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May 20, 2013

May 20, 2013

RESUMING OF COVERAGE

A nice mix of short and long term triggersWe resume coverage on OMV Petrom , which is one of our favourites in termsof valuation, triggers, financial standing and corporate governance, with a Buy

rating and a 12M TP of RON 0.52/share . Petrom currently trades at unwarranted45-48% discounts to it s peers, and we believe that the stocks low liquidity could

justify only part of this discount. Petrom currently enjoys two main triggers, ofwhich only one is near to midterm and one is for the longer run, however bothmaking the story worth watching. First is the natgas prices liberalization, with allits positive implications, second is the potential large discovery from the BlackSea. Petrom will most likely see a major increase in royalties starting 2015, butuntil then it can capture a material part of the natgas price increases resultingfrom the liberalization process.

Natgas price liberalization and taxation are the game changers :liberalization now has a timetable and first two steps have already been madetowards a full convergence, by 2014 for industrial consumers and 2019 for

households. February brought a windfall tax for the natgas producers, butwas more benign than most of us feared. We asses that Petrom will retainsome 43-45% of the additional revenues in 2014.

Major off-shore upside, with benefits for both long and short run .Expected to materialize in t he next decade, but enhances already Petromsnegotiation power. In a recent update on the Neptun Block, following the pre-appraisal evaluation of Domino-1 well, Petrom spoke of an initial estimate ofpotential gas production of approx. 630 mn cf/d. This would exceed Petromscurrent natgas production by some 20%.

Constantly strong financial performance over the past five years, decentdividend play . Petrom is a decent dividend play this year with a 6.1% yield

(at announcement), and a RON 0.028 gross DPS (-9.7% yoy), after reportinganother record high net profit in 2012. Its guidance for 2013 encourages us toexpect another top financial performance.

Main shortcoming is the low stock liquidity . It seems that the State iscurrently not considering the re-launch of Petrom SPO, therefore we view asa positive the 1.12% stake sale out of FPs holding in Petrom, done at RON0.39/share, although the deal size is not as impressive as we hoped.

Very undemanding valuation . Petrom is attractively priced at 5.6x-5.1x P/Eand 3.3x-2.9x EV/EBITDA on our 2013E-2014E assumptions, trading at stillwide discounts to CEE peers of 40-54% (45-48% adjusted for outliers).

2011 2012 2013E 2014E 2015E

Sales (RON mn) 22,614 26,258 21,833 23,929 22,981EBITDA (RON mn) 7,766 8,514 8,151 8,792 7,742

EBIT (RON mn) 4,936 5,662 5,186 5,677 4,524

Net income (RON mn)* 3,757 3,953 4,182 4,558 3,689

EPS reported (RON) 0.066 0.070 0.074 0.080 0.065

DPS (RON) 0.031 0.028 0.022 0.024 0.020

ROCE (%) 13.7 14.6 12.7 12.9 9.8

P/E (x) 5.4 5.5 5.6 5.1 6.3

P/CF (x) 3.3 3.1 3.7 3.4 3.8

P/BV (x) 1.0 0.9 0.9 0.8 0.7

EV/EBITDA (x) 2.9 2.8 3.3 2.9 3.3

EV/DACF (x) 3.8 3.3 4.4 3.9 4.3

Net gearing (%) 11.4 8.6 13.7 8.7 6.7

Dividend yield (%) 8.7 7.9 5.4 5.9 4.8* attributable to shareholders Source: OMV Petrom, SSIF Broker estimatesNB: Historical multiples based on avg. prices

Oil & gas / Romania Resuming of coverage

OMV Petrom Buy

12M target price (RON) 0.52

Current price (17 May) (RON) 0.4105

Potential upside (%) 26.7

Key data

Bloomberg ticker SNP ROReuters ticker SNPP.BXMCap (EUR mn) 5,358.3Free float (%) 7.73Shares outstanding (bn) 56.6

Average daily vols. (EUR mn) 255.5

Shareholders %OMV AG 51.01Ministry of Economy 20.64Fondul Proprietatea 18.99EBRD 1.62Free-float 7.73

Upcoming events1H13 OMV trading statement 24 Jul 20131H13 financial result 13 Aug 20133Q13 OMV trading statement 18 Oct 20133Q13 financial results 7 Nov 2013

SNP RO share price performance

* Rebased chart

Analyst:Carmen Ars ene , CFA

+40 364 260 [email protected]

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BROKER DAILY BRIEF February 13, 2013

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Highlights on the investment case

Legislative changes mayhave limited impact on

profitability in 2013

but could be more materialin 2014 and going forward,

provided they remain in place

However, we expect the newtaxes to be replaced with ahigher royalty

We resume coverage on OMV Petrom, which is one of our favourites in terms of valuation, story,managements abilities and corporate governance, with a Buy rating and a 12M TP of RON

0.52/share. Petrom currently trades at unwarranted 45-48% discounts to its peers, and we believethat the stocks low liquidity could justify them only partly. Our assumptions incorporate a 5.8%and 9% EPS growth for 2013 and 2014, respectively. Petrom is a more attractive story these daysthan in the recent past, thanks to its off-shore major upside potential and its near term supportivetaxation regime, expected to allow for a better netback from natgas prices liberalization, higherthan most of the analysts expected for the domestic natgas producers, Petrom and Romgaz.Petrom will most likely see a major increase in royalties starting 2015 (or even earlier), but untilthen it can capture a material part of the natgas price increases resulting from the liberalizationprocess (as long as they happen as scheduled). We see the stock as a great combination of shortand long term triggers and undemanding valuation. It is one of the best in our universe in terms ofcorporate governance, constantly improving financial performance, being at the same time adecent dividend play. Strong crude prices environment is highly supportive for this virtually 100%upstream company. One main shortcoming is the stock s low liquidity. It seems that the State iscurrently not considering the re-launch of Petrom SPO, therefore we view as a positive the 1.12%stake sale of FPs holding in Petrom , although the stake sold is below what FP initially announcedas available for sale and the increase in free-float is not impressive.

Main short and mid-term triggers are about prices liberalization and taxationMain piece of news on Petrom in the beginning of 2013 was about taxation the windfall taxenforced in February was more benign than we would have hoped for, as natgas producers wouldbe allowed to retain a significant stake (we estimate it at around 45% of net earnings in 2014) ofthe liberalization benefitsMost of the market participants expected a neutral effect from prices liberalization, i.e. the benefits ofliberalization to be wiped out by the windfall tax. The Government decided to apply a 60% tax, whichgiven the capex (up to maximum 30% of additional revenues) and approx. 8% royalty deductibility goesdown to 42% at EBIT level, according to our estimates. As for the bottom line impact, we estimate thestake of additional revenues that would remain with the Romanian state at 55 -57%, if we refer to 2014and also account for the 0.5% tax on natural resources (crude in Petroms case) (some 51% w/o the tax).

As detailed below, we estimate that Petrom will register additional revenues of RON 235mn in 2013 andRON 826mn in 2014. Therefore the impact in 2013 is likely to be less material, while for 2014 it alldepends on how much the Government would stick to the liberalization schedule. Our calculationscurrently account for a one year and a half delay in the overall schedule for non-household customers,until mid 2016. In fact, given that the law allows for the prolonging of the liberalization for industrial usersby one year (untill end 2015), our delay is of 6 months, which may prove optimistic. The risk wouldincrease in case Romania will not renew its agreement with the IMF post June this year, given that theliberalization was a main subject in the Governments talks with the IMF.

It is obvious that Petroms negotiation power in its dialogue with the Romanian officials increased, most

likely as a consequence of the potentially major discovery from the Black Sea, which could be a majorstep towards Romanias energy independence . We therefore expect a reasonable position of theRomanian government regarding the increase in royalties to be implemented starting 2015. We accountfor an increase from approx. 8% currently to 20%, which may be overcautious and we note that we seethe risk on the downside. We do not exclude an earlier revision of the royalties, scenario that weassociate with a lower level of royalty, more towards 16%, but we stick to our 20% scenario for now andonly indicate this as a possibility. If to choose between scenarios, we believe Petrom would be better offwith a lower rate even if applied one year earlier.

The potentially sizeableoffshore upside brought amajor change in Petromsnegotiation power in therelationship with Romanianauthorities

Major off-shore upside, with benefits for both long- and short-runThe second majo r Petroms trigger is expected to materialize in the next decade, but enhancesPetroms negotiation power, as it could bring Romanias independence from natgas importsGiven that the potential discovery in the Black Sea (Neptun Block, a 50%/50% JV with Exxon Mobil)might change Romanias energy sector in the next decade, Petrom now has materially more ammunitionin its discussions with the Romanian officials. Recent legislative changes come to confirm our statement

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and we hope to see the confirmation in the royalty negotiations result. Preliminary estimated resources forDomino, the first deep water exploration well drilled in the Neptun Block, are 1.5 3 tcf (42 84 bcm) ofnatgas. Additionally, the pre-appraisal evaluation of Domino-1 well results communicated by Petrom inearly April this year indicate an initial estimate of potential gas production of approx. 630mn cf per day,the equivalent of roughly 6bcm per year, more than its current production (5.3bcm in 2012, at OMVPetrom Group level). Petrom will finalize in 2Q13 a sizeable 3D acquisition and next well drilling isscheduled for end 2013. Conclusion of the appraisal phase of the Neptun block is estimated for 2016.

Exxon/Petrom partnership increased its presence in the Black Sea by acquiring new exploration acreage,via a 85% interest in the Midia Block (transfer agreement was signed in Oct 12 and is subject to thefulfillment of several conditions). It also gave an option to Romgaz, the state-owned domestic natgasproducer to purchase 10% of the participating interest in Midia Deep, which we believe it was a smartmove as it is good to have a state-owned partner in such a venture. Also in the Black Sea, a productionsharing agreement for Skifska block (Ukraine) is currently being negotiated with the UkrainianGovernment. OMV Petrom has a 15% stake in the wining consortium. Current offshore productionaccounts for approximately 17% of the domestic production, produced mainly (70%) in shallow waters.

