debt, while average cost of debt

increased 2.2pp to 12.3% in 1Q15; and ii) lower capitalised interests. Net financial debt decreased 3% YoY reflecting higher gross financial debt (+R\$0.9m) which was more than compensated by higher 'cash andequivalents'.

Results from associated totalled -R\$38m in 1Q15, down R\$24m YoY, reflecting ^a more negative contribution from Pecém ^I coal facility (-R\$26m in 1Q15 vs. -R\$15m in 1Q14), on the back of higher net financial costs, as well the ^a negative contribution from Jari hydro power plant (-R\$12m in 1Q15) driven by low GSF in the period.

As of Mar-15, hydro reservoirs in the Southeast/Center-West ("SE-CW") regions were at 28% of their maximum level (vs. 19% in Dec-14 and 36% in Mar-14). Although Jan/Feb-15 ended up being some of the worst months in terms of rainfall levels for the period, Mar/Apr-15 benefitted from some recovery and by the end of Apr-15, reservoir levels were above 30%. Nonetheless, given relatively low reservoir levels andinsufficient rainfall, GSF(3) stood at particularly low levels (79% in 1Q15) leading hydro generators to keep on purchasing energy at high market prices to meet their PPA obligations. At the same time, despite the continued strong thermal dispatch, thanks to the application of ^a new price cap methodology starting Jan-15(new cap at R\$388/MWh vs. previous R\$822/MWh), average electricity spot prices (PLD) fell fromR\$647/MWh(4) in 1Q14 to R\$388/MWh(4) in 1Q15.

(1) Net Operating Costs = Operating Costs (Supplies and services + Personnel costs + Costs with social benefits) + Other operating costs (net);

(2) Excluding investments in wind farms held by EDP Brasil (45%) and EDP Renováveis (55%).

⁽³⁾ GSF: Generation Scaling Factor; (4) Source: CCEE; based on weekly prices; Southeast/Center-West regions;

Brazil: Electricity Distribution

\$ m ( ) Inc e S R tat t om em en	1Q 15	1Q 14	∆ %	bs. ∆ A
fit Gr Pr oss o	42 5	30 5	% 39	+1 20
lies d s ice Su pp an erv s el c nd loy be fits Pe ost rso nn s a em p ee ne he (ne ) Ot ing rat sts t r o pe co ( ) Ne t O ing Co 1 rat sts pe	86 70 37 19 3	80 64 19 16 3	8% 9% 92 % 18 %	+6 +6 +1 8 +3 0
EB ITD A	23 2	14 2	64 %	+9 0
Pro vis ion s nd Am isa tio im irm ort t n a pa en	8 46	3 47	16 5% -2%	+5 -1
EB IT	17 9	92	94 %	+8 6

fit rfo Gr Pr Pe oss o rm an ce	1Q 15	1Q 14	∆ %	bs. ∆ A

\$ m fit ( ) Gr Pr R oss o lat ed Re	42 5	30 5	39 %	+1 20
gu re ve nu es Ch ble in cei	42 5	32 2	32 %	+1 03
an ge reg . re va s	-	( ) 17	-	-
\$ m lat cei b les ( ) Re Re R gu ory va
inn ing f p eri od Be g o	60 2	19 9	20 3%	+4 03
t d Pas iat ion ev s	( ) 82	( ) 16	42 9%	-66
al d ( ) An iat ion 2 nu ev	22 3	44 7	-50 %	-22 3
/ ( ) CD E AC R A 3 t cco un	( ) 18 2	( ) 41 4	% -56	+2 32
d o f p eri od En	56 1	21 6	16 0%	+3 45

lie ed ( h ) C Co nts ect t nn	3, 18 2	3, 07 6	3%	+1 05
nd Ba eir ant e	1, 74 0	1, 68 3	3%	+5 6
els Esc a	2 1, 44	39 3 1,	4%	9 +4

Ele icit Dis tri bu ted ( h ) GW ctr y	6, 76 4	6, 72 6	1%	+3 8
nd Ba eir ant e	3, 77 5	3, 92 3	-4%	-14 8
els Esc a	2, 98 9	2, 80 3	7%	+1 86
wh ich Fro m :
cli ark ( h ) To in Fre e M GW ts et en	2, 44 5	2, 50 2	-2%	-57

( ) Ele icit So ld GW h ctr y nd eir Ba te	4, 32 0	4, 22 4	2%	+9 5
an sid . & he Re Co Ot	2, 38 1	2, 42 5	-2%	-44
mm erc r ., Ind l ria	1, 80 3	1, 81 9	-1%	-16
ust lsa Esc	57 8	60 6	-5%	-28
e Re sid Co . & Ot he	1, 93 9	1, 79 9	8%	+1 40
mm erc r ., Ind l	1, 65 9	1, 50 5	% 10	+1 55
ria ust	27 9	29 5	-5%	-15
x & rfo Ca Op Pe pe ex rm an ce	1Q 15	1Q 14	∆ %	bs. ∆ A

lla b le O ( ) Co ing Co 4 ntr rat sts o pe	0 15	13 7	10 %	3 +1
\$ /c ( /c ) Co lien lien nt. sts t R t co	47	44	6%	+3
/ \$ / km ( ) Co R Km nt. sts co	2	2	9%	+0
loy ( ) Em # p ee s	2, 14 7	2, 22 6	-4%	-79
\$m (ne f s bsi die ) ( ) Ca R t o pe x u s	55	72	-24 %	-17

Network ('000 Km)

EBITDA from our electricity distribution activity in Brazil went up 64% YoY (+R\$90m) to R\$232m in 1Q15, reflecting: i) higher electricity gross profit (+R\$120m YoY), driven by higher regulated revenues, mostly due to the annual tariff readjustments at both our DisCos; and ii) higher operating costs (up R\$30m YoY) essentially reflecting an increase in losses on fixed assets and higher provisions for doubtful clients.

