May 4, 2017

InternatIonal ScoutServing the international upstream industry with information, analysis & prospects for sale Volume 09, No. 06

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Norway says Barents Sea holds over 17 Bboe

Norway believes the Barents Sea holds double the amount of oil and gas it previously thought. New seismic mapping carried out by the Norwegian Petroleum Directorate in the northeast part of the Barents estimates that the region contains 8.8 Bboe. This brings the Barents Sea total to about 17.6 Bboe, or 65% of the total amount of undiscovered resources that remains to be found on the Norwegian Continental Shelf. Prior estimates of the Barents Sea’s resource potential had the region holding just 50% of Norway’s undiscovered oil and gas.

The new Barents Sea resource tally results from analysis of seismic data and cores recovered from a 170,000-sq-km area. From these data, NPD predicts that about 60% of the estimated resources are liquids. About half the 17.6 Bboe Barents total lies in the north part of the sea and about half in the south, but because the mapped region in the north part of the Norwegian Barents is much smaller than in the south, the northern Barents has about twice the resource potential per square kilometer as the southern Barents.

Woodside produces 50 MMcf/d in Thalin DST off MyanmarWoodside’s appraisal of the 1.5 Tcf Thalin-1A find offshore Myanmar was successful.

Thalin-1B was drilled as a sidetrack from Thalin-1A in late February and recovered 99 m of core and wireline logs. Initial multi-rate DST results from the lower reservoir

section of Thalin-1B demonstrated sustained flow rates of 50 MMcf/d for a 50-hour period on a 48/64-in. choke. This exceeded pre-drill expectations and indicates the presence of

excellent-quality reservoir. A test of the upper section will be carried out shortly.

The company has added a well to its Myanmar drilling program this year based on these results. Following the test of the upper section of Thalin-1B, the drillship Dhirubhai Deepwater KG2 will drill appraisal well Thalin-2 in the same license. The drillship will then move 350 km southeast to drill two exploration wells in Block A-6, which contains the 900 Bcf Shwe Yee Htun-1 find. After that the ship will return to Block AD-7 to drill an exploration well. This brings the total to be drilled to five, but the drillship’s contract allows for up to seven.

Tatneft to expand Tatarstan production unconventionally Tatneft, Russia’s sixth-largest oil producer, believes it can significantly expand

production in its home area of Tatarstan. The company produced 574,000 bo/d from its West Siberian fields in 2016—5.0% above 2015’s volumes—but Tatneft’s

board approved a plan last year that will see the company grow output to 600,000 bo/d in 2020 and then 700,000 bo/d in 2025. If achieved, this would put Tatneft’s production on track to match levels seen at

major Western independents. The plan is premised on more efficient use of Tatneft’s reserves base of 6.2 Bbo,

which is enough to sustain production at current rates for about 30 years. Although large, Tatneft’s fields are some of the oldest in Russia, with some having started producing oil in the 1930s. These fields, like Romashkinskoye, are by now depleted and typically feature a large water cut of 85-95%. To combat this, Tatneft sees better reservoir modeling and unconventional drilling as key to improving performance.

Tatneft’s plan for the greater Ashalchinskoye field is an example of the companyʼs long-term strategy.

Exxon builds on shale strategy with Vaca Muerta planExxonMobil is planning a big Vaca Muerta development campaign in Argentina. The

company will begin in May by drilling several horizontal wells in Neuquén province that will have laterals stretching to 2,500-3,000 m. The work will likely take place in the Bajo del Choique and La Invernada blocks, where the company has been engaged in a five-well,

$230 million pilot program since 2015. So far, only two of those five wells have been drilled, but initial

results were seen as promising enough to prompt Exxon to say in mid-2016 that the pilot project could be the start of a 20-to-30-year, $10 billion program. Now, Neuquén’s governor, Omar Gutierrez, says Exxon intends to increase gas production to up to 350 MMcf/d by 2020-2021 and will ask the government for a 35-year lease covering the Los Toldos 1 Sur block. Guiterrez also said Exxon is likely to bid on up to 56 blocks in the play.

Exxon has yet to announce results from its five-well pilot, but data from two wells drilled and completed in 2014 hint at the size of the resource.

Will likely expand pilot work in Bajo del Choique and La Invernada blocks.

Continues On Pg 9

Plan hinges on ability to finance better recovery at depleted W. Siberian fields.

Doubles estimate of undiscovered resources to be found in region.

Continues On Pg 8

Continues On Pg 11

Continues On Pg 4

Results at Thalin-1B leads to additional well added to 2017 Myanmar campaign.

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■ Aker BP hired Schlumberger to carry out a four-year, $30 million 4D seismic data acquisition program at several fields off Norway. Included among them are Alvheim, Bøyla, Skarv, Snadd and Ula fields, all of which will see the 4D program start in 2017. Aker BP will use information gathered from the study to make decisions on how best to develop the fields through new production or injection wells.

■ A scoping study carried out for Cluff Natural Resources by Xodus Group shows that the Cadence-Scremerston and the Bassett Bunter sands prospects in P2248 offshore UK contain between them a best estimate of 293 Bcf. Meanwhile, the same study also shows that P2252 contains eight prospects holding between them a combined 1.4-9.5 Tcf in gross resources. Sole owner Cluff is currently trying to farm out a stake in these permits.

Statoil may greenlight its first Barents project by YE17 Tender documents for Statoil’s Johan Castberg project in the Barents Sea have been

issued to contractors, starting a process that will lead to the third producing oil and gas development in this frontier region. Johan Castberg will develop the Skrugard, Havis and Drivis finds in PL 532 that contain a combined 550-650 MMboe. A FID could come later this year, although Wood Mackenzie expects Statoil to delay a decision on Johan Castberg to 2018 in order to further reduce cost. First oil is tentatively slated for 3Q22.

The project passed Statoil’s in-house decision December 2016, which

allowed FEED to begin. Current thinking envisions Statoil drilling 30 wells—18 for production, eight for water injection and four gas injectors. The wells will produce to a newbuild FPSO with a nameplate capacity of 190,000 bo/d and 290 MMcf/d with the ability to store 1.1 MMbo. Total cost is project to be $5.3-6.0 billion, but Statoil will be able to narrow that cost range down once all contractor bids are in at the end of August.

Johan Castberg’s FPSO-based development has been considerably slimmed down from earlier plans. Prior to the 2014 price collapse, Statoil had been weighing the merits of a much larger project at the behest of the Norwegian government that included a semi-submersible production platform, a pipeline to shore and an onshore receiving terminal. The goal was to not only develop the resources at Skrugard, Havis and Drivis, but also to create the infrastructure needed to jumpstart economic

growth in Norway’s far north. Sustained lower prices nixed

this bigger plan, however, which was conservatively estimated to have a breakeven price of $80/bbl. Deep cost cutting and reduction of project scope has since reduced that breakeven point by 56% to around $35/bbl. This is much more economical for Statoil, but means Johan Castberg might not be as big a production hub for emerging Barents Sea production that both Oslo and Statoil had initially hoped it would be. Johan Castberg is owned by Statoil (50%, operator), Eni (30%) and Petoro (20%).

North Sea & Western Europe

International Scout is published every three weeks by PLS Inc.

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ABOUT PLS

Statoil’s Cost Cuts Put Resources On Stream

Johan Castberg

27Average break-even USD

Average IRR3

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100

- 1,000 2,000 3,000 4,000 5,000 6,000

Bre

ak-e

ven

oil p

rice

(US

D/b

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Recoverable resources (mmboe)

February 2016February 2017

2023Payback2@ USD 50/bbl

65%Oil share

0%

10%

20%

30%

USD 50/bblUSD 70/bblUSD 90/bbl

1. Operated and non-operated projects, sanctioned since 2015 or planned for sanction, with start-up by 2022. Volume weighted.2. Time of accumulated positive cash flow after tax.3. Internal rate of return at time of sanctioning. Capex weighted.4. Total non-sanctioned portfolio (operated and non-operated).

/bbl

More for less4World class projects 2015-221

Trestakk

Peregrino Phase 2

Source: Statoil Feb. 7 Presentation via PLS docFinder www.plsx.com/finder

Will put 550-650 MMboe on stream in 3Q22 via a 190,000 bo/d FPSO plan.

Breakeven has been slashed by 56% from about $80/bbl to around $35/bbl.

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Volume 09, No. 06 3 e&P

Access PLS’ archive for previous E&P news

Wintershall-Gazprom JV begins producing from Danish fieldWintershall Noordzee started up Ravn field, the first field in Danish waters to

be put into production in 10 years. An unmanned platform is connected to two wells that will recover an estimated 18.2 MMbo from an Upper Jurassic reservoir 4,000 m below the subsurface. Oil will be sent via an 18.5-km, 8.0-in. pipeline to a processing platform in Germany and then to the Netherlands for export.

Ravn was discovered in 1986 in North Sea licenses 5/06 and 2/16, where water depths run to 50 m. Operator Wintershall Noordzee, a 50:50 Wintershall-Gazprom JV, was awarded the licenses in 2006 and owns a 63.64% stake of the project. Denmark’s state-owned oil company, Nordsøfonden, owns the remaining 36.36%.

Statoil gets greenlight for Gina Krog to be brought online Norway gave Statoil permission to start operations at Gina Krog field in the North

Sea. Gina Krog’s 260 MMboe is being developed as a shuttle-tanker tie-back to the nearby Sleipner field in PL 046. Infrastructure consists of a newbuild processing and accommodation

platform in addition to a floating storage and offloading vessel that will service 14 wells. First oil could come before the end of May, but Statoil said start-up may not come until mid-2017.

Gina Krog will begin producing without its FSO, however. In February, Statoil was informed by Teekay Offshore that the FSO wouldn’t be available until after Q1, requiring Statoil to either push back first oil or file for permission to start up without the FSO. Statoil chose the second option as an interim solution until the FSO becomes available later in 2017. Until then, the contracted tankers will ship oil to Sleipner.

Gina Krog was discovered in the 1970s and lies in water 120 m deep, 30 km from Sleipner. Total project cost is $3.6 billion. The field sits in PL 048, which is owned by Statoil (58.7% WI, operator), Kufpec (15%), Tellus Petroleum (15%), PGNiG (8.0%) and Aker BP (3.3%). Production is expected to last until 2037.

North Sea & Western Europe International O&G takes an unconventional turn

Argentina is emerging as a major focus for oil and gas investment in what looks to be an extended period of low prices. In the latest from the country, both ExxonMobil

(PG. 1) and Total (PG. 9) announced that they would invest in large, operated

development campaigns in the country’s Vaca Muerta shale play. Also announced in the last month was a new shale deal between Schlumberger and YPF (PG. 9), the latest in string of tie-ups between the Argentine NOC and international oil companies over the past few years. The attraction is the Vaca Muerta’s vast potential and the new-found pro-business stability on offer in Argentina.

Elsewhere, unconventional oil and gas is also getting a lot of attention. In India, Reliance Industries began producing coalbed methane and plans to tap even more of the resource in the future (PG. 14). China’s CNPC is following suit via CBM projects with local independents, while CNOOC is now offering CBM blocks, though a subsidiary, alongside acreage in the South China Sea. Russia’s Tatneft is also betting big on unconventional oil, where it is drilling steam-assisted gravity drainage wells at its fields in West Siberia.

Offshore operators aren’t standing still, however. In Norway, Statoil is close to bringing Gina Krog on stream in the North Sea (PG. 3) and, after much cost cutting, may sanction the development of a much slimmed down Johan Castberg in the Barents Sea (PG. 2). Castberg would be only the third project to be developed in the Barents. Statoil says Castberg’s breakeven point is now about $35/bbl, making the project competitive even at today’s prices. With more than half of Norway’s remaining undiscovered reserves sitting in the frontier region, more drilling is sure to follow (PG. 1).

IN THIS ISSUE

Shale, steam-assisted drainage , coalbed methane projects announced.

Work in frontier Barents Sea becoming cheaper as Statoil near Castberg FID.

Gazprom Neft boosts Kurdistan well flow by 42%Gazprom Neft performed an acid stimulation on the Sarqala-1 well in the Garmian

Block in the Kurdistan region of Iraq. The well is now producing at a stabilized rate of 7,100 bo/d on a 48/64-in. choke at 5,800 psi, which is close to the capacity of surface

facilities. This is 42% more than Sarqala-1 produced prior to the acid treatment and is being achieved with only a 220 psi pressure drawdown in the reservoir.