Current tax regime wouldallow Petrom to capturemore than we have thoughtof the liberalization benefits,but all depends on theliberalization process speed

Natags prices liberalization and taxationLiberalization schedule we currently account for a 6-months delay, which may prove optimisticThere is a liberalization timetable approved by ANRE together with the Romanian Government, providingfor dates and the pace of the process. The intention is to achieve convergence of the industrial end-userprices to a European market level by end 2014 (a one year deadline extension is also taken into account)and of the households prices by end 2018. Industrial users account for roughly 70% in total consumption.Natgas market opening degree was 54.61% as at Dec 12.

TABLE: OFFICIAL NATGAS PRICES LIBERALIZATION SCHEDULEIndustrial consumers Households Weighted average (70% industrial / 30%

households)Convergence

degree %Wellhead

price(RON/MWh)

Well-headprice

increase(%)

End-userprice

increase(%(

Convergencedegree %

Wellheadprice

(RON/MWh)

Well-headprice

increase(%)

End-userprice

increase(%)

RON/MWh

RON/ '000m3

USD/ '000m3

Well-headprice

increase(%)

Dec-12 35 49 7.2 5 33 45.7 0.0 0 48.0 520 155 5.0

Apr-13 40 55.3 12.9 5 33 45.7 0.0 0 52.4 568 169 9.2

Jul-13 47 63.4 38.7 5 36 48.5 6.1 8 58.9 638 191 12.4

Oct-13 51 68.3 7.7 3 37 49.8 2.7 2 62.8 680 203 6.5

2013 49.5 18 9.0 10

Jan-14 55 72 5.4 4 38 50.6 1.6 2 65.6 710 212 4.5

Apr-14 71 89.4 24.2 5 41 51.8 2.4 2 78.1 846 253 19.1

Jul-14 91 109 21.9 5 44 53.3 2.9 3 92.3 1,000 298 18.1

Oct-14 100 119 9.2 4 46 54.6 2.4 3 99.7 1,080 322 8.0

2014 74.2 18 9.6 10

Jan-15 100 119 0.0 0.0 47 56.1 2.7 2 100.1 1,084 324 0.5

Apr-15 119 49 58.9 5.0 3 101.0 1,094 326 0.8

Jul-15 119 52 62 5.3 4 101.9 1,104 329 0.9

Oct-15 119 54 64.1 3.4 3 102.5 1,110 331 0.6

2015 17.4 12Jan-16 119 56 67.1 4.7 3 103.4 1,120 334 0.9

Apr-16 119 60 71.7 6.9 3 104.8 1,135 339 1.3

Jul-16 119 64 76.5 6.7 3 106.3 1,151 343 1.4

Oct-16 119 66 78.5 2.6 3 106.9 1,157 345 0.6

2016 22.5 12

Jan-17 119 69 82 4.5 2 107.9 1,169 349 1.0

Apr-17 119 73 86.9 6.0 2 109.4 1,184 354 1.4

Jul-17 119 78 93 7.0 5 111.2 1,204 359 1.7

Oct-17 119 81 96.5 3.8 3 112.3 1,216 363 0.9

2017 22.9 12

Jan-18 119 83 99.2 2.8 3 113.1 1,224 366 0.7

Apr-18 119 89 106.3 7.2 3 115.2 1,248 372 1.9

Jul-18 119 97 115.1 8.3 3 117.8 1,276 381 2.3

Oct-18 119 100 119 3.4 3 119.0 1,289 385 1.02018 23.3 12 5.0

NB : USD prices calculated using USDRON 3.35 for the entire time horizon Source: ANRE, Petrom, SSIF Broker

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Our base case accounts forthe conclusion of the natgas

price alignment by mid 2016instead of end 2014, but therisk is for further delays

The first step in the liberalization process was made with a delay (Feb 2013 vs. Dec 2012), causedprobably not only by the parliamentary elections that took place last winter, but also by the negotiationsand discussion with the power market regulator and key sector players. In April, ANRE announced that itstuck to the liberalization schedule but it managed to keep end- users price unchanged by modifying theimport/domestic weightings in the natgas basket. However, going forward, we believe that the pressurefrom industrial end-users will become increasingly difficult to manage, especially during colder seasons.We adjusted with a year and a half (until mid 2016) the liberalization schedule we used in building ournatgas wellhead price assumptions. We account for one more price increase taking place in 2013, of+8.5% to RON 60/MWh, instead of two increases, in July and October to 68.3 RON/MWh, as officiallyplanned. For 2014, we assume an overall price raise of 28.3%, which compares to 74.2% in the officialschedule. As we previously mentioned, the risks to our scenario are to be too optimistic, in which case theimpact on Petroms financials will be less material, although still positive.

TABLE: OUR ASSUMPTIONS FOR THE NATGAS PRICES LIBERALIZATION PROCESS - POSTPONEMENT UNTILL MID 2016Industrial consumers Households Weighted average (70% industrial / 30% households)

Convergencedegree (%)

Wellheadprice

(RON/MWh)

Well-headprice

increase(%)

Convergencedegree (%)

Wellheadprice

(RON/MWh)

Well-headprice

increase(%)

RON/MWh

RON/'000 m3

USD/'000 m3

averageyearly price(RON/ '000

m3)

averageyearly price(USD/ '000

m3)

yoy (%)

Feb-13 35 49 7.2 33 45.7 0.0 48.0 520 155 Apr-13 40 55.3 12.9 33 45.7 0.0 52.4 568 169

Jul-13 45 60 8.5 33 45.7 0.0 55.7 603 180Oct-13 45 60 0.0 36 48.5 6.1 56.6 612 183

2013 31.3 6.1 574 174 17.5Jan-14 47 63.4 5.7 37 49.8 2.7 59.3 642 192

Apr-14 51 68.3 7.7 38 50.6 1.6 63.0 682 204Jul-14 55 72 5.4 41 51.8 2.4 65.9 714 213

Oct-14 60 77 6.9 44 53.3 2.9 69.9 757 2262014 28.3 9.9 699 209 20.1

Jan-15 63 81 5.2 46 54.6 2.4 73.1 791 236 Apr-15 71 89.4 10.4 47 56.1 2.7 79.4 860 257

Jul-15 71 89.4 0.0 49 58.9 5.0 80.3 869 259

Oct-15 76 95 6.3 52 62 5.3 85.1 922 2752015 23.4 16.3 861 257 23.1

Jan-16 76 95 0.0 54 64.1 3.4 85.7 928 277 Apr-16 81 100 5.3 56 67.1 4.7 90.1 976 291

Jul-16 81 100 0.0 60 71.7 6.9 91.5 991 296Oct-16 91 109 9.0 64 76.5 6.7 99.3 1,075 321

2016 14.7 23.4 993 296 15.3

Jan-17 91 109 0.0 66 78.5 2.6 99.9 1,081 323 Apr-17 100 119 9.2 69 82 4.5 107.9 1,169 349

Jul-17 100 119 0.0 73 86.9 6.0 109.4 1,184 354Oct-17 100 119 0.0 78 93 7.0 111.2 1,204 359

2017 9.2 21.6 1,160 346 16.8

Jan-18 119 81 96.5 3.8 112.3 1,216 363 Apr-18

119 83 99.2 2.8 113.1 1,224 366Jul-18 119 89 106.3 7.2 115.2 1,248 372

Oct-18 119 97 115.1 8.3 117.8 1,276 3812018 23.8 1,241 370 7.02019 119 100 119 3.4 119.0 1,289 385 1,289 385 3.92020 1,289 3852021 1,289 385

2022 1,289 385NB : USD prices calculated using USDRON 3.35 for the entire time horizon Source: ANRE, Petrom, SSIF Broker estimates

Based on the above time table, Petroms natgas selling price would reach USD 385/000 m3 by 2019. Atan estimated sales of 4.4-4.5bn m 3, the price convergence would add in 2019 RON 3.1 3.2bn (USD1.01 1.04bn) to the current level of revenues, or a net of roughly RON 2.5-2.6bn if we account for a 20%royalty charge.

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OUR EXPECTATIONS FOR NATGAS WELLHEAD PRICES CONVERGENCE

Source: Petrom, SSIF Broker estimates

Please note than in ascenario of further delays inliberalization for non-households, the impact onEBIT could drop to 2% in2013 and 7% in 2014

As for the impact on EBIT and net profit in 2013 and 2014, our base case scenario is for a plus of 3% forEBIT and 2% for the net profit in 2013, going up to 8% in 2014 (at EBIT level). However, in a gloomierscenario of no more price increases in 2013 for non-households and a 21.3% increase in the first half of2014 (to 67 RON/MWh), average wellhead prices would be USD 168/000 m3 in 2013 and USD 197/000m3 in 2014 and the impact would drop to 2% on EBIT and 1% on net earnings in 2013, and 7% and 6%respectively in 2014.

We assess the impact of thenewly introduced tax onmineral resources at 0.6%-0.7% of EBIT going forward,and therefore minor

New mineral resources tax, i.e. 0.5%, would apply only to crude oil production and not to natgas -we estimate a negative impact of 0.6-0.7% of EBITThe new taxation regime enforced by Government in Feb 13 includes also a mineral resources taxapplied to all types of resources excluding natgas. This tax will apply until end-2014, when the fiscalstability clause that keeps royalties for mineral resources unchanged expires . In Petroms case, based on

our current estimates for crude oil production, this tax would wipe off some RON 46mn pre-tax in 2013,decreasing to RON 42mn in 2014 and towards RON 30mn by the end of our forecast t ime horizon. This isthe equivalent of approximately 0.6%-0.7% of our EBIT estimates, so the impact is actually minor.

ESTIMATED IMPACT OF NATGAS PRICES LIBERALIZATION AND TAXA TION ON PETROMS P&L 2013 2014

Natgas sales (bn m3) 4.82 4.75

Price post liberalization (RON/'000 m3) (average) 574 699

Price difference (RON/ '000 m3) 48.8 173.9

Additional revenues (RON mn) 235.1 826.1

Windfall tax (RON mn) 87.5 307.3

Impact on Petrom's EBIT (RON mn) 135.9 477.3

% of total additional revenues captured by Petrom (at EBIT level) 57.8 57.8

as % of EBIT 3 8

Net impact Petrom (RON mn) 114 401

Amounts remaining with the State (RON mn) 121 425

0.5% tax on natural resources (crude oil), RON mn 46 42

Net impact Petrom, accounting for the tax on natural resources (RON mn) 68 359

% of net profit 2 8Source: SSIF Broker estimates

Going forward, we see royalty as the main taxation tool to be used by the GovernmentWe see highly likely that all these fiscal changes would be removed and replaced by the more straightforward royalty tax. Given that the local authorities can adjust the royalty starting with 2015, we believethey will do so in such a way to allow Petrom to retain part of the liberalization benefits.