Ending 2014, ^a change in the legal framework allowed for the recognition of regulatory receivables at gross profit level. As such, 1Q15gross profit is no longer impacted by the change in regulatory receivables, reflecting the period's regulated revenues. Regulatedrevenues went up 32% YoY (+R\$103m) to R\$425m in 1Q15, mostly reflecting the annual tariff readjustments at both Escelsa (+26.54% in Aug-14) and Bandeirante (+22.34% in Oct-14). Regulated revenues also benefitted from: i) the so-called "tariff flags", ^a mechanism introduced in Jan-15 so as to signal consumers for higher electricity costs (Jan/Feb-15: red flag of R\$3 per 100kWh; Mar-15: red flag of R\$5.5 per ¹⁰⁰ kWh); and ii) ANEEL's approval of extraordinary tariff increases at both our DisCos as from March ²nd, ²⁰¹⁵ (Escelsa: +33.27% and Bandeirante: +32.18%).

As of Mar-15, regulatory receivables amounted to R\$561m (vs. R\$602m as of Dec-14). In 1Q15, ^a R\$223m negative tariff deviationwas created, essentially related to higher energy costs than the ones incorporated in the tariffs, which was partly compensated by R\$182m of contributions from CCEE (ACR account) regarding Nov/Dec-14 shortfall; also, R\$82m were received regarding past deviations. All in all, regulatory receivables went down R\$40m vs. Dez-14, to R\$561m as of Mar-15, to be collected through tariffs inthe following years. Regulatory-wise, return on regulated asset base is currently set at 7.5% (after taxes) and next regulatory reviews are due in Oct-15 for Bandeirate and Aug-16 for Escelsa. In Feb-15, the Brazilian regulator (ANEEL) proposed ^a real post-tax WACC of 8.09% to be applied to distribution on the upcoming ⁴th revision cycle.

Volumes of electricity sold went up 2% YoY in 1Q15, translating ^a 4% increase in the 'residential, commercial & other' segments, justified by ^a wider client base and by ^a warm weather in 1Q15 in the Espírito Santo region. Volumes sold to the industrial segment decreased 5% YoY, reflecting lower industrial activity as well as lower consumption from the non-metallic minerals and chemical sectors. At the same time, volumes distributed to industrial clients in the free market went down 2% YoY to 2.4TWh in 1Q15, reflecting the cooling of the industrial production in the São Paulo region.

Controllable operating costs increased 10% YoY to R\$150m in 1Q15, driven by an 8% increase in personnel costs, reflecting the annual salary update (+7.4%), higher indemnities and lower headcount. Supplies and services reflect higher expenses with O&M, IT and clients' services. Other operating costs went up R\$18m YoY, translating higher losses on fixed assets and higher provisions for doubtful clients. Distribution capex went down 24% YoY to R\$55m in 1Q15, essentially due to market retraction. On ^a recurring basis, distribution capex is mostly devoted to customer services activities and to the reinforcement of the network quality of service.

In ²⁰¹⁴ electricity sector DisCos faced record highs of electricity purchases costs mostly given involuntary short contracting positions in high market prices environment due to low rainfall and high thermal dispatch. In Apr-14, the CCEE created an account called"Conta-ACR" (Conta no Ambiente de Contratação Regulada) to help compensate DisCos for higher costs incurred – R\$21bn of financing were transferred to DisCos. ANEEL has also been passing-through some of these additional costs to consumers through the annual tariff readjustments. In 2015, other measures were implemented. In Jan-15, ^a "tariff flags" mechanism, or variable tariff, was introduced to signal consumers for higher energy costs – in Jan/Feb-15, the "red flag" was triggered, meaning +R\$3 per 100kWh andin Mar-15, this "red flag", triggered once again, was increased to +R\$5.5 per 100kWh (~+12% increase in tariffs for Low Voltage). Also, in Feb-15, ANEEL approved several extraordinary tariff increases applicable from March ²nd, ²⁰¹⁵ onwards (Escelsa: +33.27% andBandeirante: +32.18%). Additionally, for 2015, DisCos were able to reduce their involuntary short contracting positions mostly throughthe A-1 auction held in Dec-14 (Bandeirante: 107% in 1Q15 vs. 97% in 1Q14 and Escelsa: 94% in 1Q15 vs. 82% in 1Q14), which shall reduce the impact on energy costs from law rainfall and high market prices environment.

(1) Net operating costs = operating costs (Supplies and services + Personnel costs + Costs with social benefits) + Other operating costs (net); (2) Net of extraordinary tariff increase and tariff flags impacts; (3) Including financial update of the corresponding regulatory assets/liabilities; (4) S&S and Personnel costs.

\$ ( ) Inc e S R M tat t om em en		Ge rat ne	ion
	1Q 15	1Q 14	∆ %	bs. ∆ A
fit Gr Pr oss o	20 4	27 3	-26 %	-70
lies d s Su ice pp an erv s el c nd loy be fits Pe ost rso nn s a em p ee ne (ne ) Ot he ing rat sts t r o pe co t O ing Ne Co rat sts pe	12 12 0 25	18 13 0 31	-31 % -4% - -19 %	-5 +0 -6
EB ITD A	17 9	24 3	-26 %	-64
Pro vis ion s isa tio nd im irm Am ort t n a pa en	0 41	0 38	% -90 8%	-0 +3
EB IT	13 8	20 5	-33 %	-67

ly Su pp	1Q 15	1Q 14	∆ %	bs. ∆ A

EB ITD A	17 9	24 3	-26 %	-64
		68		-26
( ) Pe ixe An ica l 60 % o ed by ED PB g wn ( ) Ot he 10 0% r	65 42	82	% -20 -39 %	-16
do ( ed by ) Laj 73 % o ED PB ea wn	72	93	-23 %	-21
\$ m kd ( ) EB ITD A B R rea ow n	1Q 15	1Q 14	∆ %	bs. ∆ A

