Sponsor completion guarantees in LNG construction financing: Part II

As the world of North American LNG financings continue to evolve, OGInsights explores the use of completion guarantees in construction financings.

In Part II of this two part series, we look at the conditions precedent to project completion which typically need to be satisfied for release of the completion guarantee by lenders.

Construction criteria requires "substantial completion" under the EPC Contract. In addition, operational tests must be satisfactory and includes production of on-specification LNG for a continuous 90-day period.

At completion, maximum stated debt to equity ratio is not to be exceeded - should the ratio be too high, project sponsors are required inject capital to bring the ratio within covenanted levels. Operating account and Debt Service Reserve Accounts are also to be funded to required levels.

From a legal perspective, project agreements and finance documents must be in full force and all governmental authorisations need to be in place, together with certification of environmental and social compliance in line with covenant requirements.

Financing structures continue to evolve to support LNG projects with lenders and sponsors driving the innovation to (i) enable projects and (ii) improve project economics whilst managing the risk that lenders are exposed to.

In Part I, OGInsights covered the use of and reasons for project completion guarantees from a sponsor perspective.

Read More

Sponsor completion guarantees in LNG construction financing: Part I

As the world of North American LNG financings continue to evolve, OGInsights explores the use of completion guarantees in construction financings.

At a high level, the project sponsor guarantees debt service under a guarantee until the construction is complete. To the extent that a project does not reach completion (normally by a certain long-stop date), then the sponsor will be obliged to repay all of the debt under the guarantee.

The provision of a guarantee comes with a number of benefits:

1. Lenders are more likely to agree to the equity funding of a project to be back-ended (i.e. construction costs are first funded by debt before equity rather than pro rata). This improves project economics (NPV and IRR).
2. Lenders will allow use of pre-project completion cash flows as a source of “equity” funding towards the project, thus replacing “hard” equity contributions. In the absence of a guarantee, lenders typically do not give credit to such uncontracted cash flow and such cash generated is trapped until project completion is achieved (as normally insisted upon by lenders). When a guarantee is in place, lenders are more or less agnostic to whether pre-completion LNG sales are contracted or spot sales and can give credit to such cash flows.
3. Lower pre-completion debt costs – reduced commitment fees and margins, reflecting that of the sponsor corporate credit strength (with normal adjustments for pricing and tenor). Pricing could be c.15-30bps cheaper under a construction guarantee structure fr example

One possible downside is that higher amounts of debt are drawn in the early years of construction (vs. when no guarantee is in place) if equity funding is back-ended, and hence interest costs could be higher, although this is partly offset by the lower debt pricing mentioned above.

Note that in a financing without a completion guarantee, lenders require hedging at financial close of the facility with a substantial amount (typically >60%) under either fixed interest rate or hedged throughout the construction and operations period. A construction guarantee provides more flexibility with regard to hedging during the pre-completion/construction period as the interest rate risk is borne by the sponsor; at project completion, lenders will require fixed rate/hedging in place concurrent with the release of the guarantee.

Financing structures continue to evolve to support LNG projects with lenders and sponsors driving the innovation to (i) enable projects and (ii) improve project economics whilst managing the risk that lenders are exposed to.

In Part II, OGInsights explores the conditions that constitute project completion.

#US #LNG #financing

Read More

Valuera nears TDs at Inanli-1

Valeura has reached 4,145m on the Inanli-1 well (TD 5,000m, c.800m deeper than Yamalik-1).

It has encountered over-pressured gas with a c.40% net-to-gross, similar to that of Yamalik-1, with gas flows - all pointing to promising results. In addition, the well has encountered more naturally fractured rock than encountered in Yamalik-1 with increased gas levels recorded at the fractured intervals.

Drilling is continuing to 5,000m with an extensive set of logging and well tests planned. Operations are expected to be completed in January with fracking and flow testing expected to commence around the end of Q1/19. Inanli-1 is the final well to be funded by Equinor.

Devepinar-1 appraisal well is the next scheduled to be drilled following completion of Inanli-1.