188162 155 162 143

174209

257296

346370 385 385 385

385

0

50

100

150

200

250

300

350

400

450

Wellhead natgas prices (USD/ '000 m3)

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The renewable-powersubsidies are relevant for theeconomics of the G&P

segment, but to a limitedextent

Other legislative changes of relevance for PetromMore visibility on legislative changes for the renewable sector would be relevant for Petrom aswell, but only up to a certain extentGiven that Romania currently offers one of the most advantageous legal framework for the investors inrenewable energy, offering them a very high number of green certificates, which, on turn, burden the enduser price, the Government is considering some legislative changes for scaling back renewable-powersubsidies. While it initially spoke of a reduction in the number of green certificates granted per MWh ofenergy produced and of lowering the upper end of the price interval for these certificates, the Governmentdecided to go only for a postponement of the use of part of the certificates received by the green powerproducers. For example, the wind power producers would still be receiving 2 certificates per 1 MWh butwould be allowed to monetize only one until 2017, when the other certificate could also be sold. Solarpower companies may receive 4 certificates instead of the current 6 until mid-2016, and the Governmentwould gradually restore incentive use subsequently. Apparently, the postponement is based on theassumption that market prices for green certificates would continue their downward trend entered in 2H12and this measure would not only mean a delay of the burden on electricity end-user prices of therenewable-power subsidies, but also its reduction. Overall, the approach seems much milder than we

would have expected. This could mean that the Government fears legal cases started by the marketplayers. It seems that in any case the measures would refer only to new or technologically upgradedpower plants.

On the other hand, on 29 March, ANRE, the power market regulator published a report on the renewable-energy sector overcompensation and recommended the reduction of green certificates, for new windfarms from 2 to 1.5 certificates per 1 MWh, for technologically upgraded wind farms from 2 to 1.3certificates per 1 MWh, for solar power plants from 6 to 3 certificates and for micro hydro power plants(new) from 3 to 2.3 certificates per 1 MWh. However the reduction is for now only a recommendation of

ANRE and needs a Government Decision for its enforcement. According to Bursa daily, the reductionwould be envisaged from 2014 for solar power producers and from 2015 for the rest.

In the meantime, on 13 March, ANRE approved higher tariffs for the green certificates, given the EUimposed yearly inflation indexing. Consequently, now the green certificates can be traded at pricesbetween RON 129.64 (EUR 28.9) and RON 264.1 (EUR 58.8) per certificate, which compare to RON121.9-248.3 previously.

Natgas export is possiblenow only in theory, as thenecessary logistics are not in

place; we suspect that priceliberalization reducesPetroms interest for export

Natgas export is now legally possible, but not physically Another legislative change with relevance for Petrom was published by ANRE on 30 March and allowsthe natgas exports to EU countries, provided there is the necessary interconnection between thetransportation grids. This came as a consequence of the infringement procedure against Romania startedby the European Commission in Nov 2012, for not abiding by the EU regulations that forbid anyquantitative export restrictions or other measures with similar effect. The ANRE order says thatexchanges with non-EU countries are also not forbidden provided the necessary logistics are in place.The restriction on natgas exports was a limitation on Petroms options for natgas monetization (given thelow level of the recommended price for domestic natgas producers) and of its negotiation power in

discussions with the Romanian authorities. Therefore, this change is, theoretically, a positive, althoughwe cant estimate how much would Petrom make use of this option now, in the context of domesticnatgas prices liberalization and a relatively supportive taxation regime in force. At the same time, we notethat the export through the interconnections with Hungary and Moldova is physically not possible atpresent (natgas pressure in the interconnection point allows only one way transfer of natgas, namely intothe Romanian grid), so for the time being the regulatory change is useless.

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In Exploration & Production,Petrom is fighting forachieving productionvolumes stabilization

In Gas & Power, thecontribution of the relativelynew Power segment is toincrease but stay below theinitial profitability targets

In Refining & Marketing, aEUR 600mn technologicalupgrade of Brazi refinery isto be concluded by end 2014

Prospects of the main business segmentsPetroms focus on E&P is high and increasing, including significant production stabilizationefforts drilling of development wellsIn Feb 13, Petrom signed a farm-out agreement with Repsol by which the latter acquires a 49% workinginterest for the area deeper than 2,500 3,000 m of four onshore exploration blocks located south of theSouthern and Eastern Carpathians. Petrom had already performed an intense 3D seismic program in thearea, as a result of which the Totea gas discovery was reported in July 2011 (potentially the mostimportant onshore discovery of the past 7 years and currently Petroms largest natgas and condensateon-shore well (still an exploration well) in production volume terms, initially 3,200 boe/d). Together withRepsol will now evaluate the data obtained during seismic programs to determine exploration drillingopportunities. The company estimates that in the next two years, the OMV Petrom Repsol partnershipwill invest around EUR 50mn for exploration drilling.

field redevelopmentIn order to ensure production stability in Romania, Petrom set-up several field redevelopment projectsfocusing on drilling, workovers, water and steam injection, most of them in partnership with specialistssuch as Petrofac, Petrol Santander and Expert Petroleum. For 2013, Petrom plans to have five fieldredevelopment projects in implementation phase by year-end. In Kazakhstan, there is need forimplementing a water injection scheme in Komsomolskoe field and carry out field re-development for TOC(Tasbulat, Aktas, Turkmenoi).

Power segment challenging environment in the power market; natgas prices liberalizationexpected to pressure segments marginsRomanian power market is currently going through several changes. Not only liberalization of the end-user prices, changes in legal framework but also the structure of the power mix is changing, with therenewable accounting for much more than in the past. We saw unusual situations YTD, such as lowerprices on the spot market than on the bilateral longer- term contracts market, mainly as a consequence ofincreased power supply. Hidroelectrica restored its production levels to normal and wind farms enjoyed

favourable weather conditions. Brazi power plant, which started commercial operations in August 2012, isalready a major player on the power market, given its flexibility for quick shut down and restart. It covered5% of the domestic electricity production in 1Q13, with a 0.78 TWh production (0.78 TWh in 3Q12 and0.75 TWh in 4Q12). In 1Q13, it sold 44% of its output on the regulated market (45% in 4Q12). For 2013,

ANRE requires Petrom to sell on the regulated market up to 1.5 TWh at RON 169/MWh. Companysguidance for 2013 indicates expectations for total electricity sales of 6.41 TWh (which may proveoptimistic given the currently oversupplied electricity market). A one month shutdown of Brazi power plantfor the installation of a gas treatment unit took place in April 2013. Dorobantu wind park generated 0.09TWh in 2012, for which Petrom received 182,784 green certificates (the equivalent of EUR 10.1mn @ 55EUR/certificate).

From September 2012 onwards, Brazi power plant was supplied with equity gas only. This was a positivefor its margins, given that previously the basket of domestic and imported gas was imposed on allindustrial producers. However, going forward, natgas prices liberalization will gradually pressure powerplants margins, while the profit will be booked by the E&P division. As mentioned above, the electricitymarket is also undergoing a liberalization process, expected to offset the pressure on margins generatedby natgas prices liberalization. It will depend on the timing of the two liberalization processes.

In R&M, the focus is on finalizing Brazi refinerys technologic al upgradeIn R&M, Petrom works on finalizing the upgrade at Brazi power station, to further optimize its operationalperformance. The aim is to commission the refinery coker unit upgrade and the new gas desulfurizationunit, and to finalize Bacau terminal modernization and commence operations by end of the year. Theupgrade implemented by Petrom in its refining segment over the past years should result in yieldsstructure improvement (some benefits already kicked in last year), the target for 2014 being to havemiddle distillates at 45% vs. 35% in 2011, while cutting own crude consumption from 12% to 10% overthe same horizon. Going forward, we expect the R&M segment to continue to bring a positive contributionto Petroms EBIT, however without becoming a major contributor to companys profitability, not even afterthe technological upgrade.

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Petrom remains one of the

most constant performers inour universe in terms of profitability

The stock went ex-dividendon 10 May

1Q13 clean CCS netearnings amounted to RON1,328mn, 5% up yoy

Petrom continues the row of record high financial results and is a decentdividend playStrong 2012 results but less impressive dividend proposalPetrom registered another robust financial performance in 2012. Sales revenues advanced by 16.1% yoyto RON 26.3bn, while the EBIT margin remained flat at 21.6%. 2012 EBIT amounted to RON 5.7bn,14.7% up yoy. Petrom booked in 4Q12 RON 209mn special charges related to a fiscal review thatincreased its financial losses. However, its FY 2012 net earnings amounted to RON 3,953mn (+5.3%yoy), another record high reported by the company.

Petrom will distribute a gross DPS of RON 0.028, 9.7% lower than the one paid out of 2011 net earnings,translating into a 40.1% payout ratio, which compares to 47.6% a year ago. Implied dividend yield was6.1% at announcement. Registration date was 14 May, meaning that the stock went ex-dividend on 10May, when the share price adjusted by less than the dividend.

1Q13 financial results revealed another strong quarter, in line with market expectations. OMV Petromreported 1Q13 financial results that show EBIT of RON 1,582mn, 11.8% down yoy, mainly on the higherexploration expenses resulted from the intensive off-shore seismic campaign (clean CCS EBIT was RON

1,579mn, 4% down yoy). Some pressure also came from lower natgas sales, given the much milderwinter. 1Q13 net profit amounted to RON 1,330mn, 3.9% down yoy and 26% up qoq and very much inline with market expectations (Reuters consensus, median).