( ) Em loy # p ee s	27 8	40 2	-31 %	-12 4
\$ m ( ) Ca R pe x \$ m Fin cia l In ( ) R stm ts an ve en	11 30	12 6	-14 % -	-2 +2 4
\$ ( / ) ( ) Av Hy dro A S le Pri MW h 2 PP R g. a ce	17 6	16 1	9%	+1 4
he Ot r	60	77	-22 %	-17
Ele icit ld ( h ) So GW ctr y ed PPA ntr act co	2, 26 0 2, 20 0	2, 21 7 2, 14 0	2% 3%	+4 3 +6 0
( ) Ins Ca city MW Eq pa y				87
tal led uit	54 7	7 36 0	52 %	+1
tal led ( ) Ins Ca city MW pa	1, 79 7	1, 79	-	-
PPA ed & O the ntr act co re ve nu es r F im (ne f h ed ing ) GS t t o pac g	36 9 ( ) 16 5	29 3 ( ) 19	% 26 -76 2%	+7 6 -14 6
\$ m fit ( ) Gr Pr R oss o	20 4	27 3	-26 %	-70
Ke Da ta y	1Q 15	1Q 14	∆ %	bs. ∆ A

EB IT	13 8	20 5	-33 %	-67
Pro vis ion s nd Am isa tio im irm ort t n a pa en	0 41	0 38	-90 % 8%	-0 +3
EB ITD A	17 9	24 3	% -26	-64
(ne ) Ot ing rat sts t r o pe co Ne t O ing Co rat sts pe	0 25	0 31	- -19 %	+0 -6
he	12	13	-4%	-1

( \$ m ) kd EB ITD A B R rea ow n	1Q 15	1Q 14	∆ %	bs. ∆ A
do ( ed by ) Laj 73 % o ED PB ea wn l ( ed by ) Pe ixe An ica 60 % o ED PB g wn he ( ) Ot 10 0% r	72 65 42	93 82 68	-23 % -20 % -39 %	-21 -16 -26
EB ITD A	17 9	24 3	-26 %	-64

ly Su pp	1Q 15	1Q 14	∆ %	bs. ∆ A
\$ m fit ( ) Gr R oss pr o	33	51	-36 %	-18
\$ m ( ) ( ) Ne t O ing 1 R rat sts pe co	1	0	1% 57	+0
( \$ m ) EB ITD A R	32	51	-37 %	-19
Ele icit les ( h ) GW ctr y s a	2, 51 4	3, 45 8	-27 %	-94 4

EBITDA from our electricity generation activities in Brazil went down 26% YoY (-R\$64m) to R\$179m in 1Q15, reflecting: i) lowGSF (79% in 1Q15), and the subsequent need to purchase energy at high market prices; which was mitigated by ii) ^a seasonal allocation of volumes sold, with ^a significant portion of volumes allocated to the 1Q15 (29%); and by iii) lower operating costs, on the back of lower O&M expenses.

Gross profit fell 26% YoY (-R\$70m) to R\$204m in 1Q15 on the back of low Generation Scaling Factor (GSF), which stood at 79% in 1Q15 (vs. 96% in 1Q14 and 88% in 4Q14). In periods of low rainfall, the associated generation deficit implies that hydrogenerators have to purchase energy at market prices to meet their PPA obligations. Although market prices went downsignificantly (avg. PLD: R\$388/MWh(3) in 1Q15 vs. R\$647/MWh(3) in 1Q14), the poor hydro environment that shaped the 1Q15, coupled with low reservoir levels to begin with, resulted in ^a particularly low GSF. EDPB was able to mitigate the negative impact of low GSF through short-term sales contracted at higher prices; nonetheless, all together, this translated into +R\$146mYoY of additional costs with energy purchases (R\$165m in 1Q15 vs. R\$19m in 1Q14). Excluding the impact from low GSF (net of hedging), gross profit went up R\$76m YoY, reflecting higher volumes of electricity sold at higher prices. It is worth mentioning that Peixe Angical hydro power plant PPA (current avg. price @ R\$206/MWh) ends in Jan-16, which should help reduce EDPBnegative exposure to any low GSF impact that might still occur in 2016.

Electricity volumes sold increased 2% YoY to 2.3TWh in 1Q15 reflecting the seasonal allocation of volumes – given the adverse hydro environment, and to maintain some protection against exposure to market prices, ^a significant portion of the volumes of electricity to be sold was allocated to the 1Q, in an even higher proportion than in 1Q14 (29% in 1Q15 vs. 27% in 1Q14). Average selling price went up 9% YoY, translating PPA prices inflation updates as well as short-term contracts closed at higher prices.

EDPB operates 2.3GW of capacity, of which 0.5GW are equity consolidated. Equity consolidated capacity refers to: i) ^a ⁵⁰%equity stake in Pecém ^I coal facility (720MW in partnership with Eneva); and ii) ^a 50% equity stake in Santo António do Jari hydro power plant (373MW in partnership with CTG). In Dec-14, in light of Eneva's financially distressed situation, EDPB agreedthe purchase of Eneva's 50% stake in Pecém ^I for ^a total amount of R\$300m (closing expected for 2Q15). Pecém ^I EBITDA is currently estimated at ~R\$280m for 2015E (full year contribution @100%) and Net Debt is forecasted at ~R\$2bn as of Dec-15E. Following-up to the repair of one of the generating units (in 4Q14), both groups at Pecém ^I are now working at full speed – availability factor reached 96% in 1Q15. In 1Q15, Pecém ^I EBITDA (@50%) totalled R\$46m and net loss attributable to EDPBwas R\$26m, mostly due to higher net financial costs. Santo Antonio do Jari is fully operational since Dec-14. In 1Q15, Jari contributed with ^a net loss of R\$12m (@50%), reflecting the negative impact of low GSF.

Capex fell 14% YoY to R\$11m in 1Q15. Note that investments devoted to Cachoeira Caldeirão and São Manoel hydro projects are classified as 'financial Investments' (equity-method accounted); in 1Q15, financial Investments totalled R\$30m, which were essentially devoted to Cachoeira Caldeirão construction works. In terms of new capacity, EDPB participates in ² ne whydro projects, both under long-term PPAs: i) Cachoeira Caldeirão, ^a 219MW project 50%-owned by EDPB (in partnership withCTG) and due in Jan-17 (80% concluded); and ii) São Manoel, ^a 700MW project, 33.3%-owned by EDPB (in partnership withCTG and Furnas) – this project is in early stage of construction and should start operations in May-18.