Sarqala lies in Garmian Block, a 1,780-sq-km permit that contains the Sarqala and Mil Qasim oil finds. Garmian’s 2P reserves increased by 60% in Q1 to 51.75 MMbo based on Sarqala-1’s well data and better understanding of the Sarqala Jeribe and Upper Dhiban reservoirs. Gazprom Neft will drill Sarqala-2 in 3Q17 and Sarqala-3 in 2018. Garmian is owned by Gazprom Neft (40% WI, operator), WesternZagros (40%) and Kurdistan (20%).

Middle East & North Africa

260-MMboe project in PL 048 to start up without its FSO by the end of May.

April 2017 International Rig CountMarch-17 February-17 March-16

Land Off Total Land Off Total Land Off TotalEurope 63 31 94 69 38 107 58 38 96 Middle East 341 45 386 337 45 382 354 43 397 Africa 70 10 80 68 9 77 71 20 91 Latin America 150 35 185 147 32 179 178 40 218 Asia Pacific 122 76 198 120 76 196 113 70 183 International 746 197 943 741 200 941 774 211 985

Source: Baker Hughes Inc.

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■ Engie is studying how best to develop the Cara oil discovery in PL 636 offshore Norway. The find could start production by 2020 under a fast-track development option that entails Cara’s oil being tied to the nearby Gjoa field as an entirely subsea solution. Cara is currently estimated to hold 40-80 MMboe. Engie (30% WI) operates with Idemitsu (30%), Tullow Oil (20%) and Wellesley Petroleum (20%).

■ Eni will shut in Goliat field offshore Norway in the Barents Sea during Q3 for maintenance and to complete unfinished work from start-up in March 2016. The work should last three to four weeks starting in September, but Eni concedes that it could take up to three months to finish. Goliat lies in PL 229 and is owned by operator Eni (65% WI) and Statoil (35%).

■ Europa O&G has identified several new prospects in FEL 2/13 offshore Ireland. Four are deemed significant while two, one a late syn-rift complex and the other a Middle Jurassic tilted fault block, are each estimated to contain over 200 MMboe. As a result, combined gross mean unrisked prospective resources for the license now stand at 1.8 Bboe (62% oil) across 10 prospects. Europa is sole owner.

■ Saffron Energy started producing gas from Bezzecca field onshore Italy at 1.0-1.4 MMcf/d. Bezzecca lies 30 km east of Milan in north Italy’s Cascina San Pietro license and will supply a nearby production plant at Vitalba. Saffron, a wholly owned subsidiary of Po Valley Energy (90% WI), operates the license with Petrorep (10%). Bezzecca is estimated to contain 25.3 Bcf 3P reserves.

■ TGS will soon start a new multi-client acquisition project offshore Ireland. The Crean 3D survey will cover more than 5,400 sq km of the South Porcupine Basin between the Porcupine High and the Irish Mainland Platform and will provide the higher spatial resolution required to delineate multiple plays at multiple levels. Acquisition is expected to commence in June with processing and data delivery to follow thereafter.

Of particular interest, says NPD, are the areas known as the Storbank High, Sentralbank High and Kong Karl platform—all of which NPD Director General Bente Nyland said contained exciting structures. Although the new estimate will increase interest in the region, there are two big obstacles to drilling. The most immediate is that the northern Barents is currently not open to explorers for environmental and climatic reasons. Norway’s parliament

would have to change that and it is unclear if there is the political will to do so.

The second is the high cost of operating in undeveloped Arctic waters, especially the deepwater, which combined with low prices may dampen company enthusiasm. Tough economics have already led to a retreat from Arctic waters elsewhere in the world, and in the southern Barents, where drilling is permitted, work has proven costly and slow. So far only two fields—Eni’s Goliat and Statoil’s Snohvit—have

started producing in this region while a third project, Statoil’s Johan Castberg discovery, remains on the drawing board.

Still, drilling continues. This year will see 15 wells drilled—a record number for the frontier region. Statoil will drill five or six of these wells this year, starting with a well on the Blaamann prospect in PL 849. The campaign will also see Statoil drill the northernmost well ever drilled at the Korpfjell prospect in PL 532, which may contain over 2.2 Bboe. Other companies drilling this year include Eni, Lundin Petroleum and OMV, near, respectively, Goliat field, the Alta and Gohta finds, and the Wisting discovery.

North Sea & Western Europe

Norway says Barents Sea holds over 17 Bboe Continued From Pg 1

Barents now contains 65% of total remaining resources offshore Norway.

Still big obstacles to drilling north Barents but firms are active in south.

Top Global Oil Producers Oil Production (Mbopd) Rig Count

Feb 2017 Jan 2017 Jan 2016 Feb 2017 % Change YOY

Russia 10,771 10,512 10,476 - -Saudi Arabia 10,011 9,748 10,220 120 -6%USA 9,017 8,835 9,147 754 50%Iraq 4,566 4,630 4,458 40 -18%Iran - 3,920 3,385 - -China 3,901 3,901 4,161 18 -28%Canada 3,227 3,166 3,104 175 95%Kuwait 2,705 2,710 3,000 59 37%Brazil 2,681 2,692 2,338 14 -60%Venezuela 2,248 2,250 2,500 54 -22%Mexico 2,022 2,026 2,215 16 -59%Nigeria 1,818 1,914 2,117 7 17%Angola 1,649 1,615 1,767 3 -63%Norway 1,637 1,645 1,662 16 -11%Kazakhstan - 1,416 1,357 - -Algeria 1,084 1,091 1,138 50 -4%Oman - - 1,019 57 -20%UK 979 948 997 11 57%Colombia - - 922 22 214%Malaysia 750 733 708 3 -40%

Source: Joint Organisation Data Initiative.*Global total only includes countries with reported volumes

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Volume 09, No. 06 5 e&PTAQA expects to see first oil at Atrush in Kurdistan during Q2

TAQA completed construction of Atrush field’s facilities in Iraqi Kurdistan. Final commissioning is ongoing, and so far four wells have been completed and tied to infrastructure. Commercial production is slated to start soon at the 30,000 bo/d project,

which is waiting on completion of the 35-km feeder pipeline that will connect Atrush with Kurdistan’s main export pipeline to Turkey.

Atrush was to have started up in Q1 with first oil reportedly imminent in February, but operations were delayed for unknown reasons. Earlier delays in the field’s development had been caused by a contract dispute, technical issues and ISIS security threats. These problems seem to have been resolved, and Atrush is on course to begin production in Q2.

McDaniel & Associates pegs Atrush resources at a gross 1.5-2.8 Bbo, while 2P reserves are estimated to be 85 MMbo. Oil ranges in grade from heavy to medium (16-25° API) depending upon the formation being tapped. The field is owned by TAQA (39.9% WI), ShaMaran Petroleum (20.1%), Marathon Oil (15%) and Kurdistan (25%).

■ Genel Energy will commence a 2D seismic campaign on the Odewayne Block onshore Somalia in Q2. About

500 km of data needs to be collected for the permit’s third exploration period,

rising to 1,000 km in period four. One well must also be drilled during the fourth period. Odewayne covers 22,840 sq km of Somaliland in north Somalia. Genel (50% WI) operates with Sterling Energy (36%) and Petrosoma (16%).

■ Sharjah National Oil Corp. contracted WesternGeco to carry out a 483-sq-km 3D seismic survey over part of Sharaja’s onshore concession in the UAE. The survey is an extension of a previous survey conducted in 2011 and, like the previous one, will use the UniQ land seismic acquisition platform to manage the long offsets required to image the complex overthrust geology in the area. Data processing will be carried out in Abu Dhabi.

■ Sound Energy will enter a new exploration period for its onshore blocks in Morocco later this year, after

which the company will carry out a large geophysical study. The company will collect 2,600 km of new 2D and

24,000 sq km of gravity gradiometry data covering the TAGI and Paleozoic zones across the Tendrara and Meridja permits over 12 months. Sound (47.5% WI) operates with Schlumberger (27.5%) and ONHYM (25%).

Middle East & North Africa

Eni power problems in Libya prevent El-Feel restartEni is ready to resume production at El-Feel oil field in Libya after two years, but it

remains shut because of a power-generation problem. Power generation at El-Feel, also known as “Elephant,” relies on crude from Sharara oil field, Libya’s largest, but an equipment problem is preventing crude shipments, putting El-Feel and Sharara crude under force majeure.

El-Feel has a capacity of 80,000 bo/d, but it has been shut down since April 2015. Eni is part of a JV with the Libyan NOC that operates the field. The field was originally scheduled to reopen in December but a benefits dispute with guards kept the field closed, the NOC said.

Libya was producing 490,000 bo/d as of April 11, compared with 1.6 MMbo/d before the 2011 revolution. While Libya is a member of OPEC, they are not bound by the cartel’s production cuts because of the internal strife.

Lukoil to increase West Qurna to 550,000 bo/dLukoil’s initial development of Iraq’s West Qurna field has reached its Phase 1 goal

of 400,000 bo/d, and now the company is getting ready to implement Phase 2. Phase 2 will increase West Qurna’s production by 37.5% to 550,000 bo/d, or about halfway to Iraq’s ultimate goal of producing 1.2 MMbo/d from the field. Phase 2 will consist of drilling 91 wells, 25 of which will start being drilled in 2017 as part of Lukoil’s planned $1.5 billion investment into West Qurna this year. Supporting the

work is 450 sq km of new 3D data. In addition to the wells and

associated field infrastructure, Phase 2 will see expansion of the gas power plant and possibly the construction of a gas treatment facility intended to reduce flaring by capturing gas for sale. All this will cost $6.5 billion, which will bring Lukoil’s total investment into the field to $11-12 billion. However, an obstacle to this plan is Lukoil’s intention to renegotiate the contract governing the West Qurna concession in light of lower

oil prices and Iraq’s ongoing difficulties in financing oilfield development.

Lukoil (75% WI) took over West Qurna in 2010 after signing a 25-year service contract that ensures the company cost recovery plus a numeration fee of $1.15/bo. Production thereafter started in 2014, rising to 400,000 bo/d in January 2017. This took longer than expected due to delays in receiving payment from Baghdad—a problem other oil companies operating in Iraq have also encountered. Ensuring more timely payments is thus likely to be a centerpiece of any renegotiated contact. State-owned North Oil Co. owns 25% of West Qurna.

Was to have started flowing 30,000 bo/d in February but will now start up in Q2.

El-Feel & Sharara under force majeure, crude shipments still stopped.

Will invest $1.5 billion in 2017 into south Iraq field as part of Phase 2 build.

Lukoil to renegotiate contract in light of lower prices & delayed payments.Transactions

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TransGlobe eyes onshore Egyptian drillingOnshore Egypt, TransGlobe is constructing well sites in South Alamein’s Boraq area.

Work consists of drilling one well on the Boraq structure plus re-entering and retesting the Boraq-2 discovery well, which produced 1,600 bo/d from two zones in 2012. Successful appraisals could lead to filing of a development plan in Q2 or Q3 with first oil by YE17 or early 2018. TransGlobe will also carry out exploration drilling late in H2 targeting other

South Alamein prospects.Elsewhere in Egypt,

TransGlobe drilled two dry holes in North West Gharib. NWG-39 and -42 were drilled to 1,722 m and 1,951 m, respectively, with both intersecting thick Red Bed reservoir. However, the two wells were abandoned after the reservoir at these two locations were found to be water bearing. TransGlobe’s Egyptian production in 1Q17 was 13,940 boe/d—or 84% of the company’s total output. The remaining volumes were sourced from TransGloble’s Canadian properties.

TransGlobe is sole owner of both Alamein South’s 800 sq km, which lies in Egypt’s Western Desert, and NorthWest Gharib, a 655-sq-km license in the Eastern Desert that sits along the coast of the Gulf of Suez.

Middle East & North Africa

Occidental puts stalled Qatar project on front burnerOccidental Petroleum may soon launch a tender for the stalled Idd Al Shargi North

Dome project off Qatar. The slimmed-down project scope will consist of installation of surface facilities including conductor-supported platforms with nine slots each, 17 splitter wells and pipelines, umbilicals and brownfield work on existing infrastructure.

Up to 200 wells will be drilled, which will allow for continued production of about 100,000 bo/d.