Companys guidance for2013 looks encouraging,given Petroms history ofbeating the budget

We expect 2013 to bring another record high net profit; companys guidance issupportive2013 company budget shows expectations for a flat EBIT (+1.2%) but net earnings 15% higheryoy; Petrom estimates a 31% yoy increase in total capex (mostly in E&P)Petroms budget for 2013 (unconsolidated, Romania only) incorporates expectations for a lower turnover(excluding excises), but 15% higher net earnings, of RON 4.4bn. EBIT is estimated to remain relativelyflat (+1.2% yoy), and most likely the impact on net earnings comes from lower one-offs versus 2012(when a RON 209mn special charge for alleged late interest payments following the result of a 2009-2010

fiscal review was booked). As for the operating indicators provided as guidance, hydrocarbons productionin Romania is expected to remain flat at 62.4mn boe, as a result of a minor increase in the crude oil andcondensate production (+1%yoy) associated with a decrease, also minor, in natgas production. As forelectricity sales, Petrom estimates a total volume of 6.41 TWh, meaning that it expects a very good yearfor Brazi power plant (which, as we previously said, may prove optimistic given the currently oversuppliedelectricity market). Given that historically Petrom exceeded its budget, we are encouraged by theguidance published by the company.

OMV PETROMS GUIDANC E FOR 2013 (IFRS, UNCONSOLIDATED)RON mn 2010A 2011B 2011A 2012B 2012A 2013B yoy (%)

Turnover (excluding excises) 13,953 12,692 16,184 15,796 19,123 17,216 -10.0

EBIT 3,202 2,763 4,660 4,392 5,068 5,129 1.2

EBIT margin (%) 22.9 21.8 28.8 27.8 26.5 29.8 3.3pp

Net profit 1,799 2,316 3,730 3,784 3,851 4,430 15.0NB: A is actual, B is budget Source: OMV Petrom, SSIF Broker

Petrom estimates a 35%higher yoy E&P capex in2013, most likely on higheroff-shore exploration costs

As for capex , Petrom expects to spend 35% more in E&P in 2013 as opposed to a year ago, mainly ononshore fields redevelopment and offshore 3D seismic prospecting and new drillings. The bulk of capex isto go to E&P, in line with previous company statements.

OMV PETROMS 2013 CAPEX PLANRON mn 2010 2011 2012 2013B yoy (%) % in total

E&P 2,774 3,254 3,753 5,076 35.3 78.8

R&M 758 980 899 1,108 23.2 17.2

G&P 1,211 515 221 72 -67.4 1.1

Headquarters & other 120 54 57 189 231.6 2.9

Total 4,863 4,803 4,930 6,445 30.7 100.0NB: budget for 2013 is for Romania only (unconsolidated) Source: OMV Petrom, SSIF Broker

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Valuation

DCF valuation

We asses our 12M target price for OMV Petrom based on a 10Y DCF approach. We use a risk free ratefor Romania 5.75% and a 5% ERP. We also use a levered beta for Petrom of 1.2. We derived a 12M TPof RON 0.52/share, offering 26.7% potential upside; thus we resume our coverage on the stock with aBuy rating.

10Y DCF VALUATIONRON mn 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E

Revenues 21,833 23,929 22,981 21,293 21,465 21,869 22,277 22,945 23,634 24,343

Expenditures -16,647 -18,252 -18,458 -17,021 -16,725 -16,965 -17,346 -18,095 -18,867 -19,657

Operating profit 5,186 5,677 4,524 4,272 4,740 4,903 4,931 4,851 4,766 4,686

Tax -830 -908 -724 -684 -758 -785 -789 -776 -763 -750

NOPLAT 4,356 4,769 3,800 3,588 3,982 4,119 4,142 4,075 4,004 3,936

Depreciation 2,965 3,115 3,218 3,317 3,317 3,317 3,317 3,317 3,317 3,317

Change in net working capital -198 -94 -72 -807 -17 -40 -41 -67 -69 -71Capex -6,500 -4,500 -4,300 -4,000 -4,000 -4,000 -4,000 -4,000 -4,000 -4,000

FCF 624 3,289 2,646 2,098 3,282 3,396 3,419 3,325 3,252 3,183

PV FCF 662 3,152 2,289 1,640 2,316 2,163 1,967 1,728 1,526 1,493Source: SSIF Broker estimates

DCF SUMMARY AND WACC CALCULATIONI. perpetuity (g= -2%) II. Exit EV/EBITDA at 4x WACC calculation

Sum of PV of FCF 18,935 18,935 Risk-free rate (Romanian EUR-bond) 5.75%

PV of Terminal value 9,365 12,933 ERP 5.00%

Total EV 28,300 31,867 Levered beta 1.23

Net debt (end 2012)* -3,591 -3,591 Cost of equity 11.9%

Equity value (RON mn) 24,708 28,276 Tax rate 16.0%

Equity value (USD mn) 7,487 8,569 After-tax cost of debt 6.1%

per share (RON) 0.436 0.499 % of Debt 20.0%

12M target (RON) 0.483 0.553 % of Equity 80.0%

WACC 10.74%* as per end 2012 adjusted for dividends Source: OMV Petrom, SSIF Broker estimates

Petrom trades atundemanding valuation andoffers interesting short andlong term triggers

Relative valuationDiscounts to CEE peers between 45% and 48% seem unjustifiedPetrom is trading at 40-54% discounts to its peers in 2013E-2014E P/E terms and 51-53% in EV/EBITDAterms. If we exclude outliers (including Tupras from EV/EBITDA calculations), discounts go to 45 48%for both multiples. Its current discounts to peers are roughly similar to the historical ones in EV/EBITDAterms, however the stock triggers improved significantly (i.e. offshore potential, natgas pricesliberalization). One downside still in place is the low liquidity, solvable through either FP or the

Government selling part of their stakes. At present, the former seems more likely than the latter.

PEER GROUP COMPARISON (USD-BASED)MCap Price (LC) P/E (x) EV/EBITDA (x)

Company Country USD mn 17 May 2013 2012 2013E 2014E 2012 2013E 2014E

CEE/SEE peers*

OMV AT 12,600 38.9 5.4 8.6 8.5 2.8 3.7 3.6

MOL HU 5,916 16,700.0 7.9 8.3 7.4 5.8 4.9 4.4

PKN PL 5,228 52.0 5.9 12.4 11.7 5.1 6.3 6.2

Tupras TR 5,553 52.3 7.1 10.9 11.2 8.4 10.8 10.6

Unipetrol CZ 1,198 172.0 n/a -23.9 29.5 9.1 7.6 6.5

INA CR 5,647 4,318.1 26.2 10.1 n/a 12.9 7.3 n/a

Median 7.1 9.3 11.2 7.1 6.8 6.2

Petrom RO 5,358.3 0.4105 5.5 5.6 5.1 2.8 3.3 2.9

Petrom vs. CEE/SEE (%) -22.8 -40.5 -54.3 -60.8 -51.4 -52.5* consensus estimates Source: Bloomberg, OMV Petrom, SSIF Broker estimates

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Forecasts and estimates

In spite of companys effortsto stabilize production, westill account for a 1.7% p.a.decline over the long term

Revenues assumptions

We expect a gradual decline of hydrocarbon production over the long runHaving less to almost no capex requirements for G&P and R&M segments, Petrom has intensified itsalready high focus on E&P, with the main target being production stabilization, either through fieldsredevelopment or new developments. However, in spite of companys efforts, given the high naturaldecline rate (10%), we prefer a conservative approach and account for decreasing production over thelong run. Our current assumptions incorporate a 0.5% yoy decrease in total production in 2013, and wecontinue to build our estimates for 2014 and onwards on a decreasing trend of production (decreasing byan average 1.7% p.a., the decline coming more from crude than from natgas production). Upsidepotential can co me from Petroms off -shore exploration efforts, which so far have confirmed a potentiallymajor natgas presence. However, further tests are required to gather information on the hydrocarbonpotential and whether this will prove commercial or not depends on several factors. We currently dontaccount for this upside potential, we however underline i t as being major.

E&P PRODUCTION VOLUME ASSUMPTIONS2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E

Crude production (mn bbl) 32.5 32.3 31.7 31.1 30.4 29.8 29.2 28.6 28.1 27.5 27.0

Natgas production (bn m3) 5.27 5.24 5.16 5.09 5.01 4.94 4.86 4.79 4.72 4.65 4.58

Total production (boe/day) 182,700 182,373 179,195 176,073 173,007 169,995 167,036 164,130 161,276 158,472 155,718

Yoy (%) -1.6 -0.5 -1.7 -1.7 -1.7 -1.7 -1.7 -1.7 -1.7 -1.7 -1.7Source: OMV Petrom, SSIF Broker estimates

Crude prices remainsupportive for an upstreamcompany such as Petrom

Crude price forecastsWe basically followed the futures curve to build our assumptions for crude prices. Our LT price forecast isUSD 90/bbl (2019 onwards). Sensitivity to LT crude price assumption is mate rial to Petroms valuation, asa 5% change in our LT price (USD 4.5/bbl) would cut/add 3.7% from/to our 12M target price. From our

analysis it l ooks that, based on our forecasts, Petroms current market price incorporates a USD 7 0/bbl LTcrude price.

CRUDE PRICE ASSUMPTIONSUSD/bbl 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E

Brent forecasts 111.60 105.60 102.70 96.70 94.00 92.00 91.00 90.00 90.00 90.00 90.00

Ural forecasts 110.76 104.30 101.20 95.20 92.50 90.50 89.50 88.50 88.50 88.50 88.50Source: Bloomberg, OMV Petrom, SSIF Broker estimates

12MTP (RON) SENSITIVITY TO LT CRUDE PRICE ASSUMPTION 2013 EBIT AND NET PROFIT SENSITIVITY TO CRUDE PRICE

Source: SSIF Broker estimates

0 . 4

3 4

0 . 4

5 5

0 . 4

7 6

0 . 4

9 7

0 . 5

1 8

0 . 5

3 9

0 . 5

6 0

0 . 5

8 1

0 . 6

0 2

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

7 0

. 0

7 5

. 0

8 0

. 0

8 5

. 0

9 0

. 0

9 5

. 0

1 0 0

. 0

1 0 5

. 0

1 1 0

. 0

12M TP (RON) at various LT crude price assumption s (USD/bbl)

3 , 2

9 3

3 , 7

6 6

4 , 2

3 9 4 , 7

1 3

5

, 1 8 6

5 , 6

5 9

6 , 1

3 2

6 , 6

0 5

7 , 0

7 8

2,5542,961

3,3683,776

4,1824,590

4,9985,405

5,812

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

8 5

. 6

9 0

. 6

9 5

. 6

1 0 0

. 6

1 0 5

. 6

1 1 0

. 6

1 1 5

. 6

1 2 0

. 6

1 2 5

. 6

2013 EBIT (RON mn) 2013 Net earnings (RON mn)

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In our base case, weassume a 20% hike ofroyalties, which may proveconservative

Royalty regimePetrom was granted a mild royalty regime by the privatization contract, which is to expire at the end of2014. Negotiation talks have already been started and we expect the Romanian Government to operate amajor change, which will increase the royalty paid by Petrom from the current 8% average towards the

20% level. In fact, this is our base case scenario for 2015 onwards. This compares to the European levelalthough would be a bit harsher (various sources give European level to be anywhere between 13% and20%). We therefore note that our assumption may prove over-conservative and that the risk is on thedownside. We dont 100% exclude an early implementation of the change, e.g. in 2014 vs. 2015, but inthis case we expect a lower hike (to approx. 16%, which could add around 12% to our 12M TP, all othersleft unchanged). Pe troms valuation is highly sensitive to the royalty regime. We assessed that a royaltytax 1pp higher than in the base case for 2015 onwards would cut 3% from our 12M target price.