Electricity supply gross profit decreased 36% YoY (-R\$18m) to R\$33m in 1Q15, reflecting lower volumes supplied to clients and an exceptionally strong 1Q14, which benefitted from higher spot prices and higher price volatility.

Income Statements& Annex

1 Q 1 5 ( ) €m	Lon Ter g- m ed Co ntr act Ge atio ner n	Ibe rian Lib lise d era Act ivit ies	ula ted Reg Net rks Ibe ria wo	váv eis ED P R eno	zil Bra	. & Adj Co r. A ctiv rpo ust nts me	ED P G rou p
Gr fit Pr oss o	18 6	23 3	43 1	37 5	20 5	( ) 6	1, 42 3
lies d s Su ice pp an erv s el c Pe ost rso nn s ith l be fits Co cia sts w so ne (ne ) Ot he ing rat sts t r o pe co Op tin ost era s g c	14 16 0 2 33	48 17 2 59 12 6	86 32 5 ( ) 16 10 7	65 15 2 ( ) 26 56	36 27 2 11 76	( ) 41 39 3 8 8	20 7 14 5 15 38 40 6
EB ITD A	15 3	10 7	32 4	31 9	12 9	( ) 15	1, 01 7
Pro vis ion s ( ) isa tio nd im irm Am ort t 1 n a pa en	0 39	( ) 1 50	0 82	- 124	2 28	( 0 ) 15	1 33 7
EB IT	114	59	24 2	19 5	99	( ) 29	68 0

1 Q 1 4 ( ) €m	Lon Ter g- m ed Co ntr act Ge atio ner n	Ibe rian Lib lise d era ivit ies Act	ula ted Reg rks Ibe Net ria wo	váv ED P R eis eno	zil Bra	Co r. A ctiv . & rpo Adj ust nts me	ED P G rou p
Gr fit Pr oss o	20 7	29 1	44 1	34 5	194	6	1, 48 3
lies d s Su ice pp an erv s el c Pe ost rso nn s fits Co ith cia l be sts w so ne (ne ) Ot he ing rat sts t r o pe co tin Op ost era g c s	13 17 0 2 32	47 16 1 35 98	93 38 5 59 19 6	59 16 2 ( ) 21 56	34 24 3 6 68	( ) 44 40 2 5 4	20 2 15 1 13 86 45 3
EB ITD A	17 6	19 2	24 5	28 9	12 7	2	1, 03 0
Pro vis ion s isa tio nd im irm ( ) Am 1 ort t n a pa en	5 39	1 49	( ) 1 83	- 11 0	1 27	0 16	7 32 4
EB IT	13 2	14 2	16 3	17 9	98	( ) 14	69 9

ly ( ) Qu P& L € m art er	1Q 14	2Q 14	3Q 14	4Q 14	1Q 15	2Q 15	3Q 15	∆ Y oY %	∆ Q oQ %
fro les he Re d s ice nd ot ve nu es m en erg y s a an erv s a r	4, 327	3, 692	3, 804	4, 471	4, 135	-	-	-4% -	-8%
f e les d o he Co st o t ne rgy sa an r	( 2, 844 )	( 2, 476 )	( 2, 624 )	( 2, 982 )	( 2, 712 )	-	-	5% -	9%
fit Gr Pr oss o	1, 483	1, 216	1, 180	1, 488	1, 423	-	-	-4% -	-4%
Su lies d s ice pp an erv s el c nd loy fits Pe Em Be ost rso nn s a p ee ne he (ne ) Ot ing rat sts t r o pe co tin Op ost era g c s	202 164 86 453	220 37 ( 13) 244	221 147 99 467	254 208 100 561	207 161 38 406	- - - -	- - - -	2% - -2% - % -56 - -10 % -	-18 % -23 % % -62 -28 %
EB ITD A	1, 030	972	713	927	1, 017	-	-	-1% -	10%
vis ion Pro s nd ( ) Am isa tio im irm 1 ort t n a pa en	7 324	11 357	4 334	31 383	1 337	- -	- -	-92 % - 4% -	-98 % % -12
EB IT	699	604	376	513	680	-	-	-3% -	32%
Fin cia l Re sul ts an Sh f n fit in j oin d a cia et t v tur tes are o pro en es an sso	( ) 147 12	( 98) ( 4)	( ) 208 17	( ) 118 ( 10)	( ) 208 ( 2)	- -	- -	-42 % - - -	-76 % 83%
fit be for nd Pro e i CE SE ta nco me x a	564	502	184	385	471	-	-	-17 % -	22%
Inc e t om axe s rdi ibu tio n f the Ext ntr ect rao na ry co or en erg y s or	186 15	57 16	33 15	35 16	90 15	- -	- -	-52 % - 5% -	153 % -1%
fit for th od Ne t P eri ro e p fit rib b le t Ne t P Att o E DP uta ro No llin Int tro sts n-c on g ere	364 296 68	430 377 53	136 113	334 254 80	365 297 68	- - -	- - -	0% - 0% - 1% -	9% 17% -15 %
			23