Prior to being put on hold in 2015, Idd Al Shargi Phase 5 was projected to cost $3.0 billion and entailed the construction of two clusters of six wellhead platforms, a processing platform and other surface facilities. Under the revised plan, Occidental will likely put in place only one or two platforms with the remainder to be installed at a later date. This will cost less, but Occidental has not indicted how much this reduced project scope might save.

Idd Al Shargi lies 80 km north of Doha in 36 m of water. It was discovered in 1961 and peaked at 140,000 bo/d of heavy-to-medium sour crude in 1994. Occidental operates with Qatar Petroleum.

CNPC plans to double production at Al-HafayaCNPC started Phase 3 development of Al-Halfaya field in southern Iraq.

The work will consist of construction of gas separation facilities that will allow production to double from a current 200,000 bo/d to 400,000 bo/d. Iraq intends for the expansion to be completed in 2018, making Al-Halfaya Phase 3 an import part of

Baghdad’s plan to push output past 5.0 MMbo/d next year.

Halfaya Phase 2 started up in 2014 and reached the planned target rate of 200,000 bo/d in 2015, sourced from the 152 wells that have been drilled at the field to date. Planning for Phase 3 began shortly thereafter, but low prices led to media speculation that CNPC would be forced to delay the project or even shut in the field as uneconomic. Those fears seem to have been unfounded, however.

CNPC’s (37.5% WI, operator) partners on the project are Total (18.75%), Petronas (18.75) and South Oil Co. (25%). Elsewhere in Iraq, CNPC also participates in operating Rumaila field with BP and has partnered with ExxonMobil at West Qurna 1.

Appraisals in Egypt’s South Alamein concession could lead to Boraq find plan.

Planned gas separation plant will boost south Iraq field volumes to 400,000 bo/d.

$3.0 billion Idd Al Shargi Phase 5 will keep volumes at 100,000  bo/d.

Aminex gas find in Tanzania gets reserve boost

Aminex’s test of the Ntorya-1 and -2 gas wells in Tanzania led the company to increase its estimate of gross resources in

the area around the discovery. The Ntorya appraisal area is now thought to contain 466

Bcf in place, three times the previous best estimate of 153 Bcf that was made by LR Senergy in 2015. The Ntorya appraisal area covers 750 sq km of the Ruvuma license area.

Ntorya-2 reached 2,595 m in February and found 51 m of gross gas pay 74 m shallower than at Ntorya-1. The well was then deepened to 2,795 m TD and tested for 160 hours on various chokes, with the best result obtained using a 40/64-in. choke that produced 17 MMcf/d of dry gas with no formation water. In comparison, Ntorya-1 produced

20.1 MMcf/d plus associated condensate and formation water through a 1-in. choke in 2012.

Aminex is now eyeing drilling locations for Ntoyra-3 and -4, completion of which will satisfy the company’s license obligations. Once all four wells are drilled, Aminex can apply for a 25-year development license. Ntorya lies in the Ruvuma production sharing agreement, which is owned by Aminex (75% WI) and Solo Oil (25%).

Africa

Successful test boosts best estimate of Ntoyra’s resource potential by 313 Bcf.

After drilling four wells, Aminex may seek 25-year license.

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Volume 09, No. 06 7 e&P

SDX deepens Egyptian well after hitting gasOnshore Egypt SDX Energy’s SD-1X well found gas-bearing reservoirs in the Abu

Madi formation after reaching initial TD of 2,370 m. Altogether, about 20 m of net gas pay with 25% porosity was intersected in the Abu Madi, which was in line with pre-drill expectations. However, the well is being deepened to probe for oil in the Abu Roash and

AEB formations. SD-1X was drilled in Egypt’s South Disouq concession.

South Disouq lies onshore in the Nile Delta. Egypt recently granted SDX a six-month extension to the first exploration period for the block to Sept. 19. This will allow sufficient time for SD-1X results to be fully evaluated before deciding whether to enter into the second exploration period at the permit. South Disouq is owned by SDX (55% WI, operator) and IPR Energy Resources (45%).

Condor tests Turkish field well & preps for first gasCondor Petroleum completed and tested the Poyraz West-1 and Poyrz-5 wells

in European Turkey. At Poyraz West-1, the Sogucak carbonate reservoir tested at a stabilized rate of 2.0 MMcf/d in addition to the Lower Gazhanedere sands, which

had previously tested at a stabilized rate of 500 Mcf/d. With Poyraz-5, a Gazhanedere interval tested at 500 Mcf/d but neither a second

Gazhanedere zone nor a test of the Sogucak interval produced gas.

Next up at Poyraz, a rig is mobilizing to Poyraz West-4 and will soon begin drilling a development well that will have a 500-m lateral section in the Gazhanedere. Once finished at Poyraz-5, the rig will drill the Yakamoz-1 exploration well 2.0 km north of Poyraz field. Meanwhile, the construction of Poyraz’s 15 MMcf/d processing facility continues on schedule and should start up in mid-2017. Pipeline construction starts in early May.

Poyraz is a liquids-rich gas discovery currently pegged at 21 Bcf that lies on the Turkish coast near the Sea of Marmara in the Thrace Basin. Condor Petroleum is Poyraz’s sole owner and believes it contains much more gas than now booked.

Middle East & North Africa

■ Octant Energy plans to carry out a 2D seismic survey in Kenya’s Block 1, an onshore permit spanning 22,246

sq km along the country’s southeast coast that contains several oil seeps. The survey

will be used to target a location prior to the company’s first exploration well. Octant recently acquired both Block 1 and the L17-L18 license, also in Kenya, from Afren, which is in administration. Octant operates both permits.

■ Oranto Petroleum will start collecting 1,500 sq km of 3D seismic data from the St Louis Offshore Shallow concession offshore Senegal in July. The company is also reprocessing existing 2D data covering the Cayar Shallows Block with new 3D data. Oranto is sole owner of both permits and looking to farm down some of its stake. A data room has been opened and interest is high, Oranto said.

Africa

SDX's SD-IX Abu Madi Prospect• Robust ~1000 acre four-way dip closure

mapped on seismic data

• 175’ of structural closure at Abu Madi level

• Positive AVO response reduces risk of not encountering reservoir

• Deeper potential identified in Abu Roash and AEB zones which are prolific Western Desert oil producers

ytilauQ riovreseR gnisaercnI

Extent of SD-1X closure

SW NE

SD-1X

Source: SDX Energy Jan. 27 Presentation via PLS docFinder www.plsx.com/finder

Poyraz Ridge field in European Turkey headed for a mid-2017 start-up.

Finds 20 m of gas in Abu Madi & hopes to find Abu Roash & AEB oil.

Eland touts efficient recovery at Nigerian field

A report filed for Eland O&G by Netherland, Sewell & Associates points to a three-fold increase in recoverable

reserves attributable to existing wells at Opuama and Gbetiokun fields in

Nigeria, adding a gross 22.6 MMbo. Although this has not led to an increase if bookable reserves for OML 40 as a whole, increased recovery from existing wells means fewer infill wells will be required going forward.

OML 40 is now producing 8,000 bo/d, but Eland intends to push volumes there past 20,000 bo/d by YE17. OML 40 lies onshore in the Niger Delta Basin. In addition to Opuama and Gbetiokun, the block also contains Abiala, Adagbassa Creek and Tsekelewu fields. Together, Eland estimates they contain 160 MMbo. Eland (45% WI) operates with Nigerian Petroleum Development Corp. (55%).

Eland may be able to reach YE17 target rate of 20,000 bo/d with fewer wells.

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InternatIonal Scout 8 May 4, 2017

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■ Apache’s deepwater exploration well on the Kolibrie prospect off Suriname failed to find commercial pay. Kolibrie was meant to test the extent of the emerging oil play in the Guyana-Suriname Basin that was first opened up by ExxonMobil in 2015 and prior to drilling was estimated to contain 500 MMbo. Kolibrie lies in Block 53, which is owned by Apache (45%, operator), Cespa (25%) and Petronas (30%).

■ Interoil E&P’s Turaco-1 exploration well in Colombia found oil in the upper section of the C-7 formation at about 1,751 m MD. However, the lower section at 1,803 m was water bearing. Interoil will continue slickline testing of Turaco-1 in order to determine the size of the find. Meanwhile, a rig is mobilizing to drill the Vikingo exploration well, also in Block LLA-47. Interoil is sole owner.

■ Spectrum commenced a 35,000-km multi-client 2D seismic survey offshore Argentina. The data is being collected from a 435,000-sq-km deepwater area in cooperation with YPF and the Ministry of Energy to create the first-ever detailed seismic grid over this part of Argentina ahead of upcoming licensing rounds. The data will be processed with PSTM, PSDM and Broadband products with first deliveries in Q4.

Latin America

Over the next 12 months, Tatneft will develop six more shallow heavy oil accumulations at the field via a pilot steam assisted gravity drainage project similar to that seen at oil sands operations in Canada. About 600 wells have been drilled at Ashalchinskoye, 300 of which inject 20 tonnes of steam per day produced by 13

steam generators into reservoirs in order to allow for the viscous oil to be pumped to the surface.

The Lower Karmalskoye will be the first of these heavy oil deposits to be produced and is scheduled to come on stream in June. The other five, North Ashalchinskoye, South Ashalchinskoye, Greater Kamenskoye, Tuymetkinskoye and Karmalinskoye, will become operational in 2018. In addition, Tatneft is considering targeting another six heavy oil accumulations and could drill up to 100 more SAGD

well pairs in order to put them into production at a later date.

Altogether, Tatneft estimates it will produce about 31,500 bo/d of heavy oil in 2017—equivalent to 5.5% of the company’s total production last year. Tatneft’s heavy oil volumes will increase 20% to 38,000 bo/d in 2018 once all six of the heavy oil accumulations now being developed at greater Ashalchinskoye are producing. If the other six heavy oil deposits, plus others to be identified later, are also put into production, then total heavy oil production could hit 50,000 bo/d between 2020-2025.

Tatneft hasn’t let slip how much this production drive will cost, but there is some doubt about the company’s ability to finance it. Here, the company suffers from the usual combination of poor prices and lack of access to Western

credit due to sanctions but has the added burden of being the economic mainstay in its home area, which is undergoing a banking crisis. As a consequence, the government of Tatarstan is forcing Tatneft to bail out a range of non-core assets through over $1.0 billion in non-oil-related purchases.

Tatneft to expand Tatarstan production Continued From Pg 1

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December 31, 2014 • Volume 06, No. 15

InternatIonalCapItalServing the marketplace with news, analysis and business opportunities

TUNISIA PROJECT1-Permit. 556,481-Acres. (2,252km2)GHADAMES BASINContains One Discovery. FO8 Identified Leads: Silurian SandstoneSeismic Data Available.Also Re-Entry Project for 2-Wells. RE-ENTRYSEEKING JV PARTNER FOR -----EXPLORATION PROGRAM.Est Mean EUR: 57 MMBOEst Total In-Place Reserves: 385 MMBOExploration Term Expires April 2016.CA Required To View Data Room.CONTACT AGENT TO LEARN MOREFO 1022DV

OFFSHORE AFRICA FARMOUT1-PSC. 420,079-Acres. (1,700km2)SENEGAL & GUINEA-BISSAUAGC MARITIME COMMISSION ZONE DVContains One Identified Prospect.Shallow Water: 328 Ft. (100m)3-D Seismic Data Available. SHALLOW40% WORKING INTEREST AVAILABLEEstimated Reserves: 475 MMBOCA Required To View Data Room.CALL AGENT FOR MORE INFORMATIONDV 5234L

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Petrobras scandal, possible default spurs lawsuits

The ongoing investigation into the Petrobras scandal could soon have implications outside Brazil. That’s because the company and its executives have been named as the target of a new, $98-billion US class-action lawsuit alleging Petrobras made material misstatements about the value of

its assets. The suit, filed in Manhattan’s federal court on behalf of the city of Providence, Rhode Island by the Labaton Sucharow law firm, covers all securities Petrobras sold since 2010: including debt issued by Petrobras International Finance Co. and Petrobras Global Finance from February, 2012.

Oil-linked contracts put many LNG projects in limboWhile BG Group celebrates the loading of the first commercial cargo at its Gladstone

LNG plant on Queensland’s Curtis Island, the current pricing climate has already altered the fate of the Pacific NorthWest LNG megaproject in Canada and may affect investment

decisions in other large-scale LNG projects worldwide. While not an oil drilling project, conventional or otherwise, the $32 billion, multi-partnered Petronas-led effort has been put on hold as the Malaysian NOC defers a final

investment decision on the gas project with a list of entirely Asian prospective customers that are used to paying for LNG based on oil-indexed contracts.