12M TP (RON) SENSITIVITY TO ROYALTY TAX ASSUMPTION 2013 EBIT AND NET PROFIT SENSITIVITY TO ROYALTY TAX

Source: SSIF Broker estimates

Performance of the main business segmentsWe expect E&P to remain the engine of Petroms EBIT, especially in the context of natgas pricesliberalization, as the additional margin is booked by E&P and not by G&P, as it was the case in 2012,when the realized price was better than the price recommended by ANRE.

For R&M , we assume a 95% LT capacity utilization for Petrobrazi refinery, based on the new nameplatecapacity of 4.2 mn t/y (since 3Q12, previously 4.5mn t/y). We also assume a yield improvement after2014, following the conclusion of the refinery modernization works, due for this year. Yields have alreadyimproved after the modernization of the vacuum distillation unit that was done in 3Q12, which togetherwith a lower energy consumption supported the R&M EBIT in 4Q12. Refining margins are expected to beweak in 2013 and we dont expect any impressive recovery going forward, as the gap between demandand supply may continue to exert a negative pressure. The same sluggish demand would also limitimprovements in the marketing business.

As for G&P , we see some pressure on the gas demand going forward due to the liberalization process.We expect the Brazi power plant to be in the short and possibly midterm clearly below the target 13%ROIC; and therefore to contribute less than initially hoped for (even half).

FX rates : USDRON rate is an important variable for P etroms valuation. At now, we use 3.35 RON/USDaverage rate for 2013-2015 and 3.10 RON/USD going forward.

EBIT BREAKDOWN BY SEGMENTRON mn 2008 2009 2010 2011 2012 2013E 2014E 2015E

E&P 2,931 2,468 3,012 5,236 5,467 5,011 5,397 4,118

R&M -1,800 -618 106 -187 138 203 280 264

Gas & Power 109 71 164 149 360 414 443 474

Corporate & others (incl. provisions) -35 -299 -297 -262 -302 -442 -442 -332

EBIT 1,205 1,622 2,986 4,936 5,662 5,186 5,677 4,524EBIT margin (%) 6.0 10.1 16.0 21.8 21.6 23.8 23.7 19.7

Source: OMV Petrom, SSIF Broker estiamtes

0 . 5

7 9

0 . 5

6 4

0 . 5

4 9

0 . 5

3 3

0 . 5

1 8

0 . 5

0 3

0 . 4

8 7

0 . 4

7 2

0 . 4

5 6

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.700

1 6

. 0

1 7

. 0

1 8

. 0

1 9

. 0

2 0

. 0

2 1

. 0

2 2

. 0

2 3

. 0

2 4

. 0

12M TP (RON) a t various royalty tax levels for 2015 on wards (%)

5 , 1

8 6

5 , 0

5 9

4 , 9

3 1

4 , 8

0 4

4 , 6

7 7

4 , 5

5 0

4 , 4

2 3

4 , 2

9 6

4 , 1

6 8

4,182 4,073 3,963 3,8543,744 3,634 3,524 3,414 3,305

0

1,000

2,000

3,000

4,000

5,000

6,000

8 . 0

9 . 0

1 0

. 0

1 1 . 0

1 2

. 0

1 3

. 0

1 4

. 0

1 5

. 0

1 6

. 0

2013 EBIT (RON mn) 2013 Net earnings (RON mn)

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4Q12 results review

4Q12 results: very strong EBIT (+41.6% yoy), bottom line slightly affected by unfavorable financialresult Petrom s 4Q12 results were in line with markets expectations at EBIT and EBITDA level (even slightlyabove, by 2% at EBIT and 7.6% at EBITDA level), but lagged the expectations for net earnings, on higherFX losses but also a RON 209mn special charge related to a fiscal review. EBIT amounted to RON1,673mn, up 30.1% qoq and 41.6% yoy. Clean CCS EBIT amounted to RON 1,824mn, up 6.7% yoy.

In E&P , EBIT amounted to RON 1,281mn, lower by 12.3% yoy, mainly due to higher explorationexpenses and OPEX (the latter 6% higher yoy in RON terms due to increased personnel expensessubsequent to the conclusion of the new collective labour agreement), partly offset by weaker RONvs. USD. Group hydrocarbon production was 16.84mn boe in 4Q12, vs. 17.08mn boe in 4Q11 and16.75 mn boe in 3Q12. In Romania, production contracted by 2% yoy due to natural decline, causedmainly by a 3% lower crude oil production while natgas output remained roughly unchanged. CleanE&P EBIT was RON 1,329mn.

In G&P , the yoy decrease in natgas sales volumes was more than compensated by the positivecontribution of Dorobantu wind power and Brazi gas-fired power plant, as well as by the better termsfor gas sales. Brazi power plant generated 0.75 TWh, of which 45% sold on the regulated market. In4Q12, Brazi power plant covered some 5% of the domestic electricity production. Dorobantu parkgenerated 0.02 TWh, for which it received 44,183 green certificates (34% more yoy and 16% qoq).

In R&M , the refining margins improved and refinery utilization rate increased to 93% from 76% in3Q12. Clean CCS EBIT amounted to RON 80mn, 29% higher yoy, supported also by improvements inthe yields structure (after the 6-weeks shutdown for technological upgrades in 2Q12). Marketingvolumes decreased by 12% yoy, on the back of an unfavourable market environment.

As expected, a positive effect on EBIT came at the consolidation line level, due to a substantial realizationof intercompany profits (RON 313mn) (due to the decrease in crude inventories and a seasonal decline inthe gas stored). Financial losses were higher yoy and qoq, burdened by a RON 209mn special charge for

alleged late interest payments following the result of a 2009-2010 fiscal review and negative FX effect onreceivables and loans to Kazakh subsidiaries. 4Q12 net income amounted to RON 1,056mn, higher by26.3% yoy, but 15% below market expectations which most probably assumed a better financial result.FY2012 net earnings amounted to RON 3.953mn (+5.3% yoy), another record high reported by Petrom.

Capex in 2012 amounted to EUR 1.1bn, of which 76% went to E&P.

In 2012, reserves continue to decrease: proved and probable (2P) reserves amounted to 1,091mn boe,down 3% yoy, while proved (1P) reserves were 775mn boe (of which 770mn boe in Romania), down by4.6% yoy. Reserves replacement ratio dropped significantly from 70% in 2011 to 44% (42% in Romania).

4Q12 RESULTS REVIEW (IFRS)RON mn 1Q12 2Q12 3Q12 4Q12 qoq (%) yoy (%) vs. cons (%) 2012 2011 yoy (%) vs. cons (%)

Sales revenues 6,005 6,197 6,983 7,073 1.3 10.7 5.8 26,258 22,614 16.1 1.5

Total operating costs -4,211 -5,288 -5,697 -5,400 -5.2 3.7 7.1 -20,596 -17,677 16.5 1.8

EBIT 1,794 909 1,286 1,673 30.1 41.6 2.0 5,662 4,936 14.7 0.6

by segments:

E&P 1,704 1,192 1,289 1,281 -0.6 -12.3 5,466 5,236 4.4

R&M 86 -198 266 -18 n.m. -95.3 137 -187 n.m.

Gas & Power 136 29 59 135 128.5 19.8 360 149 141.3

Corporate & Others -133 -114 -329 274 -183.4 n.m. -302 -262 15.1

EBIT 1,794 909 1,286 1,673 30.1 41.6 2.0 5,661 4,936 14.7 0.6

EBIT margin (%) 29.9 14.7 18.4 23.7 5.2 5.2 -0.9 21.6 21.8 -0.3

Net financials -138 -116 -237 -344 45.0 241.7 -838 -327 156.3

Pre-tax profit 1,655 793 1,049 1,329 26.7 22.9 4,826 4,609 4.7

Income tax -271 -150 -185 -275 48.8 13.0 -880 -850 3.6

Net income* 1,384 643 870 1,056 21.4 26.3 -14.9 3,953 3,757 5.3 -4.5

EBITDA 2,410 1,619 2,035 2,450 20.4 27.9 7.6 8,514 7,766 9.6 2.1Depreciation 616 710 749 777 3.8 5.9 22.1 2,852 2,830 0.8 5.2

* atributable to stockholders Source: OMV Petrom, SSIF Broker

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1Q13 OMV trading statement

In 1Q13, Petromshydrocarbon productionstabilized at 183,000 boe/d

OMVs trading statement indicates a decently good quarter for Petrom, without major surprises On 26 April, OMV published its 1Q13 trading statement incorporating some operational data on Petrom

as well, picturing a good quarter, without anything too spectacular. The hydrocarbon production stabilizedat 183,000 boe/d, same as in 4Q12, 0.5% down yoy. Exploration expenses remained similar to 4Q12 atOMV group level, but increased at Petrom level due to ongoing 3D seismic activities. Natgas salescontracted by 5% yoy, in line with the market demand. Power output increased 5.1% to 0.82 TWh from0.78 TWh in 4Q12. In R&M, OMVs refining margin indicator continued to decrease (on weaker middledistillates and naphta spreads), while its marketing business continued to face subdued demand andmargin pressure, which we suspect it applies to Petrom as well. Crude price was supportive in 1Q13 ifcompared to the previous quarter, as Brent was up 2.3% qoq, but it contracted versus 1Q12 by 5.1%. Nooil hedges have been entered into for 2013 by OMV. On the other hand, the RON appreciated against theUSD on average by some 4.9% qoq and remained almost unchanged vs. the average of 1Q12.