Read More

Petronas enables Cheniere Sabine Pass Train 6

Petronas has agreed to enter into a 1.1mtpa offtake deal with Cheniere on Sabine Pass Train 6 which should enable the train take FID shortly. With a foundation buyer now in place, Cheniere can continue with raising finance to progress the 4.5mtpa project.

Under the deal, Petronas has signed up to 1.1mtpa on a FOB basis for 20 years. As common with east coast LNG contracts, the pricing will be indexed to the monthly Henry Hub price, plus a toll for the liquefaction services plus margin.

Petronas vice president of LNG Marketing & Trading, Ahmad Adly Alias said: "Petronas is pleased to enter into this long-term relationship with Cheniere... With the addition of this new volume, it will enhance Petronas' supply portfolio and further strengthen our position as a reliable global LNG portfolio player."

Read More

SNE partners progress to FEED for Phase 1 of the development

The SNE JV offshore Senegal (Cairn 40%, Woodside 35%, FAR 15%, Petrosen 10%) has entered FEED for Phase 1 of the SNE development. The engineering contract has been awarded to the Subsea Integration Alliance (OneSubsea, Schlumberger and Subsea 7).

First oil is being targeted for 2022 with an initial production rate of c.100mbopd. The exploitation plan had previously identified a total development of 500mmbbl of oil over a multi-phase development with the Phase 1 FEED targeting 230mmbbl from the base, thicker sand package.

Woodside noted that the Senegalese Minister of Petroleum and Energies has approved Woodside’s transition to operator of the RSSD JV (Rufisque, Sangomar and Sangomar Deep) and the SNE development. Separately, FAR continues its commercial arbitration around the initial deal between Conoco and Woodside.

Read More

DEA acquires Sierra Oil & Gas

DEA has expanded its international footprint into the Americas by acquiring Sierra Oil & Gas from Riverstone Energy.

The Sierra portfolio includes the prized Zama discovery (Sierra Oil & Gas 40%, Talos Energy 35%, Premier Oil 25%) and an extensive exploration acreage position offshore Mexico.

The value of the deal is reported  at ~USD500 million which provides a positive read-through for Zama of over USD300 million net to Premier.

The acquisition further bolsters the Wintershall DEA portfolio ahead of its planned IPO in 2019-2020 and adds prospective acreage in what is otherwise a production (but stable) weighted profile.

Read More

Brasse's growth halts as Faroe's Rungne well disappoints

Faroe announced in November that the Rungne well came in disappointing with only sub-commercial levels of gas found. Although encountering hydrocarbons, the estimated volumes of 12-57bcf gas and 0.5-3.9mmboe condensates will mean the discovery is non-commercial on a standalone basis. Nevertheless it could form a future tie-back to Brage or Oseberg.

Faroe's exploration programme continues with Brasse East which could be another chance for Faroe to grow the Brasse Area prior to taking FID. Faroe is currently going through concept selection for the field with two potential hosts: Brage or Oseberg.

Related posts:

• Brasse - Brage's younger sibling
• Brasse continues to grow
• Brasse flow test shows promising results

Read More

ExxonMobil makes 10th oil discovery offshore Guyana; resource increased to 5+ bnboe

ExxonMobil announced its tenth discovery offshore Guyana and its sixth discovery on the Stabroek Block in the past year.

The Pluma-1 well encountered c.121 feet of high-quality, oil-bearing sandstone reservoir and is located c.17 miles southwest of the Turbot-1 well and follows previous discoveries on the Stabroek Block at Liza, Liza Deep, Payara, Snoek, Turbot, Ranger, Pacora, Longtail and Hammerhead. The discovery adds to ExxonMobil's previous 4+ bnboe resource estimate which is now being increased to 5+ bnboe.

The drillship will next drill the Tilapia-1 prospect located 3.4 miles (5.5 kilometers) west of the Longtail-1 well, with ongoing work to evaluate development options in the southeastern portion of the block and potentially combining Pluma with the prior Turbot and Longtail discoveries.