With the drop in crude, LNG prices landing in Asia have now sunk below $10/MMbtu, down from $16/MMbtu as recently as April 2014. In North America alone, nearly 40 mtpa of LNG projects are under construction with another 30 mtpa expected to reach FID in the next twelve months. In Australia, LNG breakeven prices are $13-$14/MMbtu. Globally, as with oil, LNG landed prices will adjust to market dynamics.

Oil prices the scourge of noted investors in 2014Some of the world’s most astute and followed investors couldn’t escape the grip

that a slumped oil price had on various securities during 2014, and has given the $2.8 trillion hedge fund sector its worst year since 2008. Most notable is the loss

incurred by legendary activist investor Carl Icahn courtesy of his investment in Talisman Energy, now prepping for a

Repsol takeover (see story on page 7). After accumulating more than 7% of Talisman’s shares and gaining board seats

and influence in the company, the golden Icahn touch was no match for oil prices this year—his almost $900 million investment was down $540 million until the Repsol offer and the resulting share price boost cut his losses down to $286 million. His company’s total portfolio was up 4.4% through the end of Q3, filings show. Looking at his Talisman experience, Icahn told the Wall St. Journal: “In this oil environment, I’m certainly glad a bidder came along for it.

Analysts assess project risk at various price pointsIn perhaps the most extreme prognostication to date, Goldman Sachs analysts

say $1.0 trillion in projects could fall by the wayside as $60/bbl Brent renders certain higher-priced projects around the world unprofitable. Projects aggregating $930 billion worth of future investment were no longer profitable with Brent at $70/bbl, the investment bank said, and that $10/bbl less would push that number to the $1.0 trillion

mark. The Goldman analysis looked at 400 of the world's largest new fields excluding US shale.

Led by Canadian oil sands projects at $80/bbl and certain US shale plays and other tight oil plays at $76, Energy Aspects say more than 12% of global oil production would be uneconomic if the majors were to move forward on existing projects at today’s prices. Brazil’s deepwater fields just wouldn’t be worth the expense at $75 and Mexican projects would cease to be profitable at $70. The group told the Financial Times it believes 1.5 MMbopd of the world’s planned 2016 projects are at risk at $70 and that over 1.0 MMbopd of 2017 projects are chancy at that price point.

Goldman estimates that more than $1.0T in projects are at risk at current prices.

Icahn's investment was down 40% at one point before rebounding somewhat.

LNG prices in Asia now below $10/MMbtu, disturbing to profitability.

S&P says Petrobras would be junk-rated if not for government support.

Continues On Pg 4

Continues On Pg 6

Continues On Pg 10

Continues On Pg 12

Tatneft finances strained on use as regional ATM machine.

InternationalCapital April 27

Heavy oil SAGD development will be an important part of production drive.

Some question how Tatneft can finance production plans.

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Kazakstan may revive Kurmangazy field plansKazMunayGaz and Rosneft may restart work on the cross border Kurmangazy

field in the North Caspian Sea. Kurmangazy is a 7.0-10-Bboe, shallow-water field that lies west of Buzachi Peninsula in Kazakh waters that has long gone undeveloped due to conflicting claims to the area by Russia and Kazakhstan. A 2005 agreement

created a joint operating company, Kurmangazi, to run the field, but initial exploration stalled after the first well drilled turned out to

be a dry hole. Two more wells were to follow, but they were either never drilled or their results

were not reported. In the years since, a draft protocol to introduce amendments to the 2005 PSA governing the field was introduced. If signed by Kazakhstan, the two countries will be able to add

more acreage to the PSA without changing terms and conditions while also giving Kurmangazi two additional terms of six and four years, respectively, for appraisal and exploration.

Kurmangazy, billed as Kazakhstan’s third-largest oil field, is owned 50:50 by KazMunayGaz and Rosneft through Kurmangazi.

FSU & Eastern Europe

Work at 7.0-10 Bboe Kurmangazy stopped after initial wells turned up dry.

Original joint operating company created in 2005.

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Volume 09, No. 06 9 e&P

YPF & Schlumberger ink Argentinian shale pact

YPF and Schlumberger will work together on a Vaca Muerta shale pilot project. Under the terms of the agreement, the pair will invest $390 million to carry

out technical studies, drill 26 pilot wells and build

field infrastructure in Neuquén province’s Bandurria Sur Block. YPF will remain operator and retain 51%, while the oilfield services giant will gain a 49% stake in the concession by making a series of in-kind contributions of its services at market price.

YPF’s deal with Schlumberger was the latest in a series of agreements to develop Neuquén’s shale. Last month the company signed a $500 million agreement with Pan American Energy, Total, and Wintershall covering the Aguada Pichana area. The new agreement with Schlumberger also follows a deal with Shell at Bajado de Anelo, where Shell promised to spend nearly $300 million on a two-phase shale pilot project.

Karoon preps Echidna for early production in 2019

Activity is heating up to develop Karoon Gas’ Echidna light oil discovery offshore Brazil. The company plans to drill

two appraisal wells in Q2 and eyes the installation of an early-production system over the next

two years. Karoon awarded Wood Group a multi-year, engineering services contract intended to support full-field development—particularly for the field’s planned floating production unit and subsea package.

Echidna, which is in Block BM-S-62, will be developed via five wells—three extended-reach producers and two water-alternating-gas injectors. All will be connected to an 80,000 bo/d FPU. First oil is slated for 2020. In Phase 2, Karoon will bring the nearby Kangaroo find in BM-S-68 on stream through the drilling of five more wells. Altogether, 125 MMbo will be developed. Karoon is sole owner of both discoveries.

Latin America Total to produce over 500 MMcf/d from Vaca MuertaTotal sanctioned Phase 1 development of the eastern part of the Aguada Pichana

license in Argentina. The Vaca Muerta shale project greenlight comes shortly after Total, BP subsidiary Pan American Energy and Wintershall asked Argentina to split the region in two, with Total taking charge of the east while Pan American operates the west. So far Total has drilled 10 wells, which are producing a combined

60 MMcf/d of dry gas. Phase 1 development will

consist of 100 wells, drilled in batches of 20, which would lift production to 565 MMcf/d and allow for local infrastructure to reach full capacity. However, follow-on work would include drilling 1,000 wells and building processing facilities. Total hasn’t said how much gas this larger program might produce from Aguada Pichana, but the economics are certainly compelling.

In terms of productivity, Total has concluded that 1,500-m laterals there have IP rates of up to 10 MMcf/d with cumulative production curves comparable to that found in the US’ Haynesville shale play

in northern Louisiana. Supporting these positive rates are attractive financial terms since gas prices have been guaranteed under a recent deal struck by Argentina with oil and gas companies. The agreement offers a subsidized price of $7.50/MMbtu produced from new wells through 2020—double NYMEX’s current front-month contract.

As a result of these attractive terms, Total has designated Aguada Pichana Este as one of just 10 major projects that the supermajor will sanction in 2017-2018. Total also intends to boost its working interest in the permit. The company recently signed an MOU with the other Aguada Pichana partners, YPF (27.27%), Wintershall (27.27%) and Pan American Energy (18.18%) to increase Total’s working interest in Aguada Pichana Este from 27.27% to 41% in order to further benefit from the development.

Latest YPF Vaca Muerta deal will see 26 wells drilled in Bandurria Sur.

Supermajor’s greenlight of work in Aguada Pichana to see 100 wells drilled.

Ultimate aim of effort is to drill up to 1,000 wells.

Will be just one of 10 projects that Total’s E&P arm will sanction in ’17-’18.

That May, the Bajo del Choique X-2 well reached 4,572 m MD in Bajo el Choique Block. On test, it produced 770 bo/d on a 12/64-in. choke. This was followed in Dec. 2014 by the La Invernada X-3 in the La Invernada Block. That well flowed

630 boe/d (70% oil). Exxon is also

teaming up with other Vaca Muerta players. In January, Argentine power company Pampa Energia said it will drill its first Vaca Muerta well this year in a JV with Exxon on the Parva Negra East Block.

As part of the deal, Exxon will re-enter an already perforated vertical well to drill horizontally and then turn the well over to Pampa after completion.

Pampa said it aims to expand its relationship with XTO to other Vaca Muerta projects.

Exxon’s Vaca Muerta push comes after announcing in Q1 that it will invest $5.5 billion, or about 25%, of its 2017 capex into US shale. In the US, the supermajor will focus on the Permian and Williston basins, where the company’s inventory of over 5,000 wells has a rate of return over 10% at $40/bbl WTI. Exxon hopes that the expertise it has gained in drilling these US shale wells can be applied in the Vaca Muerta—the biggest shale producing region outside North America.

Exxon builds on shale strategy Continued From Pg 1

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Petro ScoutMay 21, 2015

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REEVES CO., TX PROSPECT ~4,600-Net Acres.DELAWARE BASINObjectives: Wolfcamp (A,B,C)All Depths. All Rights. L80-Acre Down Spacing Pilots Underway.Subsurface Geology Data Available100% OPERATED WI; 75% NRI WOLFCAMPWolfcamp A Approx. IP: ~1,091 BOEDWolfcamp B/C Approx. IP: ~1,190 BOEDWolfcamp EUR’s: 300-450 MBO/WellPKG UPDATED WITH NEW ACREAGEL 5187DV

COLORADO DRILLING PROJECT~43,700 Net Acres.LINCOLN & KIT CARSON COUNTIES MISSISSIPPIAN / PENN TARGETSMiss-Spergen & Penn-Cherokee. <7,500’. LMultipay Objectives. Shallow Depths.Defined By Extensive 3-D Seismic-- MULTIPAY-- Geology & Geophysics Data.100% OPERATED WI; ~80% NRI221 Active Offset Wells, 150 Offset Permits.L 4489DV

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Hess’s Bakken costs falling, targeting $6.0-6.5MM/well

Hess’s lean manufacturing approach in the Bakken is leading to higher production and cheaper wells. Q1 volumes averaged 108,000 boe/d, up 70% YOY and 6% sequentially. A total of 70 wells were brought online in the play during the quarter, down from 96 in Q4. Well costs fell to $6.8 million from $7.1 million in Q4 and

$7.5 million in 1Q14. Hess expects costs to fall further, with 2015 wells averaging $6.0-6.5 million.

During Q1 Hess reduced its Bakken rig count to 12 from 17 at the end of 2014. The company is running currently eight rigs in the play and will continue with that number for the remainder of the year. D&C plans call for 178 wells drilled, 214 completed and 213 turned to sales compared to 261, 230 and 238 last year, respectively.

Noble’s DJ Basin spud-to-rig release days fall to seven In the DJ Basin, Noble Energy has driven spud to rig release times for 4,500-ft

laterals down to just seven days as of Q1, a 23% reduction YOY. Notably, the company drilled a 9,280-ft lateral in just seven days.

“We’re now averaging seven days from spud-to-rig release for a standard lateral length well, almost as fast as we used to drill vertical wells,” said chairman, president

and CEO David L. Stover during a conference call.The company is drilling

wells so quickly that it will end up drilling more wells than anticipated in 2015 and has taken funds from the Marcellus and reallocated them to the DJ. Currently Noble is drilling 70% of the footage of 2014 with 40% of the rigs. The company ended Q1 running four rigs and one completion crew in the DJ. In H2, an additional completion crew will be added as needed.

Reduced drilling times and equipment optimization has led to a 5-15% reduction in costs vs. 2014. Noble foresees further savings via lower service costs and possible use of slickwater, which could save $2.0 million per well.

Parsley’s rookie hz drilling season delivers peer-leading resultsParsley Energy’s well performance has continuously improved since it began

drilling horizontal wells a year and a half ago. The company has drilled 30 Wolfcamp A or B wells thus far and, based on the 30-day data, recently introduced a type curve with

estimated recoveries of 1 MMboe. In the Wolfcamp B during Q1, the 30-day peak IP per 1,000 ft of lateral improved 30% YOY to 231

boe/d. According to COO Matt Gallagher, the improved performance is owed to higher stage density, more slickwater stages, increased proppant per stage and optimal placement of the lateral within the zone.