OMV 1Q13 TRADING STATEMENT - PETROM DATA1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 qoq (%) yoy (%)

Production (boe/d) 186,000 187,000 184,000 186,000 184,000 182,000 182,000 183,000 183,000 0.0 -0.5Gas sales (TWh) 16.5 11.97 9.47 16.23 17.32 11.16 9.24 14.4 16.4 13.5 -5.4

Total net electrical output (TWh) - - - - - - 0.78 0.78 0.82 5.1Source: OMV, SSIF Broker

PRODUCTION VOLUMES (BOE/D) CRUDE VS. NATGAS PRODUCTION (MN BOE)

Source: OMV Petrom, SSIF Broker

NATGAS PRODUCTION AND SALES VOLUMES (BN M3) REALIZED CRUDE PRICE VS. URALS (USD/BBL)


170,000

175,000

180,000

185,000

190,000

195,000

1 Q

2 0 0 9

2 Q

2 0 0 9

3 Q

2 0 0 9

4 Q

2 0 0 9

1 Q

2 0 1 0

2 Q

2 0 1 0

3 Q

2 0 1 0

4 Q

2 0 1 0

1 Q

2 0 1 1

2 Q

2 0 1 1

3 Q

2 0 1 1

4 Q

2 0 1 1

1 Q

2 0 1 2

2 Q

2 0 1 2

3 Q

2 0 1 2

4 Q

2 0 1 2

1 Q

2 0 1 3

Total produ ction (boe/day)

8 . 4

8 . 3

8 . 4

8 . 5

8 . 3

8 . 3

8 . 4

8 . 4

8 . 3

8 . 3

8 . 2

8 . 3

8 . 2

8 . 1

8 . 1

8 . 1

8 . 0

9 . 0

8 . 6 8

. 6 8 . 6

8 . 4

8 . 3 8

. 4 8

. 6 8

. 5 8 . 6

8 . 7 8

. 8 8

. 6 8

. 5 8

. 6 8

. 7 8

. 5

0.02.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

1 Q

2 0 0 9

2 Q

2 0 0 9

3 Q

2 0 0 9

4 Q

2 0 0 9

1 Q

2 0 1 0

2 Q

2 0 1 0

3 Q

2 0 1 0

4 Q

2 0 1 0

1 Q

2 0 1 1

2 Q

2 0 1 1

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2 0 1 1

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2 0 1 1

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2 0 1 2

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2 0 1 2

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2 0 1 3

Oil production (mn boe) Natgas (mn boe)

1.48

0.881.04

1.441.55

0.94

0.77

1.661.54

1.11

0.88

1.521.62

1.030.86

1.341.53

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

2.00

Natgas production volumes (bn cm) Natgas sales volumes (bn cm)

0.0

2.0

4.0

6.08.0

10.012.014.016.0

18.0

20.0

01020304050

60708090

100110120

Urals crude price (US$/bbl) Realised crude price (US$/bbl)Realisation gap (rh side)

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1Q13 results review

1Q13 clean CCS EBITdropped 4% yoy on smallersales (especially natgas) andhigher exploration expenses

1Q13 results: a solid quarter, in l ine with expectations, with E&P EBIT slightly pressured byexploration expenses (off-shore 3D seismic campaign)

OMV Petrom reported 1Q13 financial results that show EBIT of RON 1,582mn, 11.8% down yoy, mainlyon the higher exploration expenses resulted from the intensive off-shore seismic campaign (clean CCSEBIT was RON 1,579mn, 4% down yoy). Some pressure also came from lower natgas sales, given themuch milder winter. 1Q13 net profit amounted to RON 1,330mn, 3.9% down yoy and 26% up qoq andvery much in line with market expectations (Reuters consensus, median).

E&P : total hydrocarbon production remained relatively constant, showing a slight 1% yoy contractionto 16.46mn boe (183,000 boe/d, of which 171,000 boe/d in Romania) from 16.71mn boe (184,000boe/d) in 1Q12 (annual production comparison slightly distorted by the fact that 2012 was a leapyear). The drop in production refers to the domestic operations, as the oil and gas production inKazakhstan remained almost stable. Crude prices remained supportive and average realized priceincreased by 1% to USD 99.37/bbl, as there were no hedging losses in 1Q13 (no hedges entered bythe company for 2013). OPEX decreased by 3% yoy to USD 14.92/boe (same decrease was

registered in RON terms as well), however there was a major increase in exploration expenses (toRON 190mn from RON 18mn in 1Q12) due the 3D seismic campaign started in December in theBlack Sea and, to a small extent, to the write-off of two unsuccessful onshore exploration wells. E&PEBIT amounted to RON 1,417mn, 16.8% down yoy and 10.6% up qoq.

G&P : clean EBIT amounted to RON 155mn and advanced by 13% yoy on higher contribution from thepower business and better natgas sales terms. Net electrical output of Brazi power plant was 0.78TWh, of which 44% was sold on the regulated market at RON 169/MWh. Day-ahead market priceswere RON 155/MWh for base load and RON 200/MWh for peak load in 1Q13, according to Petrom.Starting 30 March, the power plant entered a 30 days planned shut down for the installation of a gastreatment plant. In 1Q13, Dorobantu wind farm generated 0.04 TWh, 15% higher yoy, and overall,Petrom covered 5% of Romanias electricity production in 1Q13. Downward pressure came mainlyfrom lower natgas sales volumes (-5% yoy). Segment EBIT amounted to RON 113mn (clean EBIT

155mn, 13% up yoy), some 17% down yoy and qoq, reflecting a RON 42mn net special chargerelated to a non- core assets impairment.

R&M : the segment remained profitable with a clean CCS EBIT of 52mn and EBIT of RON 96mn,enjoying the benefits of the vaccum distillation unit modernization done in 2012, which resulted inimproved yields. The indicator refining margin improved to USD -0.88/bbl versus USD -3.58bbl in1Q12, on higher gasoline cracks and lower crude quotations. Marketing sales volume contracted by8% yoy, but the segment had a higher contribution thanks to improved retail margins and costmanagement.

Net debt decreased to RON 1.4bn from RON 2bn at end-Dec 2012, although capex remained elevated atRON 1bn (which compares to RON 1.1bn in 1Q12). Capex dropped significantly in G&P and R&M andwas mainly directed towards E&P (87% or RON 872mn, while its share in total was 75% in 1Q12).

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1Q13 RESULTS REVIEW (IFRS)RON mn 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 qoq (%) yoy (%) 1Q13

Cons*

Sales revenues 4,978 5,293 5,953 6,390 6,005 6,197 6,983 7,073 5,789 -18.2 -3.6 6,168

Total operating costs -3,786 -4,069 -4,614 -5,208 -4,211 -5,288 -5,697 -5,400 -4,207 -22.1 -0.1 -4,543

EBIT 1,192 1,224 1,338 1,182 1,794 909 1,286 1,673 1,582 -5.4 -11.8 1,625by segments:

E&P 1,261 1,170 1,344 1,461 1,704 1,192 1,289 1,281 1,417 10.6 -16.8

R&M -53 57 185 -376 86 -198 266 -18 96 n.m. 11.6

Gas & Power 33 -9 12 113 136 29 59 135 113 -16.5 -16.9

Corporate & Others -49 6 -203 -16 -133 -114 -329 274 -44 n.m. -66.9

EBIT 1,192 1,224 1,338 1,182 1,794 909 1,286 1,673 1,582 -5.4 -11.8 1,625

EBIT margin (%) 23.9 23.1 22.5 18.5 29.9 14.7 18.4 23.7 27.3 3.7 -2.5

Net financials -181 -103 57 -101 -138 -116 -237 -344 2 n.m. n.m.

Pre-tax profit 1,011 1,121 1,395 1,081 1,655 793 1,049 1,329 1,584 19.2 -4.3

Income tax -170 -218 -219 -243 -271 -150 -185 -275 -252 -8.2 -6.9

Net income** 840 903 1,175 837 1,384 643 870 1,056 1,330 25.9 -3.9 1,328

EBITDA 1,868 1,984 1,999 1,915 2,410 1,619 2,035 2,450 2,361 -3.6 -2.0 2,323

Depreciation 676 760 661 733 616 710 749 777 779 0.3 26.4 699* Reuters consensus (median) Source: OMV Petrom, SSIF Broker

** attributable to stockholders

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Company snapshot

OMV Petrom is virtually anupstream company, highlysensitive to crude andnatgas prices

Exploration & Production (E&P)

OMV Petrom is mainly an upstream company, proven also by the sensitivity analyses we presentedearlier in our report. E&P division generates the bulk of its EBIT and attracts most of its capex (76% in2012, 79% budgeted for 2013). It produces virtually all Romanias crude production, i.e. 4 mn toe in 2012.Petrom Groups production was 4.5 mn toe crude oil and NGL, of which 0.5mn toe were produced byPetroms Kazakhstani subsidiary. The main shortcoming is the fact that its fields are fragmented andmature, meaning Petrom consequently faces high lifting costs and a high natural decline of production(10% as per Petroms management).

OMV PETROM 2012 PRODUCTION AND RESERVES DATAProduction (mn boe) Proved (1P) Reserves

Region Oil Gas Oil Gas

Romania 29 34 383 368

Kazakhstan 4 1 21 3

TOTAL 32 34 404 371Source: OMV Petrom

42% RRR in 2012

Some 150mn boe areestimated as recoverablethrough field redevelopment

projects

While currently accountingfor 17% of hydrocarbons

production, offshore potentialis huge

Groups 2P hydrocarbon rese rves at end 2012 were 1.09bn boe, down from 1.13bn boe a year ahead.

Reserves replacement ratio (RRR ) dropped last year to 42% from 70% in 2011 (past 3Y average was61%). However, the high replacement ratio registered in 2011 and 2010 came mainly from reservesrevision subsequent to various geological studies.