Phase 1 of the development is underway, and will include 17 wells connected to a FPSO with 120mbopd capacity by early-2020.

Phase 2 is due to be sanctioned in early-2019 and will use a 220mbopd FPSO.

For Phase 3, ExxonMobil plans to use an 180mbopd FPSO, with first oil in 2023. FID for Phase 3 is expected in 2019, which is now further supported by the Pluma discovery.

ExxonMobil sees the potential for five FPSOs producing 750mbopd by 2025 offshore Guyana.

#ExxonMobil #Guyana #Pluma #Liza #Stabroek

Read More

Kirkuk exports resume via Kurdistan

The Kurdistan and Federal Iraq governments have announced an agreement for the resumption of oil exports from Kirkuk via the Kurdistan export pipeline to Ceyhan. This positive development will benefit the public revenues of Federal Iraq which has been grappling with funding issues in recent years with the oil price collapse on the one hand and need to fund defences along its borders on the other.

Kirkuk production was locked out of the Kurdistan export pipeline following the Kurdistan independence referendum last autumn, the result of which also led to Federal Iraq taking back over the Kirkuk fields from the Kurds.

Related posts:

• Kurdistan referendum: Barzani's legacy
• Kurdistan independence referendum

Read More

INEOS swoops in for Conoco North Sea

As widely reported over the weekend, INEOS is the front-runner for the ConocoPhillips’ UK North Sea portfolio. ConocoPhillips had a buyer for the portfolio back in 2015, but pulled the deal citing that it had no desire to sell-out at the bottom of oil price cycle,

INEOS has beaten other likely UK North Sea focussed contenders which could include Ithaca Energy, Premier Oil, Neptune Energy, Chrysaor and SiccarPoint. The sale, estimated to be around USD3 billion, will exclude the Teeside Norsea terminal and London trading business.

INEOS existing North Sea portfolio
Source: The Times

The below was originally published on 24^th June 2018:

------------------------------------------------------------------------

ConocoPhillips' is one of the largest operators in the UK North Sea, being the operator of the Britannia area, the J-Area and large swathes of the Southern North Sea. ConocoPhillips is also a non-operated partner in the giant Clair field.

Clair is one of the largest oil fields in the UK offshore and located in the West of Shetlands which is making a name for being the last frontier of the UK and is increasingly attracting further exploration activity. The Clair field was brought onstream in 2005 and is currently undergoing a second phase of development (Clair Ridge). Clair Ridge is planned to come onstream in Q4 2018 with operator BP targeting an additional 640mmbbl which will extend the life of the Clair Area beyond 2050. As soon as Clair Ridge is onstream, the partners will be planning for the Phase 3 of the development known as Clair South.

On the operated assets, Britannia is one of the largest gas fields in the UK which has acted as a hub for various tie-backs over the years. The J-Area, although now beginning to mature, has been a highly successful gas hub in the Central North Sea where more infill drilling and exploration activity is planned into 2019 and 2020.

The Southen North Sea assets are the most mature with some going into decommissioning. ConocoPhillips has widely announced the closure of the Theddlethorpe gas processing plant which is the terminus for its CMS pipeline. This will lead to early/forced decommissioning of all the fields which currently utilise the CMS pipeline as the export route including the Faroe and Tullow Schooner and Ketch fields which will cease production in August 2018.

The ConocoPhillips' UK portfolio is concentrated around a few hubs and excluding the Southern North Sea, has a good amount of life remaining with current production at c.80mboe/d.

Read More

PGNiG expands footprint in Norway

On 18^th October PGNiG announced that it had agreed to acquire Equinor's interest in the Tommeliten Alpha gas and condensate field in the Norwegian North Sea. This continues PGNiG's strategy of diversifying its gas supply away from Russia.

PGNiG has always had an interest in Norwegian gas seeing it as as logical and accessible source of gas for Poland. As the long term Russian gas supply contracts come to expiry, PGNiG is making bold moves to secure new sources of gas and LNG. See PGNiG shuns Russian gas.