Parsley’s improved wells are outperforming many of its peers in the Midland Basin. In Upton County, the company’s Wolfcamp B 24-hr IPs are 75% higher than the average when adjusted for lateral length. The Ratliff-28-1 H Wolfcamp B well is credited with flowing the highest reported oil rate of all horizontals in Upton, according to IHS. In Reagan County, data suggests Parlsey’s 24-hr IPs for Wolfcamp B wells are 55% higher than the county average when adjusted for lateral length.

Devon surges past guidance on Eagle Ford performanceCompletion mods push positive results across multiple plays

Fueled by the Eagle Ford, Devon’s oil production exceeded guidance by 12,000 bo/d during Q1 at 272,000 bo/d. Based on the results, the company has increased its oil growth target from 20-25% to 25-30% (270,000 bo/d) for the full year. Q1 overall

volumes also overshot guidance, averaging 685,000 boe/d (60% liquids), up 3% vs. Q4 and 22% YOY. Devon expects volumes to grow 5-10%

this year to an average of 667,000 boe/d. Capex was reduced by $250 million to $3.9-4.1 billion on an improved LOE outlook and accretive midstream transactions.

Since it took control of the Eagle Ford position it acquired from GeoSouthern in March 2014, Devon has grown production in the play 140% to 122,000 boe/d (62% oil). In the last quarter alone volumes jumped 24,000 boe/d, exceeding expectations and creating a bottleneck that will prevent growth in Q2.

Devon’s Eagle Ford drilling is concentrated in the Lower Eagle Ford where the company added 79 new wells to production in Q1.

Eagle Ford output has risen 140% since it took over the assets in March 2014.

Continues On Pg 4

Continues On Pg 21

Continues On Pg 6

Bakken well costs stood at $7.1MM at YE14, already down to $6.5MM in '15.

Continues On Pg 22

Noble nearly drilling horizontals in the time it used to take it to drill a vertical.

Wolfcamp B rates are 75% higher than peers in Upton County.

Exxon poised to execute on shale with ‘Permian prize.’

PetroScout Mar. 15

Aims to produce up to 350 MMcf/d from Nequen Basin shale by 2020-2021.

Mirrors US plans where supermajor will spend 25% of 2017 capex on shale.

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■ Carnarvon Petroleum is reprocessing 3D data collected from WA-524-P and WA-523-P offshore Australia. Data produced so far shows encouraging results over Triassic intervals in WA-523-P, which contains the deactivated Buffalo oil field, and should significantly derisk future exploration in that license. Carnarvon also plans to collect 3D seismic in WA-521-P, targeting the Labyrinth prospect. Carnarvon is the sole owner of all three Western Australia blocks.

■ Senex’s Silver Star-1 exploration well in South Australia found gas. The well reached 3,770 m and discovered gas shows in the primary Patchawarra sands as wells as in the secondary Toolachee and Epsilon formations. Multi-stage fracture stimulation and testing of the well is expected to follow shortly. Silver Star-1 lies in PEL 514 and is owned by Senex (53.75% WI), Origin Energy (33.75%) and Planet Gas (12.5%).

New appraisals to help Conoco decide on Australia gas findResults from a recent ConocoPhillips well drilled to assess the Caldita-Barossa

gas discovery offshore Australia may push the find toward an FID over the next two years. A two-well appraisal campaign at Caldita-Barossa started in Q1 with work at the

first well, Barossa-5, having wrapped up in late April. Analysis of results from Barossa-5 is ongoing, but partner Santos has

indicated that the well confirmed substantial gas accumulations and that the rig will now move to drill Barossa-6 once Barossa-5 is plugged and abandoned.

The last major round of appraisal work carried out at Caldita-Barossa occurred in 2015, when Barossa-3 intersected a gross 152 m of gas pay after Barossa-2 found 92 m of net gas pay in late 2014. Results from Barossa-4, which was also drilled in 2015, haven’t been released, but were reported by the trade press at the time as being successful. Barossa-1 was drilled in 2006 to 4,310 m, hitting gas in the Upper Elang, Lower Elang and Plower reservoirs, and subsequently testing at 30 MMcf/d

with a high CO2 content of 16%. Work to date points to Caldita-

Barossa being a multi-Tcf deposit that is of sufficient size to be a good candidate for tie-in to Conoco’s Darwin LNG project, which the company is considering expanding to two trains. This February, Caldita-Barossa’s partners signaled that initial engineering and design work would start in late 2017 with a FID to follow in late 2018 or early 2019. Development is currently centered on an FPSO-based concept, but as of 3Q16, Conoco admitted that Barossa’s CO2 remains a challenge that has yet to be solved.

Caldita-Barossa lies in the Timor Sea off Australia’s Northern Territory in Block NT/P69, 270 km northwest of Darwin. Water depths there are 230-350 m. Conoco (37.5% WI) operates with SK E&S (37.5%) and Santos (25%).

South Pacific

Latin America

Empire optimistic about Red Gully despite low assessment

Empire O&G’s Red Gully North-1 discovery in Western Australia has found less oil than initially though. PLS reported in March that the well reached 4,410 m in EP 389, where it intersected 53 m of net gas pay in the C and D sands of the Cattamarra coal measures and produced 405 bo/d at 2,700 psi with no detectable drop in reservoir pressure during a short-period test. Now, Empire’s analysis shows the oil exhibits high shrinkage, leading to a lower-than-expected 2C estimate of 570,000 bo in place in the C sand and 3.1 Bcf in the Upper D.

Although the well found less oil than expected, the company still believes the find indicates a larger oil play in the Upper Cattamara C sand in EP 389 and PL 18/19, both of which are close to Empire’s existing production hub. Empire will now carry out an extended, 90-day well test starting in Q3 to gather more information. The test will help assess the gas volumes in the D sand as well as the commercial significance of the Red Gully oil play. Red Gully North-1 lies in EP 389 and is owned solely by Empire.

Five wells drilled since 2006 point to a multi-Tcf discovery a Caldita-Barossa.

An FID based on a FPSO concept may come sometime in 2018 or 2019.

Amerisur well shows Colombia field has more oil

Amerisur Resources’ Platanillo-22 well in Colombia has revealed a new closure at the field. In March the well intersected a gross 15 m of net oil pay in three sections across the N, Upper U and Lower U sands in addition to oil shows in the M2 and T formations. Now, Platanillo-22 has been tested at 613 bo/d (31.5°API) with less than

a 1.0% water cut from a 4.0-m interval in the Lower U sand through use of a hydraulic lifting system.

Importantly, the oil-water contact was found 11 m deeper in the Upper U sand and 7.0 m deeper than in the Lower U. This suggests that the oil accumulation at Pad 2N has separate closure from Pad 3N and the greater depth. As a result, provisional re-mapping of the field indicates potential for up to 7.82 MMbo recoverable reserves within Pad 2N’s structure as compared to the

previous estimate of 1.4 MMbo. To confirm the suspected closure,

Amerisur is now drilling Platanillo-21 as a short deviation directional well aimed at the crest of the mapped structure, with a drilling offset of 76 m and planned total depth of 2,586 m. Drilling and coring should be completed in 27 days. Platanillo field lies in south Colombia’s Putumayo Basin. Production at the end of Q1 averaged 4,345 bo/d. Amerisur is sole owner.

The Platanillo-22 well intersected the OWC deeper than expected.

Amerisur's well being drilled to confirm suspected closure.

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Volume 09, No. 06 11 e&P

Thalin in Block AD-7 and the Shwe Yee Htun are estimated to contain a combined 2.4 Tcf. Both were discovered in 2016 after exploration wells intersected 62 m of net pay at Thalin-1A and 15 m of net pay at Shwe Yee Htun-1. Although still early, Woodside and partner Daewoo are already eyeing development options. The pair is

believed to favor a plan that would see the Thalin gas discovery put on stream as a tie-back to Daewoo’s 6.0-Tcf Shwe field, which is

being upgraded. Shwe now produces 500 MMcf/d from 15 wells linked to a central processing

platform. Shwe Phase 2 will see one subsea manifold and three wells emplaced at both Mya South and Shwe Phyu, but at the latter field the manifold will leave open one additional well slot. Both will be linked via a 12-in., 20-km pipeline to facilities at Shwe. Not included in the project expansion is a compression platform, which had been in the works but is being deferred until market conditions improve.

Woodside owns 40% WI in Block AD-7 and is the deepwater operator. Daewoo owns the remaining 60% WI and

operates in all other respects. Block A-6’s working interest is held by Woodside (40%, operator), Total (40%) and MPRL E&P (20%). Water depth in the two blocks runs to 900 m and 2,500 m, respectively. Shwe lies in Myanmar’s Block A-1 in the Arakan Sea near the border with Bangladesh. Water depth runs to 110 m. Daewoo (51% WI) operates with Moge (15%), ONGC Videsh (17%), Kogas (8.5%) and Gail (8.5%).

Shell finds oil in new trap type at Brunei fieldShell made its first significant onshore discovery in Brunei in 37 years and notes

that the find is likely bigger than the 18 MMboe pre-drill estimate. The supermajor’s Layang-Layang well was drilled in Seria field to 4,319 m in order to test a new play type. The well confirmed a shale diapir trap that was interpreted from seismic data and field outcrop studies. Log evaluation shows Layang-Layang intersected a gross 300 m

of oil and gas pay over six reservoir intervals, all with good-quality sands. A shale diapir is a large

cavity injected with pay under high subsurface pressure and has never been considered a valid trapping in Brunei. Well data will help calibrate Shell’s geological model of the new trap and aid in narrowing down potential drilling locations for three more wells that will drilled over 2017-2018. Looking ahead, Layang-Layang will now be appraised with an eye toward first oil in 2018 via pipeline connection to Brunei LNG and Sungai Liang Industrial Park, which lies 10 km from the well.

Seria is in the Lumut area and is Brunei’s first and oldest field. It was discovered in 1929 and put in production shortly thereafter. Field volumes peaked in the 1950s at 115,000 bo/d, declining to just 24,000 bo/d in 2004. The field lies in a coastal region and consists of both an onshore and offshore component, with the offshore portion featuring water that runs 2.0-10 m deep. Shell operates and splits Seria’s working

interest 50:50 with Brunei.Offshore Brunei, Shell is expected to

soon issue a three- to five-year contract for a jackup rig to carry out drilling and decommissioning work, with up to two additional jackup rigs likely to be hired to do similar work on a three-year contract thereafter. Shell is also looking to hire a semi-submersible drilling rig through a rig-sharing plan with Mubadala Petroleum for work in water 45-450 m deep. This rig would drill six wells, four for Shell and two for Mubadala. Shell has not indicated where the rigs would drill.

Asia

PTTEP eyes pipe to shore over FLNG at Cash-Maple

PTTEP looks to be switching gears at the Cash-Maple gas accumulation off Australia’s Ashmore & Cartier

Islands. Under a plan proposed earlier this decade, PTTEP was to build a 1.5-2.0 mtpa FLNG project to develop

an estimated 600 Bcf of recoverable resources in Block AC/RL7, which lies 700 km from Darwin. However, this required the company to prove up the find to at least 2.0 Tcf, something that PTTEP has failed to do despite Cash-2 and Maple-2 testing at 28-30 MMcf/d in 2011 and 2012.

Now, an LNG glut and the prospect of commodity prices staying low for some time have forced a shift away from the FLNG concept. The new plan consists of piping Cash-Maple’s gas to an existing project that has yet to be identified. To help find a destination for the gas, PTTEP contracted Neptune Marine Services to acquire survey and geotechnical data on possible export pipeline routes from Cash-Maple. PTTEP hasn’t indicated how long the study may take, but with its license now extended until 2021 the company has time to consider its options.

Cash-Maple lies in the Timor Sea’s Vulcan sub-basin in water 90-305 m deep. It is owned by operator PTTEP (80% WI) and Cue Energy (20%). Cash and Maple were discovered, respectively by BHP in 1989 and El Paso in 2002. PTTEP took over the license in 2009.

South Pacific

Woodside produces 50 MMcf/d in Thalin Continued From Pg 1

Probe of a shale diapir at Seria field yields a gross 300 m of pay.

Shell expects the Layang-Layang discovery to see first oil in 2018.

Thalin likely to be tied to Daewoo’s 6.0-Tcf Shwe project in the Arakan Sea.

Woodside owns 40% WI in Blocks AD-7 and A-6.

1.5-2.0 mtpa FLNG unit to be nixed in favor of cheaper option for 600 Bcf find.