Fields redevelopment . As we mentioned above, Petrom had to find ways to stabilize its production inRomania, one main way being field redevelopment projects. It signed partnerships for its on-shore fieldswith specialized partners (Petrofac, PetroSantander, Expert Petroleum) and JVs for deeper, frontier areas(with Hunt Oil and Repsol). Estimated recoverable resources are 150mn boe. Projects in the developmentphase are estimated to require approximately EUR 400mn capex and would add 2P reserves of roughly

70 mn boe of oil and associated gas. Projects in the appraisal phase are expected to add EUR 100mn incapex and a cumulative production of 90 -110mn boe of oil and gas.

Offshore activities: Romanian Black Sea exploration in near shore areas started in 1969, with the firstproduction registered in 1987. Petroms production currently comes from onshore fields, only 17% of totalbeing generated by the offshore operations. However, deep-water perimeters are highly underexplored.Currently, Petroms presence in the Black Sea consists mainly of:

Neptun Deep : a 50%/50% JV with Exxon Mobil. Preliminary estimated resources for Domino, the firstdeep water exploration well drilled at over 9,843 feet (3,000 m), are 1.5 3 tcf (42 84 bcm) ofnatags. Petrom will finalize in 1Q13 a sizeable 3D acquisition, and next well drilling is scheduled forend 2013. Conclusion of the appraisal phase of the Neptun block is estimated for 2016.

Neptun Shallow : operated 100% by Petrom. Exploration started before 2005 and intensified since2008. Past exploration activities included the drilling of two wells (not commercially feasible) and a 2Dseismic campaign. A 60 days 3D seismic campaign conducted on 1,600 square km was started inDec 12 and was completed in the meantime.

Midia Block : Exxon/Petrom partnership increased its presence in the Black Sea by acquiring newexploration acreage, via an 85% interest in the Midia Block, adjacent to Neptun Block, from SterlingResources and Petro Ventures Europe. The transfer agreement was signed in Oct 12 and is subjectto the fulfillment of several conditions, including relevant authorities approval. It also gave an option toRomgaz, the state-owned domestic natgas producer to purchase 10% of the participating interest inMidia Deep, conditional upon the above mentioned transfer agreement becoming effective and anannouncement of a commercial discovery.

Ukraine exploration ventures : a production sharing agreement for Skifska block (Ukraine) is currently

being negotiated with the Ukrainian Government. OMV Petrom has a 15% stake in the winingconsortium (together with ExxonMobil (40%), Shell (35%), and Nadra Ukrainy (10%)).

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Petrom is the second largestnatgas market player, with a47.3% share of 2012

production

Gas & Power (G&P)

Gas : Petrom is one of the few main players on the Romanian natgas market supplying mainly domesticgas. In 2012, it covered 47.3% of the domestic production (after Romgaz with 50.1%), while the domesticproduction covered 75.7% of consumption. It also had a 6.6% share of Romanias imports. It delivers tolarge industrial customer (38% market share), chemicals producers (39% market share) and heat &powerproducers (32% market share).

NATGAS PRODUCTION AND SALES VOLUMES (BN M3) ROMANIAN NATGAS MARKET (2012, %)

Source: OMV Petrom, ANRE, SSIF Broker

After building an 860 MWgas-fired power plant,Petrom became a significant

player on the electricitymarket as well

Power : to monetize some 20% of its natgas production, Petrom started in 2009 to build an 860 MWCCPP state-of-the art natgas fired power plant , with a 57% efficiency factor. Capex was EUR 530mn. Theplant commenced commercial operations in Aug 2012 and covered some 5% of Romanias electricityproduction over 1Q13. C ompanys guidance for 2013 indicates total electricity sales of 6.41 TWh . In4Q12, it sold 45% of its output on the regulated market. For 2013, ANRE requires it to sell on theregulated market up to 1.5 TWh, or 23% of the maximum theoretical output. From September 2012onwards, Brazi power plant was supplied with equity gas only.

Petrom also has a 45 MW wind park , purchased in early 2011 and commercially operational since 4Q11,which has an incomparably lower production (but contributes to costs optimization thanks to the greencertificates received (currently 2 per each MWh produced). In 2012, Dorobantu wind park generated a netelectrical output of 0.09 TWh for which the company received 182,784 green certificates (translating intosome EUR 10mn revenues at EUR 55/certificate).

5.555.30

4.85 4.92 5.06 4.84

0.00

1.00

2.00

3.00

4.00

5.00

6.00

Natgas production volumes (bn cm) Natgas sales volumes (bn cm)

24

36

38

2

Import Petrom Romgaz Oth ers

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The refining business hasbeen resized and is beingmodernized to help the R&Msegment improve itscontribution to Groups EBIT

Refining & Marketing (R&M)

Refining : Petrom currently operates one refinery, Petrobrazi with a nameplate capacity of 4.2 mn t perannum (reduced in 2012 from 4.65mn t), after it closed its other refinery, Arpechim, in 2011 and resizedPetrobrazi to process its entire Romanian equity crude. Petrobrazi is currently undergoing a EUR 600mntechnological upgrade programme, started in 2010 and aimed to be completed in 2014, targetingsignificant yield structure improvements: middle distillates to increase from 35% in 2011 to 45% in 2014,while own crude consumption to drop to 10% from 12%. Another target of the modernization programmewas for the refinery to process the entire equity crude, target already achieved last year.

Marketing : Petrom leads the Romanian market with a 36% market share and a network of 546 fillingstations at end 2012 (545 in 2011), and 798 for the overall Petrom group (including 98 in the Republic ofMoldova, 93 in Bulgaria and 61 in Serbia).

EVOLUTION OF THE REFINING INPUT ROMANIAN MARKETING BUSINESS


6.186.51

5.46

4.153.79

3.34

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

2007 2008 2009 2010 2011 2012Refining in put (mn t)

3437

4239

37 36

3.6

4.64.9 4.7 4.50 4.40

0.0

1.0

2.0

3.0

4.0

5.0

6.0

0

5

10

15

20

25

30

3540

45

2007 2008 2009 2010 2011 2012Romanian market share (%) Thropughput per filling station (mn l/year)

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Financials

INCOME STATEMENT (IFRS)RON mn 2008 2009 2010 2011 2012 2013E 2014E 2015E

Net sales 20,127 16,089 18,616 22,614 26,258 21,833 23,929 22,981Total operating costs -18,922 -14,469 -15,630 -17,678 -20,596 -16,647 -18,252 -18,458

EBIT 1,205 1,620 2,986 4,936 5,662 5,186 5,677 4,524

By segment

E&P 2,931 2,468 3,012 5,236 5,467 5,011 5,397 4,118

R&M -1,800 -618 106 -187 138 203 280 264

Gas & Power 109 71 164 149 360 414 443 474

Provisions, others -35 -299 -297 -262 -302 -442 -442 -332

EBIT 1,205 1,622 2,986 4,936 5,662 5,186 5,677 4,524

EBIT margin (%) 6.0 10.1 16.0 21.8 21.6 23.8 23.7 19.7

Net financials -80 -457 -387 -330 -838 -210 -253 -134

Pretax profit 1,129 1,169 2,605 4,609 4,826 4,979 5,427 4,392

Income tax -233 -336 -416 -850 -880 -797 -868 -703

Net income 978 860 2,201 3,757 3,953 4,182 4,558 3,689

Depreciation -2,670 -2,489 -2,811 -2,830 -2,852 -2,965 -3,115 -3,218

EBITDA 3,875 4,110 5,797 7,766 8,514 8,151 8,792 7,742

EBITDA margin (%) 19.3 25.5 31.1 34.3 32.4 37.3 36.7 33.7Source: OMV Petrom, SSIF Broker estimates

BALANCE SHEET (IFRS)RON mn 2008 2009 2010 2011 2012 2013E 2014E 2015E

Fixed assets 23,293 25,915 28,459 31,022 32,777 36,360 37,795 38,930

Inventories 2,759 2,583 2,500 2,349 2,251 2,183 2,393 2,298

Receivables 1,205 1,332 2,001 2,176 2,179 2,074 2,273 2,183

Other current assets 62 60 77 76 173 173 173 173

Current assets 4,026 3,975 4,578 4,601 4,602 4,430 4,839 4,654

Trade and other payables -3,368 -2,823 -3,931 -3,594 -3,645 -3,275 -3,589 -3,332Net working capital 659 1,152 647 1,007 957 1,155 1,250 1,322

Net capital employed 23,952 27,067 29,107 32,028 33,734 37,515 39,045 40,252

Share capital 18,983 18,983 18,983 18,983 18,983 18,983 18,983 18,983

Retained earnings/other reserves -3,038 -2,804 -498 2,119 4,455 3,269 6,196 9,387

Profit for the year 0 0 0 0 0 4,182 4,558 3,689

Shareholders' equity 15,945 16,180 18,486 21,102 23,438 26,434 29,738 32,060

LT debt 1,468 2,810 3,466 2,322 1,885 2,600 2,000 1,600

ST debt 357 188 391 943 885 2,023 1,598 1,558

Total debt 1,825 2,998 3,857 3,265 2,771 4,623 3,598 3,158

Cash & Cash equivalents -1,598 -636 -1,727 -866 -766 -1,000 -1,000 -1,000

Net debt/(cash) 227 2,362 2,129 2,399 2,005 3,623 2,598 2,158

Provisions 7,735 8,515 8,518 8,553 8,323 7,491 6,742 6,068Net capital employed 23,952 27,067 29,107 32,028 33,734 37,515 39,045 40,252

Total assets 28,917 30,527 34,765 36,488 38,145 41,790 43,635 44,585Source: OMV Petrom, SSIF Broker estimates

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SUMMARY CASH FLOW STATEMENT (IFRS)RON mn 2008 2009 2010 2011 2012 2013E 2014E 2015E

Net profit 978 860 2,201 3,757 3,953 4,182 4,558 3,689

Depreciation 2,670 2,489 2,811 2,830 2,852 2,965 3,115 3,218

Provisions, other non-cash items -528 -1,535 -191 -383 150 -930 -850 -778

Cash earnings 3,120 1,813 4,822 6,204 6,956 6,217 6,823 6,541Capital investment -6,759 -4,219 -4,863 -4,803 -4,930 -6,500 -4,500 -4,300