The operator of the discovery is ConocoPhilips (28.26%), and current partners are Total (20.23%), Eni Norge (9.13%) and Equinor (42.38%) which will sell its entire working interest to PGNiG. The agreed price for Equinor's stake was USD220 million at 1 January 2018 effective date.

The Tommeliten Alpha discovery is located in the vicinity of large, existing fields, most notably the giant Ekofisk field. According to current plans, production is expected to commence in 2024, and the development concept assumes a subsea tie-back to the existing infrastructure on Ekofisk.

Tommeliten Alpha is a gas and condensate field with estimated recoverable resources of 52 mmboe (net to PGNiG's 42.38%). PGNiG believes in an upside potential in the field reserves as well as significant exploration upside in the area.

The field was originally planned to start production in 2019, but development plans were shelved by operator ConocoPhillips in 2016 due to low oil prices.

#PGNiG #NorthSea #TommelitenAlpha # Equinor #Conoco

Read More

PGNiG shuns Russian gas

PGNiG is increasingly boldening its signals on shunning Russian gas as it turns to the west. The Polish state has historically been dependent on gas imports from its eastern neighbour but is looking to loosen its reliance to the communist state.

Poland consumes around 17 bcm of gas annually, more than half of which comes from Gazprom under a long-term contract that expires in 2022. It is seeing the upcoming expiry as the opportunity to diversify its gas supply ahead of time and has consistently stressed that Gazprom is charging Poland too much for the gas noting that Russia has taken advantage of the historic lack of other sources of gas which is now changing with the advent of LNG.

Poland has also vehemently opposed plans by Russia to build a new gas pipeline across the Baltic Sea which is aimed at strengthening its dominant market position into Europe. Instead Poland is looking to sanction the Baltic gas pipeline later this year or beginning of 2019 which will bring gas directly from Norway.

The last month has seen a flurry of newsflow around PGNiG’s activity in sourcing new gas.

In mid-October, PGNiG finalised terms with Venture Global for 2mtpa of LNG. It will buy LNG for 20 years on a FOB basis with supplies commencing under two contracts for 2022 and 2023. The FOB contracts are deemed attractive for PGNiG as it can choose to take the LNG to Poland or use it in its trading portfolio. The terms are not disclosed but understood to be in line with other Gulf Coast LNG contracts being 115% x Henry Hub plus a toll of c.USD2.50/mmbtu. Venture Global is currently developing the Calcasieu Pass LNG terminal on the US Gulf Coast.

This has been followed by a 24 year LNG deal with Cheniere Energy at the beginning of November. PGNiG has signed up a 1.45mtpa deal with LNG supplied by Cheniere’s Sabine Pass, Louisiana and Corpus Cristi, Texas liquefaction plants. The contract is for delivery on a DES basis directly to the 5Bcm/year Swinoujscie terminal in Poland. Poland is also looking to expand the import terminal to 7.5Bcm/year in part of the countries grander ambitions to become a LNG and gas trading hub.

PGNiG also farmed-in to the Tommeliten Alpha in the Norwegian North Sea on the upstream side at the end of October. See PGNiG expands footprint in Norway.

#PGNiG #LNG #Russia #Gazprom #VentureGlobal #Cheniere

Read More

Second chance for Petronas in West Africa

Following the recent disappointment at the Samo-1 well in The Gambia, Petronas has another chance in West Africa on the other side of the border in Senegal. Petronas is growing its West African exploration portfolio and is continuing its search for more acreage.

In August Petronas had farmed-in to 30% of Total's Rufisque Offshore Profond block, marking its entry into Senegal. Total retains 60% in the block with Société Nationale des Pétroles du Sénégal (Petrosen) holding the remaining 10%.

The block lies immediately to east to the Sangomar Deep block which contains the Cairn/Woodside/FAR SNE and FAN fields. The Rufisque Offshore Profond block covers 10,357km² , with a water depth ranging from 100m to 3000m.

The partners now plan on the interpretation of the acquired 3D seismic data with exploration drilling activities planned to commence in 2019.