EDP - Installed capacity & electricity generation

	Ins	lle d C ta ap	( aci - M W 1 ty	)	Ele	icit Ge ctr y ne	( ion GW rat	) h			( ) Ele icit Ge ion GW h ctr rat y ne
hn log Te c o y	1Q 15	1Q 14	∆ M W	∆ %	1Q 15	1Q 14	∆ G Wh	∆ %	1Q 14	2Q 14	3Q 14	4Q 14	1Q 15	2Q 15	3Q 15	4Q 15
/ ( ) CM EC l PP A Po rtu ga	4, 47 0	4, 47 0	0	0%	4, 15 1	5, 00 2	-85 1	-17 %	5, 00 2	4, 09 9	3, 62 2	4, 43 7	4, 15 1
dro Hy	3, 29 0	3, 29 0	0	0%	1, 90 3	3, 73 9	-1, 83 6	-49 %	3, 73 9	2, 12 0	1, 07 5	2, 09 7	1, 90 3
ff t he Ru riv n o er	1, 05 6	1, 86 0			93 8	2, 124			1, 61 5	87 9	42 4	81 2	93 8
Re ir ser vo	2, 23 4	2, 23 4			96 5	1, 61 5			2, 124	1, 24 1	65 1	1, 28 5	96
l - S Co ine a s	18 0 1,	18 0 1,	0	0%	2, 24 8	26 3 1,	98 5	78 %	26 3 1,	97 9 1,	2, 6 54	2, 34 0	5 2, 24 8
eci l R im Wi nd Ex-	20 6	27 4	-69	-25 %	22 2	41 4	-19 1	-46 %	41 4	21	11 2	26	22 2
( ) Sp a eg e	18 1	18 1	0	0%	19 0	34 7	-15	-45 %	34 7	2 17 8		0 23 8	19 0
l Po rtu ga							8				82
all- dro Sm Hy	15 7	15 7			13 8	27 8			27 8	12 7	39	18 6	13 8
Co ion rat ge ne	24	24			52	69			69	50	42	52	52
Sp ain	25	93	-69	-73 %	33	67	-34	% -51	67	34	30	21	33
Co ion rat +W ast ge ne e	25	93			33	67			67	34	30	21	33
Lib lise d I be ria era	7, 80 8	7, 77 7	30	0%	4, 70 9	4, 18 6	52 3	12 %	4, 18 6	3, 28 6	3, 74 7	3, 84 4	4, 70 9
dro Hy	2, 45 3	2, 42 2	30	1%	1, 91 0	2, 83 4	-92 5	-33 %	2, 83 4	1, 50 7	74 0	1, 20 1	1, 91 0
l Po rtu ga	2, 02 6	1, 99 6			1, 49 5	2, 39 9			2, 39 9	1, 26 1	67 3	1, 00 1	1, 49 5
Sp ain	42 6	42 6			41 4	43 5			43 5	24 6	67	20 0	41 4
l Co a	1, 46 3	1, 46 3	0	0%	2, 05 8	86 2	1, 19 6	13 9%	86 2	1, 52 1	2, 19 1	1, 84 0	2, 05 8
Ab oñ o I	34 2	34 2			52 4	19 3			19 3	31 7	60 1	56 8	52 4
Ab oñ o I I	53 6	53 6			92 2	59 7			59 7	88 6	99 2	91 1	92 2
ibe Sot o R II	23 9	23 9			19 0	36				11 5	14 8	24 2	19 0
ra ibe	34 6	34 6			42 2	36			36 36	20 3	0 45	9 11	42 2
Sot o R III ra
CC GT	3, 73 6	3, 73 6	0	0%	41 1	15 8	25 3	16 0%	15 8	61	48 0	46 4	41 1
Rib jo ( ) 3 g ate rou ps	1, 17 6	1, 17 6			54	28			28	21	114	66	54
( ) Lar 2 g es rou ps	86 3	86 3			13 6	8			8	3	22 1	46	13 6
ón ( ) Ca j 2 g ste rou ps	84 3	84 3			14 3	66			66	17	10 3	18 2	14 3
( ) Sot o IV & V 2 g rou ps	85 4	85 4			77	56			56	20	43	17 0	77
Nu lea Tri llo c r -	15 6	15 6	0	0%	33 1	33 2	-1	0%	33 2	19 7	33 6	33 9	33 1
Ga soi l - T un es	0	0	0	-	0	0	0	-	0	0	0	0	0
Wi nd ( de tai l o ) Mo 16 re n p age	8, 06 7	7, 71 0	35 7	5%	5, 75 7	6, 10 1	-34 4	-6%	6, 10 1	4, 83 3	3, 38 2	5, 38 0	5, 75 7
Ibe ria	2, 81 6	2, 81 3			2, 00 4	2, 33 0			2, 33 0	1, 53 9	1, 20 3	1, 75 4	2, 00 4
f E Re st o uro pe	36 3 1,	30 1, 7			91 6	79 1			79 1	3 51	43 1	70 1	91 6
rth eri No Am ca	3, 80 5	3, 50 6			2, 79 2	2, 93 0			2, 93 0	2, 72 7	1, 67 8	2, 86 2	2, 79 2
zil Bra	84	84			46	49			49	54	70	63	46
lar So	82	52		57 %		11	18	16 1%		20		14	29
			30		29				11		22
( ) Bra zil Ex- Wi nd	79 1, 7	79 1, 7	0	0%	62 1, 4	2, 34 1	-71 7	-31 %	2, 34 1	65 0 1,	32 2 1,	92 3 1,	62 1, 4
dro Hy	1, 79 7	1, 79 7	0	0%	1, 62 4	2, 34 1	-71 7	-31 %	2, 34 1	1, 65 0	1, 32 2	1, 92 3	1, 62 4
do Laj ea	90 3	90 3			82 7	1, 20 5			1, 20 5	81 4	52 8	84 1	82 7
l Pe ixe An ica g	49 9	49 9			52 2	66 7			66 7	45 8	54 0	72 1	52 2
Ene st rge	39 6	39 6			27 4	46 9			46 9	37 8	25 4	36 1	27 4
TO TA L	22 43 0 ,	22 08 2 ,	34 9	2%	16, 49 2	18, 05 6	-1, 56 3	-9%	18, 05 6	14, 10 0	12, 20 7	15, 85 8	16, 49 2

lid Eq uit Co d ate y nso	Ins 1Q 15	lle d C ta ap 1Q 14	( aci - M W 2 ty ∆ M W	) ∆ %
Ibe al R ( ) ria Sp eci im Ex- Wi nd eg e	46	50	-4	-8%
Wi nd ED PR	88 6	81 7	69	8%
zil dro Bra Hy	18 7	0	18 7
zil al Bra Co	36 0	36		- 0%
		0	0
TO TA L	1, 9 47	1, 22 8	25 2	20 %

(1) Installed capacity that contributed to the revenues in the period. (2) MW attributable to associated companies consolidated by equity method