Acquisition/asset disposal 0 0 67 172 74 50 50 50

Previous year dividend -933 -15 0 -1,003 -1,756 -1,186 -1,255 -1,368

Outflows from operations -7,692 -4,234 -4,796 -5,633 -6,612 -7,636 -5,705 -5,618

Net flows from operations -4,572 -2,420 26 570 344 -1,419 1,119 924

Working capital change 1,793 -494 505 -360 50 -198 -94 -72

Other 0 0 0 0 0 0 0 0

Finance need/excess -2,779 -2,914 531 211 394 -1,617 1,024 440

Capital contribution 0 0 0 0 0 0 0 0

Change in net debt -2,779 -2,914 531 211 394 -1,617 1,024 440Source: OMV Petrom, SSIF Broker estimates

UPSTREAM ASSUMPTIONS AND FORECASTS2008 2009 2010 2011 2012 2013E 2014E 2015E

Brent crude (USD/bbl) 97.01 61.60 79.50 111.31 111.6 105.6 102.7 96.7

Urals (USD/bbl) 94.01 60.80 78.28 109.64 110.8 104.3 101.2 95.2

Ural-Brent differential (USD/bbl) -3.0 -0.8 -1.2 -1.7 -0.8 -1.3 -1.5 -1.5

RON/USD avg. 2.52 3.05 3.18 3.05 3.47 3.35 3.35 3.35

Crude production (mn tons) 4.77 4.66 4.62 4.59 4.51 4.48 4.39 4.31

Natgas production (bn m3) 5.62 5.33 5.16 5.31 5.27 5.24 5.16 5.09

Total production (mn boe) 71.08 68.29 67.08 67.77 66.87 66.57 65.41 64.27

Total production (boe/day) 194,708 187,431 183,707 185,619 182,700 182,373 179,195 176,073

Natgas sales (bn m3) 5.30 4.85 4.92 5.06 4.84 4.82 4.75 4.69

Revenue side

Realized crude price (USD/bbl) 84.11 55.23 68.72 93.30 94.00 89.70 90.57 85.20

Wellhead gas price (USD/'000 m3) 187.9 162.6 155.8 155.8 151.3 174.0 209.0 257.0

Oil revenues (USD mn) 2,893 1,857 2,291 3,086 3,054 2,900 2,870 2,646Gas revenues (USD mn) 1,094 866 843 866 806 896 1,001 1,327

Total revenues (USD mn) 3,987 2,723 3,134 3,952 3,860 3,796 3,871 3,972

Cost side

Opex (USD/boe) -18.0 -15.1 -16.7 -16.2 -15.4 -16.8 -16.4 -16.2

Depreciation (USD/boe) -7.0 -6.2 -9.8 -10.4 -8.8 -9.0 -9.8 -10.5

Royalty (USD/boe) -4.5 -3.2 -3.7 -4.7 -4.6 -4.6 -4.7 -12.4

Other, incl. exploration (USD/boe) -2.5 -2.8 -2.8 -3.0 -3.0 -3.0 -3.1 -3.1

Total lifting costs (USD/boe) -32.1 -27.2 -33.1 -34.2 -31.8 -33.3 -34.0 -42.1

Operating profits

EBIT (USD mn) 1,200 809 948 1,718 1,575 1,509 1,624 1,241

EBIT/boe (USD) 16.89 11.83 14.14 25.35 23.55 22.67 24.82 19.31Source: OMV Petrom, SSIF Broker estimates

DOWNSTREAM ASSUMPTIONS AND FORECASTSRON mn 2008 2009 2010 2011 2012 2013E 2014E 2015E

Crude oil throughput ('000 tons) 6,121 5,161 3,902 3,567 3,146 3,560 3,760 3,760

Crude oil throughput (mn bbl) 44.9 40.0 30.4 30.4 27.8 27.7 29.2 29.2

Capacity nameplate 8,000 8,000 8,000 8,000 4,500 4,200 4,200 4,200

CUR (%) (nameplate) 76.5 65.0 49.0 79.0 73.0 90.0 95.0 95.0

Total output ('000 tons) 5,448 4,982 3,780 3,580 3,060 3,402 3,631 3,631

Domestic 3,800 4,670 3,780 4,070 3,830 3,945 3,945 3,945

Export 1,648 1,510 1,130 1,160 1,180 357 586 586

Export (%) 30.3 24.4 23.0 22.2 23.6 8.3 12.9 12.9

Total sales 5,448 6,180 4,910 5,230 5,010 4,302 4,531 4,531

Ural-MED ref. margin (USD/bbl) 5.54 1.94 2.88 1.15 2.50 3.50 4.00 4.00

Downstream EBIT/bbl (USD/bbl) -5.31 -5.06 1.10 -2.21 1.62 2.19 2.86 2.69

Source: OMV Petrom, SSIF Broker estimates

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DISCLAIMEROur recommendations are based on information obtained from, or are based upon public information sources that we consider to be reliable but for thecompleteness and accuracy of which we assume no liability. All estimates and opinions included in the report represent the independent judgment of theanalysts as of the date of the issue. We reserve the right to modify the views expressed herein at any time without notice. Moreover, we reserve the right notto update this information or to discontinue it altogether without notice.

This analysis is for information purposes only and (i) does not constitute or form part of any offer for sale or subscription of or solicitation of any offer to buy orsubscribe for any financial, money market or investment instrument or any security, (ii) is neither intended as such an offer for sale or subscription of orsolicitation of an offer to buy or subscribe for any financial, money market or investment instrument or any security nor (ii i) as an advertisement thereof. Theinvestment possibilities discussed in this report may not be suitable for certain investors depending on their specific investment objectives and time horizon orin the context of their overall financial situation. The investments discussed may fluctuate in price or value. Investors may get back less than they invested.Changes in rates of exchange may have an adverse effect on the value of investments. Furthermore, past performance is not necessarily indicative of futureresults. In particular, the risks associated with an investment in the financial, money market or investment instrument or security under discussion is notexplained in their entirety.

This information is given without any warranty on an "as is" basis and should not be regarded as a substitute for obtaining individual advice. Investors mustmake their own determination of the appropriateness of an investment in any instruments referred to herein based on the merits and risks involved, their owninvestment strategy and their legal, fiscal and financial position. As this document does not qualify as an investment recommendation or as a directinvestment recommendation, neither this document nor any part of it shall form the basis of, or be relied on in connection with or act as an inducement toenter into, any contract or commitment whatsoever. Investors are urged to contact their bank's investment advisor for individual explanations and advice.

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The authors of this analysis certify that the remuneration has not been, and will not be, geared to the recommendations or views expressed in this study,neither directly nor indirectly. Also, the authors of the present analysis certify that the views expressed in this analysis accurately reflect their personal viewsabout any and all the securities or issuers mentioned in the present analysis .

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Notice for the US residents:

This research report is directed only to the major U.S. institutional investors, as defined under Rule 15a-6 promulgated under the U.S. Securities Exchange Act of 1934, as amended, and as interpreted by the staff of the U.S. Securities and Exchange Commission. This research report is not intended to be use byany other person or entity that is not a major U.S. institutional investor. If you have received a copy of this research report and are not a major institutionalinvestor, you are instructed not to read, rely on or reproduce the contents hereof, and to destroy this research report or return it to SSIF Broker SA. Theanalysts who prepare this research report are employees of SSIF Broker SA and are not associated persons or employees of any U.S. registered

broker/dealer. Therefore the analyst(s) are not be subject to Rule 2711 of the Financial Industry Regulatory Authority (FINRA) or to Regulation AC adoptedby the U.S Securities and Exchange Commission (SEC) which among other things, restrict communications with a subject company, public appearances andpersonal trading in securities by a research analyst. Any U.S. recipient of this report that wishes to discuss or receive additional information regarding anysecurity or issuer mentioned herein, or engages in any transaction to purchase or sell or solicit or offer the purchase or sale of such securities, should contacta registered representative of SSIF Broker SA.

Responsibility for the content of this publication lies with:

SSIF Broker SA, 16 SplaiulUnirii, 8 th floor, Room 802-804, Sector 4, Bucharest, Romania. Authority responsible for the supervision of SSIF Broker SA is theRomanian National Securities Commission (www.cnvmr.ro). This analysis is presented in accordance with Regulation no. 16 regarding recommendations forinvestments in financial instruments.

All materials presented in this analysis, unless indicated separately, are under the copyright of SSIF Broker SA. None of the materials or content or any copythereof may not be modified, transmitted, copied or distributed to any other party, without the permission of SSIF Broker SA. All trademarks, service marksand logos used in this analysis are trademarks or service marks or registered trademarks of SSIF Broker SA. Downloading the materials provided by SSIFBroker SA, without quoting the source is prohibited and punishable by law.

Information related to the securities referred in this analysis may be obtained from SSIF Broker SA upon request.

Recommendation system

Buy : the stock is expected to generate total returns in excess of 15% over the next 12 months, as implied by the target priceHold : the stock is expected to generate total returns of 0-15% over the next 12 months, as implied by the target price caSell : the stock is expected to generate negative total returns over the next 12 months, as implied by the target priceRestricted : disclosure of financial estimates, target price and rating of a stock is temporarily restricted due to compliance reasons (e.g. conflict of interests)Coverage in transition : due to changes in the research team, disclosure of financial estimates, target price and rating of a stock are temporarily suspended .

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Adriana Marin Serban Marin Institutional Clients Division Manager Head of Trading& Head of Research Tel : +40 21 387 3505 / +40 364 260 766 Tel: +40 364 260 761Mobile : +40 740 008 015 Mobile: +40 741 060 000Email : [email protected] Email: [email protected]

Carmen Arsene, CFA Daniel GavrilaSenior Equity Analyst Senior TraderTel : +40 21 387 3459 / +40 364 260 765 Tel: +40 364 260 762Mobile : +40 745 040 077 Mobile: +40 745 466 251Email : [email protected] Email: [email protected]

Dr. Andrei Radulescu Alexandru PredaSenior Investment Analyst Trader Tel: +40 21 387 3456 Tel : +40 213 873 456 Mobile :+40 730 727 516 Mobile : +40 749 026 083 Email: [email protected] Email : [email protected]

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5.SNP - SSIF Broker - 20.05.2013