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■ Oilex commissioned studies by Schlumberger and Baker Hughes on how best to increase production from the Cambay gas field in Gujart, India via stimulation of the tight EP-IV reservoir. In addition, Oilex intends to carry out two workovers this year in the shallower OS-II conventional reservoir in order to reestablish flow from this historically productive zone. Oilex (45% WI) operates with GSPC (55%).

■ China produced 3.88 MMbo/d during 1Q17, down 80,000 bo/d from December 2016, but this is still above September’s 3.8 MMbo/d low. Meanwhile, the commerce ministry reports China had 256 MMbo in its strategic reserve as of mid-2016. China also said it will stop accepting new applications from refiners to use imported oil May 5. Previous to this, 22 independent refiners had been allowed to import oil since 2015.

Santos changes Ande Ande Lumut plan Santos is amending its approved development plan for the Ande Ande Lumut

heavy-oil discovery off Indonesia to take into account results from the last year’s AAL-4X appraisal well. The original plan focused solely on the K-sands, estimated to contain a recoverable 101 MMbo. The G-sand was successfully appraised by AAL-4X in July 2016, helping to prove that it held 289 MMbo in place with 36 MMbo being recoverable—increasing the overall size of the development by 35% to 136 MMbo.

More oil won’t mean an upsized

project, however. Santos is studying options for co-mingled production from the two sands with early results looking promising. This means that there will be little change needed to the planned production and processing infrastructure, which consists of a leased, standalone FPSO tied to a 48-slot wellhead platform. Submitting and then receiving approval for the amended plan will take some time, though, which will push back a FID, planned for 1H17, to 2018.

Ande Ande Lumut lies in the Northwest Natuna Sea production sharing contract. Once on stream it will initially produce 25,000 bo/d, rising thereafter to reach 40,000 bo/d. Water depth is 75 m. Santos operates with 50:50 partner AWE.

Repsol Vietnam nears FID for Cá Rong Do off Vietnam The field development plan for Repsol’s Cá Rong Do project offshore Vietnam

has been approved by Hanoi, paving the way for a final investment decision in H2. Cá Rong Do, also known as Red Emperor, sits in North Natuna Sea Block 07/03 and is estimated to contain a gross 79 MMboe (60% oil). Development will consist of the drilling of 12 wells plus installation of a tension-leg wellhead platform tied back to a leased FPSO capable of 25,000-30,000 bo/d and up to 130 MMcf/d. Total project cost

is estimated at $1.1 billion,Cá Rong Do will also

feature a unique platform design. Repsol will install a three-leg TLWP at the field, making the project not only the first such TLWP-based development in Vietnam but also the only one in the world to feature a TLWP with three legs. The platform will be erected in 320 m of water depth and host up to 20 wells. Contract awards for the TLWP’s construction and installation and the supply of the FPSO are currently being finalized by Repsol with formal awards to Keppel FloaTEC and Yinson Holdings, respectively, expected soon.

Meanwhile, Repsol executed a $5.0-million deal with project partner Pan Pacific Petroleum to buy Pan Pacific’s 5.0% stake in Cá Rong Do. After closing, Repsolʼs interest will be a 60% operated stake with Mubadala Petroleum subsidiary Pearl Energy owning 25% and PetroVietnam retaining 15%.

Asia

Husky to drill three South China Sea wells in 2018Husky Energy signed a production sharing contract for a new exploration

block offshore China. Block 16/25 is in the Pearl River Mouth Basin, about 150 km southeast of Hong Kong. The company expects to drill two exploration wells in the permit during 2018 in conjunction with two planned exploration wells at nearby Block

15/33, which Husky also owns. Water depth is 80-100 m.

Husky operates both blocks with 100% WI during exploration phase. In the event of a discovery, CNOOC may assume a participating interest of up to 51% during the development and production phases. In addition to blocks 16/25 and 15/33, Husky’s interests offshore China include a 49% operated stake in the Liwan gas project and a 40%, non-operated interest at Wenchang field. CNOOC is the sole partner at both assets.

Drilling will take place in Block 15/33 and the newly acquired Block 16/25.

79-MMboe Cá Rong Do will feature the world’s first three-leg wellhead platform.

Success at last year’s AAL-4X appraisal adds 36 MMbo in G-sands oil.

Nido Petroleum sidetracks Philippines well

Nido Petroleum’s Galoc-7 sidetrack intersected a 115-m gross hydrocarbon column at Galoc field offshore Philippines. Galoc-7 was drilled to 2,373 m and in the gross interval found 8.0 m of net pay in sands judged to be of poor quality. Preliminary logging and wireline data indicates the reservoir unit contains oil, gas and water, but results are inconclusive in terms of the commerciality of this part of the block.

Nido will plug and abandon Galoc-7 and prep to drill the Galoc-7ST-1 well in the block’s central area. Galoc lies off northwest Palawan in Block SC-14C. Water depth ranges 290-330 m. Gross production during Q1 averaged 4,385 bo/d while field uptime was 99.9%. Galoc is owned by Nido (55.88% WI, operator), Kupec (26.85%), Philodrill (7.21%), an Oriental Petroleum & Minerals-Linapacan JV (7.79%), and Forum Energy (2.28%).

Drilling aims to establish the potential of the central portion of Block SC-14C.

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Volume 09, No. 06 13 e&P

Africa

Apr. 26 Kenya- Ngamia Ngamia-11 will be used for an extended water flood pilot test.

Apr. 26 Kenya- Block 13T A rig will reenter the Etom-2 well and prepare the well for a DST.

Apr. 13 Botswana- Serowe Coring will commence within the next eight weeks on NWB-352-1-W005.

Apr. 11 Cote d'Ivoire- CI-202 An upcoming five-well drilling campaign to be carried out by Vitol E&P will include this block.

FSU & Eastern Europe

Apr. 28 Azerbaijan- Bulla-More Socar is preparing to drill a well on the field in the near term.

Apr. 25 Kazakhstan- Rostoshinskoe An appraisal well at Rostoshinskoye is pending a flaring permit before testing.

Apr. 11 Georgia- Norio Goldcrest Resources will drill a horizontal sidetrack from an existing well to reach targets between 1,000-1,500 m.

Apr. 11 Romania- XV Midia Shallow Black Sea O&G awarded a contract to the GSP Uranus jack-up rig to drill two wells in the block starting in 4Q17.

Latin America

Apr. 28 Brazil- CE-M-717 Premier Oil's planned drilling campaign in the Ceara Basin probably won't start until 2H18.

Apr. 28 Brazil- Foz do Amazonas Basin Total reached a deal with Ensco to use the Ensco DS-9 drillship to drill two firm wells in 2017.

Apr. 21 Bolivia- Incahuasi Gazprom plans to soon drill the Incahuasi-4 well.

Apr. 18 Argentina- Agua del Cajon Capex is considering a 35-well pilot program in the block.

Middle East & North Africa

Apr. 28 Egypt- Abu Sennan Following completion of the Al Jahraa SE-2X, a rig will drill the Al Jah-raa-9 targeting the AR-C reservoir.

Apr. 28 Turkey- Ortakoy Condor Petroleum will drill the Yakamoz-1 exploration prospect this year.

Apr. 25 Morocco- Sebou SDX Energy will drill two exploration wells in the block in 2017.

North Sea & Western Europe

Apr. 28 Norway- PL 644B OMV contracted Odfjell Drilling to use the semi-sub Deepsea Bergen to drill at least one HP-HT well.

Apr. 25 Italy- FR.39.NP An EIA will be submitted during 2017 for an appraisal well to be drilled.

Apr. 18 UK- Lidsey Angus Energy won local approval to drill a second well in the oilfield.

South Pacific

Apr. 27 Australia- Callawonga A five-well development drilling campaign is scheduled to begin in May.

Apr. 26 Australia- ATP-795-P Senex will start drilling the Eos Block in May.

Apr. 20 Australia- Barossa The first well of the 2017 campaign was completed and analysis of results is ongoing.

Asia

Apr. 28 Indonesia- Mahakam Pertamina is looking for a jack-up rig to drill the block once the company takes over operatorship in 2018.

Apr. 21 Mongolia- Bogd Block IV A well could be drilled in the block in the about six to seven weeks.

Apr. 18 China- South China Sea CNOOC contract Hai yan Shi You 981 for a drilling campaign offshore China commencing in May and lasting five months.

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CNPC will more than double wells at CBM fieldCNPC has approved a major upgrade for a coalbed methane field in China’s

Qinshui Basin. Chengzhuang, in Shanxi province, already has 114 wells producing 7.25 MMcf/d, but now CNPC will invest $53.8 million over the next two years to drill 147 new production wells. This will lift Chengzhuang’s production by 13% to 8.2 MMcf/d

this year, while in 2018 the field will average 8.85 MMcf/d. Regulators must now approve the plan, which partner Green Dragon

Gas expects will happen by Q3. Chengzhuang is a 67-sq-km block that contains 62 Bcf 2P and will have more than 1,300 potential CBM well sites remaining once the current round of development drilling is completed. CNPC (53% WI) operates with Green Dragon Gas (47%).

Licensing

Cairn India plans revitalization campaign at Rawa Cairn India will drill 20 wells and build new infrastructure to stave off production declines

at Rawa field, offshore India. The $504 million program will see six of the 20 new wells drilled from a new platform while the remaining 14 will be drilled from existing platforms already operating at the field. This project follows a recent well intervention and acid stimulation

program that managed to increase production 3.0% in 2H16 to 19,637 boe/d. Despite that program, Rawa averaged 18,600 boe/d in 2016—down

22% from 2015’s 23,845 boe/d. Rawa is located in the shallow offshore area of the Krishna-Godavari Basin, in the Bay of Bengal, and has been producing for 21 years. Over that time, it has produced 343 MMboe (82% oil), representing 48% recovery of in place resources. Cairn India (22.5% WI) operates with ONGC (40%), Videocon (25%) and Rawa Oil (12.5%).

Reliance starts up Indian coalbed methane fieldReliance Industries started commercial production of coalbed methane from its

Sohagpur development project in Madhyapradesh, India, at the end of Q1. Phase 1 will reach 14 MMcf/d by mid-June, but will ramp upward over the next 15-18 months to hit 124 MMcf/d once the first batch of 230 planned wells are fully on stream and connected

to the gas gathering systems servicing Sohagpur East and Sohagpur West. So far, more than 200 wells have been drilled and hooked to infrastructure.

Later phases will see Reliance drill 600-800 more wells and associated infrastructure, which could push gas volumes from Sohagpur into the 300 MMcf/d range. Sohagpur covers 1,000 sq km and contains a gross 1.9 Tcf. Pilot production began in July 2016. Gas is transported 312 km via a new pipeline to a connection with GAIL’s main Hazira-Vijaypur-Jagdishpur trunkline near Allahabad in Uttar Pradesh. Reliance acquired Sohagpur in 2001 and is the license’s sole owner.

Asia

Sinopec to launch new Fuling Phase in MaySinopec will start up production from the Nanchuan shale gas block in May, which

will formally kick off Phase 2 production of the Fuling gas project in China. Sinopec aims to produce 232 MMcf/d from Nanchuan between now and the end of 2020 and will spend $250 million in 2017 to build eight pads and drill 33 production wells. So far, Sinopec has drilled seven wells in Nanchuan, including four high-producing ones

at pad 195 that have each averaged 200 Mcf/d. Fuling Phase 2 was greenlighted last year and will double volumes from

2016’s 484 MMcf/d to 967 MMcf/d. Current production is averaging 565 MMcf/d from 250 wells. Fuling’s wells typically cost $14.5 million to drill, complete and tie to infrastructure, but Sinopec has reduced that by 30% to $10.17 million. Sinopec believes it has further room to improve.

Fuling is a 200-sq-km shale gas block in Chongqing province that contains 13.4 Tcf in 2P reserves. The field was discovered in 2013.

■ Uruguay will auction 17 deepwater blocks in 2019. The tender, called Uruguay Round 3, will be launched in Houston in September. The regions to be offered include areas in the Eastern del Plata and Punta del Este basins, where water depths run to 3,000 m. The last deepwater well drilled of Uruguay was Total’s Raya-1 in Block 14, which was plugged and abandoned as a dry hole in 2016.