EDP - Volumes distributed, clients connected and networks

ELE CT RIC ITY					GA S
Ele bu ted ( h ) icit Dis tri GW ctr y	1Q 15	1Q 14	∆ G Wh	∆ %	rib d ( h ) Ga s D ist GW ute
l Po rtu ga	11, 68 7	11, 47 0	21 7	1.9 %	l Po rtu ga
Hig h V olt Ve ry age	53 8	50 8	30	6.0 %	Low Pr ess ure
/ h diu olt Hig Me m V age	5, 11 7	5, 04 0	78	1.5 %	diu Me Pre m ssu re
lta Low Vo ge	6, 03 2	5, 92 3	10 9	1.8 %	LPG
Sp ain	2, 38 1	2, 36 5	16	% 0.7	Sp ain
/ Hig h diu olt Me m V age	1, 73 3	1, 69 8	35	2.1 %	Low Pr ess ure
lta Low Vo ge	64 8	66 8	-20	-2. 9%	diu Me Pre m ssu re
zil Bra	6, 76 4	6, 72 6		0.6 %	TO TA L
lien Fre e C ts	2, 44 5	2, 50 2	38 -57	-2. 3%
Ind ria l ust	85 8	90 0	-43	8% -4.
sid tia l, rcia l & he Re Co Ot en me r	3, 46 2	3, 32 4	13 8	4.2 %
TO TA L	20 83 2 ,	20 56 1 ,	27 1	1.3 %

∆ G Wh	∆ %	1Q 15	1Q 14	∆ G Wh	∆ %

21 7	1.9 %	2, 03 1	1, 97 9	52	2.6 %
30	6.0 %	42 3	37 5	48	12 .9%
78	1.5 %	1, 59 9	1, 59 6	3	0.2 %
10 9	1.8 %	9	9	0	1.1 %
	0.7 %	8, 84 4	13, 55 5	-4, 71 0	-34 .8%
35	2.1 %	3, 97 0	3, 59 7	37 3	10 .4%
-20	-2. 9%	4, 87 4	9, 95 7	-5, 08 3	-51 .0%
38	0.6 %	10, 87 5	53 15, 4	65 9 -4,	-30 .0%

( ) C lie Co ed h nts ect t nn	1Q 15	1Q 14	Ab ∆ s.	∆ %	( ) Su ly Po int h t pp s
l Po rtu ga / / h h diu olt Ve Hig Hig Me m V ry age al L lta Sp eci Vo ow ge	6, 08 2 24 34	6, 07 0 24 34	11 .8 0.2 0.5	0.2 % 1.0 % 1.5 %	l Po rtu ga Low Pr ess ure diu Me Pre m ssu re
lta Low Vo ge	6, 02 4	6, 01 3	.0 11	0.2 %	LPG
Sp ain / h diu olt Hig Me m V age lta Low Vo ge	65 9 1 65 8	65 9 1 65 8	0.1 0.0 0.0	0.0 % 0.9 % 0.0 %	Sp ain Low Pr ess ure diu Me Pre m ssu re
zil Bra nd eir Ba ant e els Esc a	3, 18 2 1, 74 0 1, 44 2	3, 07 6 1, 68 3 1, 39 3	10 5.4 56 .2 49 .2	3.4 % % 3.3 3.5 %	TO TA L
TO TA L	9, 92 2	9, 80 5	11 7.3	1.2 %

ks Ne tw or	1Q 15	1Q 14	Ab ∆ s.	∆ %	ks Ne tw or
( ) ht f t he ks Len tw Km g o ne or	33 3, 29 5	33 1, 64 1	1, 65 4	0.5 %	( ) Len ht f t he ks Km tw g o ne or
l Po rtu ga	22 3, 97 6	22 2, 96 5	1, 01 1	0.5 %	l Po rtu ga
Sp ain	20 30 9 ,	20 19 6 ,	11 3	0.6 %	Sp ain
zil Bra	89 01 0 ,	88 48 0 ,	53 0	0.6 %
( f e ) Los % o lec tri cit dis tri bu ted ses y
l ( ) Po 1 rtu ga	10 .9%	11 .2%	-0. 3 p p
Sp ain	-5. 1%	-5. 0%	-0. 1 p p
zil Bra
nd Ba eir ant e	9.3 %	9.7 %	-0. 3 p p
Te ch nic al	% 5.5	% 5.5	-0. 0 p p
Co rcia l me	% 3.8	% 4.1	-0. 3 p
els Esc a	13 .6%	13 .2%	p 0.4 pp
ch al Te nic	7.9 %	7.6 %	0.3 pp
l Co rcia me	5.7 %	5.6 %	0.1 pp

	Ab ∆ s.	∆ %	1Q 15	1Q 14	Ab ∆ s.	∆ %
	11 .8	0.2 %	32 1.3	30 9.5	11 .8	3.8 %
	0.2	1.0 %	31 5.0	30 2.8	12 .2	4.0 %
	0.5	% 1.5	1.4	1.3	0.1	7.0 %
	11 .0	% 0.2	4.9	5.4	-0. 5	2% -9.
	0.1	0.0 %	93 6.5	1, 01 9.8	-83 .3	-8. 2%
1	0.0	0.9 %	93 5.8	1, 01 9.0	-83 .3	-8. 2%
	0.0	0.0 %	0.7	0.8	-0. 1	-10 .1%
		3.4 %	1, 25 7.8	1, 32 9.3	-71 .5	-5. 4%

1Q 15	1Q 14	Ab ∆ s.	∆ %
12, 82 4	14, 52 1	-1, 69 8	-11 .7%
4, 67 7	4, 51 3	164	3.6 %
8, 14 7	10, 00 8	86 -1, 1	-18 .6%

EDP - Sustainability performance

1Q15 Main Events

Fev - Moody's upgrades EDP's ratings to "Baa3"/"Prime-3" with stable outlook.

Fev - EDP wins ¹st place at "Excellence at Work Awards 2014" in large company category, according to ^a study held by Heidrick & Struggles, Diário Económico and INDEG-IUL.

Fev – EDP Renováveis is awarded at Euronext Lisbon Awards 2015, as the company with the best stock market performance in 2014, with ^a rise of 40% in its market capitalization.