Related links:

• The Gambia's Samo-1 well disappoints
• FAR goes further with another industry partner

#Petronas #Samo #FAR #Senegal #Gambia #Total #SNE #FAN

Read More

Hurricane's FPSO docked for changeover

Hurricane Energy has announced that the Aoka Mizu FPSO has been docked into Algeciras, Spain for planned personnel changes and bunkering.

The stopover will be extended to undertake a repair to an auxiliary system associated with power generation.

Commissioning activities will continue during its transit to the West of Shetlands as planned with first oil from the Lancaster field still on schedule for H1 2019.

The Aoka Mizu FPSO was designed and built and is owned by Bluewater Energy Services for operation as an FPSO in harsh environmental conditions. It was previously operated on the Ettrick and Blackbird fields in the North sea for Nexen Petroleum.

#Hurricane #Lancaster #AokaMizu #WOS

Read More

The Gambia's Samo-1 well disappoints

The JV in offshore Blocks A2/A5 has announced a disappointing result on the Samo-1 well. The JV, which comprises FAR Limited 40%, Petronas 40% and Erin Energy 20%, has hit water.

FAR Limited had prospective P50 resource estimates of 825mmbbl (gross unrisked) with a 55% geological chance of success. Wireline logs indicate that the target was water bearing. The Government of Gambia has now granted a six month extension to end of June 2019 to enable a thorough evaluation of the Samo-1 well result.

The blocks contain numerous other prospects including Saloo and Bambo for follow-up exploration. The findings from Samo-1 will guide next steps.

In the meantime, FAR Limited and its partners are continuing with the SNE development with development plans recently submitted to the Government of Senegal. FID for this 500+mmbbl development is targeting for end 2019 with first oil in 2022.

Related links:

• FAR goes further with another industry partner with Petronas
• FAR AMI with CNOOC in Senegal and The Gambia
• Senegal moves ahead

Read More

Soco acquires Egypt-focussed Merlon Petroleum

SOCO is rebuilding its business with the proposed USD215 million acquisition of Merlon Petroleum.

Merlon will significantly diversify the SOCO business adding Egypt as a new base from which to build a MENA portfolio. The acquisition will double SOCO's 2P reserves and production through the addition of 24mmbbl of oil.

Merlon's key asset is its 100% interest in the El Fayum licence which currently produces at c.7,000bbopd. The block contains 37mmbbl of contingent resources for SOCO to exploit which could take production beyond 15,000bopd. Furthermore, the northern area of the block is unexplored which SOCO will be keen to go after - management has already mapped 20 leads and prospects to be drilled between now and 2020.

The acquisition is to be financed by a mix of cash (up to USD158 million), assumption of debt (USD22 million) and issuance of 66 million new shares to Merlon's existing shareholders. The acquisition is expected to complete in H1 2019.

Read More

Verus acquires CIECO's UK North Sea portfolio

Verus has agreed to acquire Cieco Exploration & Production (UK) from parent ITOCHU Corporation for USD400 million. The effective date of the transaction is 1 January 2018.

The acquisition will includes a 23.1% interest in the Western Isles Development Project, a 25.8% interest in the Hudson field, a 2.0% interest in the Brent Pipeline System, and a 1.2% interest in the Sullom Voe terminal. This will add 11mboepd taking Verus' net production to c.18mboepd

The transaction will be funded by a combination of equity, existing cash reserves and debt. Equity will be provided by HitecVision, the majority owner of Verus.

Alan Curran, Chief Executive of Verus Petroleum commented:

"Verus is pleased to have signed this SPA with ITOCHU, which is aligned with our strategy to expand our production base and cash flow through the acquisition of high quality production assets. We are delighted to acquire high value barrels with the Western Isles production in particular having very low lifting costs and being a long-life asset with strong cash generation...

The Western Isles development includes the Harris and Barra oil fields. Production has exceeded expectations since it started in November 2017 and is currently on plateau at in excess of 40,000 boepd, with an estimated field life of 15 years.

HitecVision’s continued support provides Verus with a solid capital base which is a robust foundation for further growth."