■ Petro Matad has received an official letter from Mongolia’s Mining Resources and Petroleum Authority confirming the company’s intent to extend the PSC exploration periods for Blocks IV and V by two years to July 2019. The company also expects to mobilize a rig to drill sites in both blocks in the next four weeks. Petro Matad is sole owner of the two licenses, but is looking for a farm-in partner.

People & Companies ■ Tony Hayward, former CEO of BP,

is retiring as chairman of Genel in June. He is being replaced by Stephen Whyte, who has over 30 year of experience in the oil and gas industry. The move follows Ben Monaghan’s decision last month to step down from his position of CFO following the writedown of reserves at Genel’s Taq Taq field in Iraqi Kurdistan.

■ CNOOC’s CEO Yang Hua resigned less than a year after being appointed to the role. He is being replaced by Yuan Guangyu, who had been president. Xu Keqiang was named executive director and president, replacing Yuan. Yang and Yuan are both 35-year veterans of CNOOC.

■ Eni reappointed Claudio Descalzi as CEO and Andrea Gemma, Pietro Guindani, Karina Litvack, Alessandro Lorenzi, Diva Moriani and Domenico Livio Trombone independent directors

■ Zoltan Laszlo Magyar became the new CFO of MOL Romania as of March 1. Since 2014, Magyar has held several positions, including CFO and managing director, within MOL Kalegran, an upstream subsidiary of MOL Group in Kurdistan.

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Volume 09, No. 06 15 e&P

Africa

May 2 Gabon- Baudroie-Merou The field currently produces 4,600 bo/d from three wells.

Apr. 28 Botswana- Selemo Tlou has been producing CBM from the Selemo pilot project for about 12 months.

Apr. 26 Ghana- Tweneboa Gross production during 1Q17 was 50,000 boe/d.

Apr. 25 Mauritania- Chinguetti Sterling Energy reports the field produced a gross 6,480 bo/d during 1Q17.

FSU/Eastern Europe

Apr. 24 Russia- Vladimir Filanovsky Lukoil reports the field has now passed a cumulative 12.5 MMbo.

Apr. 25 Kazakhstan- Chinarevskoye About 43 wells are now producing from the field, 22 oil wells and 22 gas-condensate wells.

Apr. 11 Georgia- Norio Goldcrest Resources reports the field is now producing 25 bo/d.

Latin America

May 2 Colombia- Platanillo During April the field produced an average of 4,845 bo/d.

Apr. 28 Brazil- Frade Chevron is producing about 22,000 bo/d from the field, nearly 80% below the FPSO's capacity.

Apr. 28 Mexico- Cardenas-Mora The field is currently producing about 7,200 bo/d.

Middle East/North Africa

Apr. 19 Oman- Block 8 Production from Block 8 averaged 5,325 bo/d in 2016.

Apr. 18 Iran- South Pars South Par field is averaging 20.3 Bcf/d.

Apr. 13 Egypt- Abu Qir Gas production started up at a new production platform.

Apr. 11 Iraq- Tawke Production averaged 113,280 bo/d in January 2017.

North Sea/Western Europe

Apr. 28 Ireland- Corrib Production from Corrib averaged 381 MMcf/d in 1Q17.

Apr. 21 Norway- Goliat The field will be shut-in after the summer for maintenance.

Apr. 19 Denmark- Ravn First oil at Ravn field was achieved early in 2017.

Asia

Apr. 28 Indonesia- Oyong Oyong's average production for 1Q17 was 850 bo/d.

Apr. 28 China- Block 22/12 Gross oil production for 1Q17 averaged 8,326 bo/d.

Apr. 26 China- Linxing Average production increased to 20 MMcf/d in April.

Apr. 25 India- KG-D6 The KG-D6 gas project produced 260 MMcf/d in 1Q17, 25% less gas compared to 4Q16.

South Pacific

May 1 Australia- Cliff Head Tamarind reports production increased 17% during 1Q17 to 1,300 bo/d.

Apr. 28 Australia- Casino Gross 1Q17 production was down 9.0% YOY to 9.3 MMcf/d.

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InternatIonal Scout 16 May 4, 2017

NORTHERN EUROPENORTHERN EUROPE FARMOUTOne Anticline Prospect.Dual Targets U. Jurassic Bridport SS &-- DV--Cornbash Limestones.Onshore To Offshore Seismic Data. ONSHOREUP TO 50% INTEREST AVAILABLERecoverable Resources: 37 BCFDV 2970FO

UK DEVELOPMENT OPPORTUNITY1-Exploration Well & 1-Appraisal Well.Significant Untested Upside Potential. DVVirtual & Physical Dataroom Available.SEEKING JV PARTNER FOR FARMOUT NORTHPmean Reserves Range: 14-20 MMBOE SEACA Required To View Dataroom.DV 2980FO

UK NORTH SEA FARMOUTOne Oil Discovery & One Large Prospect.2 Appraisal Wells Planned In 2017. DVReprocessed 3D Seismic Available.SEEKING JV PARTNER FOR FARMOUT NORTH30-50% WORKING INTEREST AVAIL SEAEstimated 2P Reserves: 29 MMBOComb. Reserve Potential: 80 MMBOCONTACT AGENT FOR MORE INFODV 2981FO

UK UNCONVENTIONAL PROJECTOne Well Drilled In 2013. DVHydraulic Fracturing Project. UNCONVENTIONALWORKING INTEREST FOR SALEDV 2054FO

UNITED KINGDOM FARMOUTTriassic Sandstones Discovery. DVDinantian Limestones.3D Seismic Data Available. OFFSHOREPromote Period Extended Until Dec 2017.SEEKING JV PARTNERP50 Reserves: 291 BCFCA Required To View Online Data Room.DV 1696FO

UNITED KINGDOM FARMOUTTwo Identified Prospects. DVAwarded September 2015. NORTHSEEKING JV PARTNER SEAProspective Resources: 463 BCFDV 8157FO

UNITED KINGDOM FARMOUTOne Identified Prospect. DVOne Well Commitment. NORTH SEASEEKING JV PARTNERMean Recoverable Reserves: 30 MMBOEDV 8611FO

FORMER SOVIET UNIONTAJIKISTAN EXPLORATION PROJECTExploration 2D Infill Seismic Planned. EX2D Seismic Data Available.SEEKING JV PARTNER - FARMOUT-- FOR FARMOUTEX 4895FO

MIDDLE EASTKURDISTAN AREA OPPORTUNITYLight Sweet Crude With No Water.Development Plan Approved In May 2016. PP2 Development Wells Identified.3D Seismic Data Available.50% WORKING INTEREST FOR SALE 5,000Gross 2P Reserves: 21 MMBO BOPDTotal Proved Plus Probable: 40 MMBOUnrisked Prospective Resources: 66 MMBOCONTACT AGENT FOR MORE INFOPP 2975DV

OMAN EXPLORATION OPPORTUNITYREADY TO DRILL PROSPECTSMapped Prospects Are All Structurally- DV-Defined W/ Several Large 4-Way Closures.2D & 3D Seismic Data Available. READYSEEKING JV PARTNER TO DRILLCONTACT AGENT FOR STATUS UPDATEDV 2882FO

NORTHEAST ASIA2017 CHINA LICENSING ROUNDWater Depths >700m. BRData Room Closes June 15, 2017. BIDWORK PROGRAMME BIDDING ROUND ROUNDBIDS ARE DUE SEPTEMBER 15, 2017BR 4811

MONGOLIA EXPLORATIONSignificant Frontier & Emerging Basins-- EX--Exploration Opportunity. FARMOUT2D & 3D Seismic Data Available.SEEKING JV PARTNEREX 1974FO

NORTHERN EUROPEDENMARK OPPORTUNITYTriassic, Rotliegend, & Middle Jurassic SS. EXFour Play Fairways.Preliminary 7th Round Awards. FARMOUTSEEKING JV PARTNERSEX 8228FO

OFFSHORE IRELAND OPPORTUNITYOne Identified Prospect.Water Depth: 280m DVWork Programme: Seismic Reprocessing.SEEKING JV PARTNER FARMOUTMean Recoverable Reserve: 1.2 TCFDV 8566FO

CENTRAL AMERICA/CARIBBEANCUBA FARMOUT OPPORTUNITYTwo Identified Prospects. DV2D Seismic Data Available.SEEKING JV PARTNER - ONSHORE-- FOR DRILLINGProspective Resource: 637 MMBOEDV 4721FO

EAST AFRICAKENYA FARMOUT OPPORTUNITYMultiple Leads at Miocene Level. DVDrilling Plan - 1 Well to 2,000m.Seismic, Water Wells And G&G Data. SEEKINGUP TO 66% WORKING INTEREST AVAIL JVTotal Pmean Recoverable: 285 MMBOCA Required To View Data Room.DV 2015FO

EAST AFRICA FARMOUTEarly Stage Of CBM Project. DVPermo-Triassic Coals. 250-1,000m.Pilot Wells Planned. Gas Markets Identified.SEEKING JV PARTNERS TO FULLY-- FARMOUT-FUND DEVELOPMENT PROGRAMME.Potential >12 TCFCONTACT AGENT FOR STATUS UPDATEDV 2792FO

MOZAMBIQUE FARMOUTFour Wells Drilled To Date. DVMiocene, Oligocene, Eocene Formations.Extensive 2D Seismic Data Available. ONSHORESEEKING INDUSTRY PARTNERDV 2950FO

EAST AFRICA OPPORTUNITYUnderexplored Acreage. Mesozoic Rifts.High Impact Exploration Wells In 2018/19. EXSimilarities To Yemeni Rift Basins.2D Seismic To Be Acquired In 2017. FARMOUTSEEKING JV PARTNERCONTACT AGENT FOR MORE INFOEX 2589FO

WESTERN TANZANIA EXPLORATIONHigh Impact Exploration Well Planned.Neogene, Oligocene & Cretaceous. DVRecent Seismic Data Available.SEEKING JV PARTNER FOR DRILLING SEEKINGUnrisked Resource Potential: 300 MMOE JVCA Required To View Data Room.DV 2939FO

FORMER SOVIET UNION2017 GEORGIA OPEN TENDERBlanket License For Oil & Gas. BROPEN APPLICATION - BID ROUND-- PROCESSBR 4899

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Volume 09, No. 06 17 e&P

Africa

Apr. 26 Kenya- Amosing The Amosing-6 well drilled near the basin bounding fault encountered 35m of net gas and oil pay.

Apr. 13 Cameroon- Logbaba Well La-108 has encountered a gross pay of 125m of high permeability, high porosity gas bearing sand.

Mar. 27 Senegal- Sangomar The VR-1 well found a gross oil column of 97 m across several reservoirs.

FSU/Eastern Europe

Mar. 11 Azerbaijan- Guneshli Shallow Socar brought a new well on stream at the field at the rate of 625 bo/d.

Mar. 10 Russia- Khazri A Lukoil exploration well intersected hydrocarbons, but the rig was not able to test the find.

Mar. 3 Azerbaijan- Oil Rocks A new well will produce at the rate of 72 bo/d.

Latin America

Apr. 27 Argentina- La Escalonada An appraisal well drilled in 2016 on the block to test the oil window has shown excellent productivity.

Apr. 21 Mexico- Yaxche A horizontal well produced 4,600 bo/d, or 2,100 bo/d more than expected.

Apr. 20 Colombia- Platanillo Amerisur reports Platanillo-22 has tested at 613 bo/d of 31.5° API oil with a very small water cut.

Middle East/North Africa

Apr. 28 Turkey- Poyraz The Poyraz West-1 tested at a stabilized rate of 2.0 MMcf/d from the Sogucak carbonate.

Apr. 17 Egypt- South Disouq The SD-1X well has discovered gas at the initial target depth, and drilling is continuing to a lower horizon.

Apr. 10 Iraq- Sarqala Sarqala-1 is now producing 7,100 bo/d after completion of acid stimulation.

North Sea/Western Europe

Apr. 11 Norway- Edvard Grieg Lundin appraisal well 16/1-27 drilled on the SW flank of the field found a 15-m gross oil column in a 94-m thick sand reservoir.

Mar. 27 UK- P2308 The Halifax exploration well found over 1,000 m of net oil pay after being drilled to 1,846 m TVD.

Mar. 24 Norway- Gimle Statoil drilled wildcat well 34/10-55 S to 7,811 m TMD and intersected 170 m of hydrocarbon pay, about 60 m of which was in good-quality sands.