Mar - EDP was distinguished by Institutional Investor Magazine. António Mexia was electedEurope's best CEO of the Utilities sector by Buy Side analysts. Nuno Alves, EDP's CFO and Miguel Viana, Investor Relations Officer, were also recognized by "Institutional Investor Magazine". Inthe overall evaluation of listed European companies of all sectors, EDP climbed ⁷¹ positions compared to the previous year, and now ranks ²⁰th place.

Mar – For the fourth year running, EDP ranks among the "The World's Most Ethical Companies", by Ethisphere Institute.

l M (a ) Env iro ics ta etr nm en	1Q 15	1Q 14	∆ %
( ) Ab lut e A he ric iss ion kt tm Em so osp s				CO 2 E mi ssi
(e ) CO 2	84 4, 5	2, 72 5	78 %	on s
NO x	5.0	2.0	15 1%
SO 2	4.6	1.6	19 9%
le Pa rtic	0.2 32	0.0 71	22 6%
				/ PP A CM EC
(g / ) Sp eci fic he ric iss ion h At Em KW mo sp s				Co al
(e ) CO 2	29 5.8	15 1.6	95 %	l O il & al G Fue Na tur as
NO x	0.3 1	0.1 1	17 5%
SO 2	0.2 8	0.0 9	22 8%	Lib lise d era
				al Co
( ) GH G e mi ssi ktC O2 on s eq				CC GT
Dir iss ion (sc ) Em e 1 ect s op	85 4, 5	2, 73 0	78 %
Ind (sc ) ire mi ssi e 2 ct e on s op	54 4	60 1	-9%	eci l R im Sp a eg e
( ) ( f ) Pri En Co tio TJ ma ry erg y nsu mp n	47 68 2 ,	25 87 2 ,	84 %	Th l G tio erm a en era n
( ) Ne t C ifie d C aci % Ma ert ty x. ap	96 %	% 77	19 p.p
( ) Wa Us 10 3 m 3 ter e	43 1, 84 6	35 2, 10 0	23 %	ion CO 2 F Ge rat ree ne
l W ( ) To ta ast t e	95 60 8 ,	59 53 6 ,	61 %	CO 2 E mi ssi on s
( ) iro l In nd € t h Env ta stm t a nm en ve en ex pe nse s	22 14 7 ,	65 6 17,	25 %
iro l Fe d P ltie ( ) Env € ta nm en es an en a s	77 8	34 99 9 ,	-98 %

	14
98	10 7	-9%	Dir ly Ge ed ect rat ne
88 33 %	11 5 33 %	-23 %	Dis tri bu ted lat ed Ac cu mu

l Su bi ED P I ina nte sta rna	lity de ( ba In x se	) 20 10 -12		Eco mi c M no	ics etr	1Q 15	1Q 14	∆ %
	1Q 15	1Q 14	∆ %	mi c V Eco no a	( ) ( ) lue €m 1
ina b. Ind (a ) Su sta ex	98	10 7	-9%	ly Dir Ge ect ne	ed rat	4, 56 1	4, 64 0	-2%
tal Env iro nm en ht %W eig	88 33 %	11 5 33 %	-23 %	bu ted Dis tri lat ed Ac cu mu		3, 86 5 69 6	3, 81 9 82 0	1% -15 %
mi Eco no c	10 5	98	7%	cia l M ics So etr	(a )	1Q 15	1Q 14	∆ %
ht %W eig	37 %	37 %		loy (c Em p ee s	)	11, 63 2	12, 04 7	-3%
l ( b ) So cia %W eig ht	10 0 30 %	11 1 30 %	-10 %	( ini ho Tra ng	) urs	74 86 6 ,	78 56 4 ,	-5%
Th is S ain ab ilit Ind ust y ex 3 3 s ain ab ilit ust on y p er	s d lop ed wa eve for in dic ma nce	by ED P a nd ato rs.	is bas ed	-du cid On Ac ty Sev eri Rat ty e Fre rat qu en cy Fre e E DP rat q.	ts en ( ) Tg ( Tf ) e ( Tf ) ( d ) +E SP	9 82 1.7 2.9	7 98 1.2 3.2	29 % -16 % 38 % % -11

	Ab lut so e ( ktC ) O2		eci fic Sp / ( h ) MW t		ion Ge rat ne ( h ) GW		(g )
	1Q 15	1Q	14	1Q 15	1Q 14	1Q	15	1Q 14
	99 1,	7	22 3 1,	0.8 9	0.9 7		2, 24 8	26 3 1,
	1, 99	7 -	1, 22 3 -	0.8 9 -	0.9 7 -		2, 24 8 -	1, 26 3 -

1Q 15	1Q 14	∆ %	l M (a ) Env iro ics - C O2 Em iss ion ta etr nm en s
4, 84 5 5.0	2, 72 5	78 %	mi ssi CO 2 E on s	Ab lut so ( ktC O2	e )	eci Sp / ( MW t	fic h )	Ge rat ne ( h GW	ion (g ) )
4.6 0.2 32	2.0 1.6 0.0 71	15 1% 19 9% 6% 22		1Q 15	1Q 14	1Q 15	1Q 14	1Q 15	1Q 14
			/ CM EC PP A al Co	1, 99 7 1, 99 7	1, 22 3 1, 22 3	0.8 9 0.8 9	0.9 7 0.9 7	2, 24 8 2, 24 8	1, 26 3 1, 26 3
29 5.8 0.3 1	15 1.6 0.1 1	95 % 17 5%	l O il & al G Fue Na tur as	-	-	-	-	-	-
0.2 8	0.0 9	22 8%	Co al	2, 76 0 2, 57 8	33 6 1, 1, 25 9	2 1.1 1.2 5	1.3 1 1.4 6	2, 46 9 2, 05 8	02 0 1, 86 2
4, 85 5	2, 73 0	78 %	CC GT	18 2	77	0.4 4	0.4 9	41 1	15 8
54 4	60 1	-9%		88	16 6	0.2 9	0.4 0	30 9	41 4
47 68 2 ,	25 87 2 ,	84 %		84 4, 5	2, 72 5	0.9 6	1.0 1	02 6 5,	2, 69 7
% 96	% 77	19 p.p	ion CO 2 F Ge rat ree ne					11, 36 0	15, 27 5
43 1, 84 6	35 2, 10 0	23 %
95 60 8 ,	59 53 6 ,	% 61	CO 2 E mi ssi on s			0.3 0	0.1 5	16, 38 6	17, 97 3

(a) Excludes Pecém;

(b) 1Q14 figures were revised to the number of fatal accidents envolving non workers;

(d) ESP: External Services Provider.