Western Isles

The Western Isles project comprises the Harris and Barra fields, located south of Hudson. The two fields have been developed as subsea tie-backs to a new build cylindrical FPSO.  First production was originally envisaged to be in 2015, but delays to the construction of the FPSO topsides meant production was not achieved until November 2017.

Verus has therefore acquired the Western Isles post first oil with a few months of production history. The field is Dana Petroleum's (76.9%) first fully operated full development and therefore a landmark project for Dana.

The field is estimated to contain c.50mmbbl oil and c.2bcf gas, peaking at 40mbopd production. Produced gas will be used for fuel until the field becomes gas deficient at which time it will look to import gas.

Western Isles cylindrical FPSO

Read More

Valeura's value protected by another gas price increase in Turkey

Valeura has announced that BOTAS, which owns the Turkish natural gas network and imports 82% of Turkey’s gas, has announced a fourth natural gas reference price increase. This increase is 14% (63% compounded so far this year) to around USD5.60-6.00. This increase more than compensates for the recent depreciation in the Turkish Lira by maintaining the gas price in USD broadly unchanged.

On a related note, Valeura has drilled the Yamalik-1 well in the Thrace Basin and production tubing will now be fitted for clean-up and testing.

For the next well, Inanli-1, site construction is progressing with the rig being mobilised in location. Spudding is expected end Q3 2018 targeting 5,000m (800m deeper than Yamalik-1). Inanli-1 is the final earn-in well funded by Equinor, the following two appraisal wells will be funded on a working interest basis.

Once appraisal is complete, development should progress expeditiously given the plentiful gas infrastructure to enable monetisation.

#Inanli #Turkey #Valeura #Yamalik

Read More

EnQuest acquires remaining Magnus stake

EnQuest has exercised its option to acquire the remaining 75% interest in Magnus from BP, together with an increase in the interests of the Sullom Voe Terminal (to 15.1%), Ninian Pipeline System (to 18.0%) and Northern Leg Gas Pipeline (to 41.9%). The transaction will add c.60mmboe of 2P reserves and 10mmboe of 2C resources.

To fund the transaction, EnQuest is looking to raise USD138 million in a 3-for-7 rights issue at 21p/share, which represents a 46% discount to the closing share price of 6 September 2018.

Read More

Spirit Energy farms in to Hurricane's Greater Warwick Area

After many years of trying to find a farm-in partner, Hurricane Energy has finally succeeded in bringing in farminee for its Greater Lancaster/Warwick Area in the West of Shetlands.

Hurricane's tough journey had the company combating a falling oil price environment coupled with industry scepticism around its "fractured basement reservoir" plays. In 2017, it ploughed on alone with the sanction of an Early Production System ("EPS") at the Lancaster field without a partner.

With the improving oil price environment and refreshed North Sea corporate landscape, including the likes of Spirit Energy, Hurricane has finally found a partner for its assets. However Hurricane is not giving away its prize of the Lancaster field, instead Spirit Energy is buying into the yet undrilled and untested Warwick prospect and to be appraised Lincoln discovery.

Spirit Energy has farmed into 50% of Lincoln and 50% of Warwick licences, together the Greater Warwick Area (“GWA”) for a committed carry of USD387 million. This transaction is a major stamp of approval for Hurricane and a major step forward ahead of first oil from Lancaster. It also accelerates appraisal of the overall West of Shetland fractured basement play with significant appraisal drilling brought into 2019/20.

Greater Warwick Area is now envisaged to progress as its own separate development to the Greater Lancaster Area, although utilising the same Aoka Mizu FPSO export facilities and infrastructure.