Asia

May 1 Philippines- Galoc The Galoc-7S1 intersected 12 m of net gas pay in a 122 m reservoir section.

Apr. 27 China- Bozhong CNOOC found oil at the Bozhong 29-6 and 29-6S wells in the mature region of the Bohai Sea.

Apr. 20 Myanmar- Block AD-7 Thalin-1B intersected 99 m of net gas pay and tested at 50 MMcf/d over 50 hours on a 48/64-in. choke.

South Pacific

Apr. 27 Australia- PEL 106 The Canunda-3 well intersected nearly 3.0 m of net gas pay.

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InternatIonal Scout 18 May 4, 2017

OCEANIA/SOUTH PACIFICvAUSTRALIA FARMOUT OPPORUNITYTwo Identified Prospects.Laurel Formation: 2,000m-5,000m. DVSEEKING JV PARTNER - ONSHORE-- FOR FARMOUTUnrisked Mean Prospective: 13.02 TCFDV 2115FO

AUSTRALIA GAS PROSPECTEarly Permian Cattle Creek Formation. DVSEEKING JV PARTNER QUEENSLANDLate Permian Coal Seam Gas: >90 BCFDV 1538FO

OFFSHORE AUSTRALIA FARMOUTThree Identified Prospects. DVWater Depth: 180-400m. FARMOUTUP TO 50% WORKING INTEREST AVAILMean Potential: 275 MMBOAGENT MARKETING DIVERSE PORTFOLIODV 1383FO

OFFSHORE AUSTRALIA FARMOUTMultiple Untested Structural Trends. EXRecently Acquired Rocket 2D Seismic. SEEKINGUP TO 50% WORKING INTEREST AVAIL JVCONTACT AGENT FOR MORE INFOEX 8080FO

ONSHORE AUSTRALIA PERMITSOne Ready To Drill Prospect.Active Exploration Programme And --- DV--Flexible Farm-In Terms.SEEKING JV PARTNERS ONSHOREUnrisked Prospective: 70-100 MMBOECONTACT AGENT FOR UPDATEDV 8330FO

WESTERN AUSTRALIA FARMOUTMultiple Leads Identified. EXLower Keraudren Formation. SEEKINGExisting Seismic Data Available. JVSEEKING FARMOUT PARTNEREX 4976FO

2018 NEW ZEALAND BLOCK OFFERExploration Acreage. BRNominate Areas To Be Considered. BID ROUNDWORK PROGRAMME BIDDING ROUNDBR 2722

NEW ZEALAND OPPORTUNITYMangahewa Formation. DVMiddle Eocene Ongoing Well Testing.Data Room Opening May 1, 2017. ONSHOREUP TO 60% NONOP WI AVAILABLEBid Offers Are Due July 31, 2017.DV 2734FO

NORTHERN EUROPEUNITED KINGDOM PROSPECTOne Appraisal Well Prospect. DVTriassic Sherwood Sandstone.Reprocessed 3D Seismic Survey. FARMOUTUP TO 50% INTEREST AVAILABLERecoverable Resources: 30 MMBODV 2972FO

UNTIED KINGDOM FARMOUTFour Identified Prospects. DV28th Licensing Round Award. NORTHSEEKING JV PARTNER SEATotal P50 GIIP: 2.6 TCFDV 8470FO

OCEANIA/SOUTH PACIFICAUSTRALIA EXPLORATION FARMOUTLarge Structural Prospect Identified With--Additional Structural & Stratigraphic Leads. DVUP TO 50% WORKING INTEREST AVAILEst Mean Prospective: 1.4 TCF FARMOUTP10 Upside: 2.0 TCFCONTACT AGENT FOR INFODV 8005FO

AUSTRALIA FARMOUT OPPORTUNITYOnshore Gas Project.SEEKING JV PARTNERS DVCertified 2P Reserves: >60 BCF QUEENSLANDCertified 3P Reserves: >280 BCFDV 1569FO

AUSTRALIA FARMOUT OPPORTUNITYMultiple Identified Prospects.Early Entry Into An Opening Play. DVSEEKING JV PARTNER OFFSHOREProspect Resources: 250 MMBOCONTACT AGENT FOR UPDATEDV 2818FO

AUSTRALIA FARMOUT OPPORTUNITYUnconventional Hydrocarbon Potential.Two Wells Drilled & Several Leads. DVSEEKING JV PARTNERP50 Conventional Gas: 12.44 BCF ONSHOREP50 Unconventional Gas: 1,456 BCFCONTACT AGENT FOR MORE INFODV 4765FO

AUSTRALIA FARMOUT OPPORTUNITYConventional & Unconventional Prospects.SEEKING JV PARTNER FOR PROJECT DV2C Gross Contingent Rsrcs: 1,572 BCF ONSHOREDV 4966FO

AUSTRALIA FARMOUT OPPORTUNITYOne Identified Prospect.Water Depths: 200m to 1,000m. DV2D Seismic Data Recently Interpreted. OFFSHORESEEKING EXPLORATION PARTNERDV 4760FO

NORTHERN EUROPEUNITED KINGDOM FARMOUTTwo Identified Prospects. DVNew Broadband Seismic Planned 2017. SEEKINGUP TO 50% WI AVAILABLE JVP50 Prospective Resources: 533 MMBODV 2014FO

UNITED KINGDOM FARMOUTUpper Jurassic - Fulmar Formation. DV10 Seismically Identified 3D HI Features.2,400m Drilling Depth In 90m of Water. NORTH3D & Reprocessed 2D Seismic Data. SEASEEKING JV PARTNERPortfolio Unrisked Recoverable: 1.5 BBODV 2990FO

UNITED KINGDOM FARMOUTSTACKED RESOURCE PLAY DVMississippian-Age Shales.3D Seismic Data Acquired In 2016. ONSHOREEst. Total In-Place Resource: >1,300 TCFEst. Recoverable Resource: >100MMBODV 2934FO

UNITED KINGDOM OPPORTUNITYOne Identified Prospect. DVFirm Well Commitment Expanded To-----July 19, 2019. NORTHSEEKING JV PARTNER SEAUnrisked Recoverable Rsrces: 92.5 MMBOEDV 8994FO

UNITED KINGDOM OPPORTUNITYOne Identifed Gas Discovery. DVOther Low Risk Undrilled Segments. NORTH SEASEEKING JV PARTNERDV 2052FO

UNITED KINGDOM OPPORTUNITYOne Drill Ready Prospect. DVProprietary 3D Seismic Survey Available. DRILL75% INTEREST AVAILABLE READYRecoverable Resources: 70 MMBODV 2973FO

UNITED KINGDOM OPPORTUNITYThree Identified Prospects.Appraisal Well Planned In 2017. DV3D Geostreamer Data Available.Site Survey Imminent. Tendering For Rig. FARMOUTSEEKING JV PARTNER Pmean Recoverable: 60 MMBOEDV 4926FO

UNITED KINGDOM PROJECTOne Identified Prospect. DVTwo Historic Drilled Wells W/Gas Shows.Significant Exploration Upside. NORTHHigh Quality Reprocessed 3D Seismic. SEASEEKING JV PARTNEREst.P50 Prospective Resource: 168 BCFDV 1940FO

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Volume 09, No. 06 19 e&P ■ Murphy Oil will promote financial

projects VP Christopher Hulse as VP and controller effective June 1 to replace Keith Caldwell, who will retire

later this year. Hulse joined Murphy in 2015 as onshore finance VP.

■ Oronova Energy named Travis Doupe as its VP, Finance and CFO. Previously, he was CFO at various public and private oil and gas companies throughout Canada and Latin America. He began his accounting career at PwC in 1997 and is a chartered accountant.

■ Steve Phimister will replace Paul Goodfellow on the board of Oil & Gas UK, effectively immediately, as he also takes up his new role as VP of Shell’s UK & Ireland upstream business unit.

■ TAQA, or Abu Dhabi National Energy Co., elected three new board members and retained four existing ones

at its annual general meeting. Saeed Mubarak Al Hajeri will continue as chairman while new member Khalifa Ali Al

Qemzi will be vice chairman. Other new board members Saif Saleh Al Sayari and Mohammad Abdullah Al Suwaidi join existing members Abdul Aziz Abdul Rahman Al Hemaidi, Salem Sultan Al Daheri and Khalid Abdullah Al Mass.

■ Woodside appointed Anthea McKinnell as acting CFO effective April

3. McKinnell was previously VP of global operations planning and performance, and has been

VP Treasury and Taxation at Woodside. The company said it was conducting an assessment of candidates for a permanent CFO, following the departure of Lawrie Tremaine in February for the same role at Origin Energy.

Pemex positions deepwater & onshore assets for farm-outsPemex will offer a stake in the Nobilis and Maximino deepwater finds to international

oil and gas companies in the company’s second-ever deepwater joint venture tender. Nobilis and Maximino lie in the Perdido Fold Belt in the Gulf of Mexico, just south of the Mexico-US maritime border. Pemex has drilled five wells across the two discoveries to date and estimates that they contain a combined 500 MMboe. Regulators must now approve Pemex’s decision, which if quickly forthcoming could lead to a farm-out

auction before YE17. Both Nobilis and

Maximino lie close to the 485 MMboe Trion discovery. BHP Billiton won the right to partner with Pemex at Trion in a hotly contested auction late last year, and took the prize by beating BP with a $624 million offer—just $19 million more than BP bid. The terms of the agreement require BHP agreed to a minimum work program that includes two appraisals, an exploration well and a 1,250-sq-km 3D seismic survey. In return, BHP gains 60% WI

and operatorship of the two blocks—AE-0092 and AE-0093—that contain Trion.

BHP is now in talks with KBR subsidiary Granherne and possibly also Williams to sound out takeaway options for Trion. The cheapest plan consists of piping Trion’s oil and gas to shore via existing pipeline networks on the US side of the border. As US facilities would then process the oil this is politically controversial in Mexico, however. The second option, preferred by Pemex, would be to use FPSOs to produce Trion—potentially the first use of such vessels in the Gulf of Mexico. Shuttle tankers would then take the oil to be processed in Mexico.

Meanwhile, regulators also approved plans for two onshore joint ventures, covering the Cardenas-Mora and Ogarrio fields, both located in south Tabasco. Cardenas-Mora produces about 7,200 bo/d, while Ogarrio is currently averaging 6,600 bo/d. Pemex will retain a 50% stake in both fields with the company winning rights to partner with Pemex taking over the remaining 50% as operator. The auction for rights to participate in the joint venture with Pemex will take place on Oct. 4.

Licensing

CNOOC offers on & offshore blocks in South China SeaCNOOC invited foreign companies to bid for 22 blocks in the north part of the South

China Sea. The blocks cover a combined 47,270 sq km and include 16 blocks in the east part of Pearl River Mouth Basin, two in the west part of Pearl River Mouth Basin and four in the Beibuwan Basin. Five blocks have water depths greater than 700 m. Data rooms

open from April 12 through June 15 and the tender closes on Sept. 15.Usually, CNOOC offers

deals for offshore blocks that have the company retaining the right to farm-in for up to a 51% stake in any developed find. However, the company is willing to offer more flexible terms in order to entice bidding in the current low-price environment. As a result CNOOC says it will now offer contract terms more closely subject to conditions in the block as well as more time, if needed, for signature payments to be made.

Meanwhile, China United Coalbed Methane Corp, a CNOOC subsidiary also issued a tender offering domestic & foreign oil companies chance to bid on 10 coalbed methane blocks. The ten blocks cover a total of 2,173 sq km and cover several areas of China including the Ningxia region in west China, Shanxi province in central China, and Shandong and Anhui provinces in east China. The data room for the tenders is open from April 30 to July 31.

More flexible terms will be offered for 22 offshore blocks in the South China Sea.

Auction of Nobilis & Maximino’s 500 MMboe will likely occur in Dec.

Both are close to Trion discovery where BHP won farm-in rights last year.

Onshore Cardenas-Mora and Ogarrio in Tobasco will be auctioned in October.

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Shaping the Continent’s Future in Upstream Oil & Gas

24th - 25th May 2017The Waldorf Hilton, London, United Kingdom

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79th PetroAfricanus Dinner 24th May, Jasper Peijs, Vice President for Exploration, Africa, BP, London, UK

8th Global Women Petroleum & Energy Luncheon 25th May, Sandy Stash, Group Vice President, Safety, Sustainability and External Affairs, Tullow Oil, London, UK