(e) Excluding vehicle fleet and natural gas consumption and losses.

(f) Including vehicle fleet.

(g) Includes heat generation (1Q14: 278 GWh vs 1Q15: 225 GWh).

(1) Generated Economic Value (GEV): Turnover + Share of net profit in joint ventures and associates + Other operating income + Financial IncomeDistributed Economic Value (DEV): Cost of energy sales and other + Operating costs + Other operating expenses + Financial expenses + Current Income tax + Div. payments Accumulated Economic Value: GEV – DEV.

EDP Share Performance

2014

02-03-2015

52W

YTD

13-Apr:Qatar notifies intra-group transaction on qualified shareholding in EDP

13-Apr: Blackrock notifies qualified shareholding in EDP

16-Apr:EDP issues €750 million bond maturing in April 2025

21-Apr:EDP'S Annual General Shareholders Meeting

24-Apr: Blackrock notifies qualified shareholding in EDP

Clo se	3.4 66	3.4 66	3.2 18
Ma x	3.7 49	3.7 49	3.7 49
Mi n	3.0 73	3.0 36	2.6 20
Av era ge	3.4 45	3.4 26	3.2 86
P's Liq uid ity in Lis bo ED Eu ext ron n
( ) Tu € m rno ve r	2, 34 4	5, 44 8	4, 89 6
ily ( ) Av Da Tu € m era ge rno ve r	26	21	19
olu (m illio ha ) Tra de d V me n s res	68 0	59 0 1,	49 0 1,
(m ) Av ily Vo lum illio ha Da g. e n s res	7.6	6.1	5.7



ha ED P S Da ta re	1Q 15	1Q 14	∆ %

mb f sh d (m illio ) Nu s Is er o are sue n	3, 65 6.5	3, 65 6.5	-

ha ED P S Da ta re	1Q 15	1Q 14	∆ %	ón ia P im ão S p Elis ab Fe ira ete rre
mb f sh d (m illio ) Nu s Is er o are sue n (m ) Tre ck illio sto asu ry n	3, 65 6.5 22 .7	25 .8	-12 .0%	ach ad Joã o M o Ma ria Jo ão M ati as élia No Ro cha

Investor Relations DepartmentMiguel Viana, Head of IRSónia PimpãoJoão Machado

Phone: +351-21-001-2834Email: [email protected]: www.edp.pt

EDP Stock Market Performance

EDP Share Price (Euronext Lisbon - €)

AI assistant

EDP-Energias Earnings Release 2015

1909_iss_2015-05-07_301376d1-8021-4b59-b78f-966a0ce55c1b.pdf

1Q15

Financial Results

Conference call and webcast

Content

Main Highlights

EBITDA Breakdown

Profit & Loss Items below EBITDA

Capital Expenditure & Net Investments

FFO & Cash Flow Statement

Consolidated Net Financial Debt

Business Areas

Iberian Electricity and Gas Markets

LT Contracted Generation in Iberian Market: PPA/CMEC & Special Regime

Explanatory note on PPA/CMEC:

Liberalised Electricity Generation in the Iberian Market

Liberalised Electricity and Gas Supply in the Iberian Market

Energy Supply in Spain

Energy Supply in Portugal

EDP Renováveis: Financial Performance

EDP Renováveis: Rest of Europe

Regulated Networks & Regulatory Receivables in Iberia

Electricity Distribution and Last Resort Supply in Portugal

Electricity and Gas Networks in Spain and Gas Networks in Portugal

ELECTRICITY DISTRIBUTION IN SPAIN

GAS REGULATED NETWORKS IN SPAIN

GAS REGULATED ACTIVITIES IN PORTUGAL

EDP - Energias do Brasil: Financial Performance

Brazil: Electricity Distribution

Income Statements& Annex

EDP - Installed capacity & electricity generation

EDP - Volumes distributed, clients connected and networks

EDP - Sustainability performance

1Q15 Main Events

EDP Share Performance

AI assistant

EDP-Energias — Earnings Release 2015

1909_iss_2015-05-07_301376d1-8021-4b59-b78f-966a0ce55c1b.pdf

1Q15

Financial Results

Conference call and webcast

Content

Main Highlights

EBITDA Breakdown

Profit & Loss Items below EBITDA

Capital Expenditure & Net Investments

FFO & Cash Flow Statement

Consolidated Net Financial Debt

Business Areas

Iberian Electricity and Gas Markets

LT Contracted Generation in Iberian Market: PPA/CMEC & Special Regime

Explanatory note on PPA/CMEC:

Liberalised Electricity Generation in the Iberian Market

Liberalised Electricity and Gas Supply in the Iberian Market

Energy Supply in Spain

Energy Supply in Portugal

EDP Renováveis: Financial Performance

EDP Renováveis: Rest of Europe

Regulated Networks & Regulatory Receivables in Iberia

Electricity Distribution and Last Resort Supply in Portugal

Electricity and Gas Networks in Spain and Gas Networks in Portugal

ELECTRICITY DISTRIBUTION IN SPAIN

GAS REGULATED NETWORKS IN SPAIN

GAS REGULATED ACTIVITIES IN PORTUGAL

EDP - Energias do Brasil: Financial Performance

Brazil: Electricity Distribution

Income Statements& Annex

EDP - Installed capacity & electricity generation

EDP - Volumes distributed, clients connected and networks

EDP - Sustainability performance

1Q15 Main Events

EDP Share Performance

More from EDP-Energias

EDP-Energias Earnings Release 2015