The spending commitment by Spirit Energy will be spread over a number of phases:

• Phase 1: USD180.6 million carry to drill, log and test three exploration/appraisal wells (2019) including funding the purchase of long lead items and carrying out modifications of the Aoka Mizu
• Phase 2: USD187.5 million carry (Subject to FID following Phase 1) for 75% of costs for tie back of one of the GWA wells to the Aoka Mizu, FPSO modifications, and tying the vessel into the West of Shetland Pipeline (WOSP) system for gas export
• Phase 3 and 4: Hurricane will pay its share of the Phase 3 and 4 programme. Phase 3 includes three appraisal wells (2020) and is expected to provide the required well stock for the first phase of a full field development. Phase 4 comprises the front-end engineering and design necessary for the first phase of a full field development of GWA. Upon commencing this phase operatorship is to transfer to Spirit Energy
• Phase 5: The first phase of a full field development (expected 2021) Spirit Energy will carry between USD150 – 250 million of Hurricane’s costs through the development, dependent on the size of the 2P reserves at FID. Up to 300 mmboe would result in a contingent carry of USD150 million and for each barrel above this level, the contingent carry would increase by $0.50/mmboe, up to a maximum of USD250 million for a development of 500mmboe

#Hurricane #Warwick #Lancaster #Spirit #WOS

Read More

Tolmount sanctioned with first gas by end 2020

Premier Oil, Dana Petroleum and Antin has sanctioned the Tolmount gas field in the UK North Sea which is planned to be onstream towards the end of 2020. This represents major project for the partners with 500bcf of gas and plateau production of 300mmcfpd.

This field will further help steer the fortunes of the two upstream partners. Premier Oil is looking for longer term growth projects having been financially constrained for years under a debt mountain and now that Catcher is onstream. For Dana, the company has been strategically lost with its parent KNOC providing minimal guidance over the years.

In progressing this project, Premier Oil has struck a smart deal. Although not necessarily the cheapest form of financing, Premier Oil has been able to secure a deal which massively limits its capex spend on the development. By bringing in Antin to fund its share of the platform and export pipeline to the Easington terminal, it has halved its capex spend to USD120m which will largely be for drilling. In return, Antin will charge a tariff for use of the platform/pipeline transportation from Premier Oil’s share of revenues.

#Premier #KNOC #Dana #Tolmount #NorthSea #Antin

Read More

Energean bearing fruit in the Eastern Med

Energean has published a new CPR highlighting the conversion of 2C resources into 2P reserves at the Karish and Tanin fields. Net 2P reserves for the fields now stands at 298mmboe with 22tcf gas and 32mmbbl liquids (gross) being upgraded. The company’s net 2P reserves including its Greek fields are now at 349mmboe.

A further 0.2tcf gas and 1mmbbl liquids remain in contingent resources relating to the Karish B reservoir and will be upgraded upon successful well production testing.

Energean is now thinking beyond its flagship development project with the recent award of its exploration acreage offshore Israel (Blocks 12, 21-23 and 31). These are estimated to contain 7.5tcf gas and over 100mmbbl liquids prospective resources. This massively enlarges the company’s exploration portfolio beyond the 1.3tcf Karish North prospect being drilled in early 2019. The company has secured an extension on the drilling rig for further exploration drilling should it have matured targets over the next 12 to 18 months.

#Karish #Tanin # Israel #Energean #EastMed #Greece

Read More

All Tawke on Peshkabir: Is Tawke production declining?

The Tawke PSC encompasses the Tawke and Peshkabir fields. In 2017, operator DNO commenced production at Peshkabir and in 2018, drilled the Peshkabir-4 and -5 wells taking production up to 30-35mbopd.

However, the limited disclosure by DNO means it is difficult to break out the production on the Tawke PSC between the Tawke and Peshkabir fields. Based on various disclosures between DNO and partner Genel, it appears that production at Tawke is declining, masked by an uptick in Peshkabir.

The Tawke PSC has been producing just c.110mbopd. However closer study reveals that Peshkabir production is now compensating on falling production on the main Tawke field, and hence maintaining the c.110mbopd levels across the PSC.

Although more production history is required, there are now concerns of the problems encountered at TaqTaq by Genel where reserves and production were significantly reduced as water started to be produced from the reservoirs.

#Tawke #Peshkabir #TaqTaq #waterbreakthrough #Kurdistan #DNO #Genel

Read More

Total sells Norweigian assets to AkerBP for USD205 million

Total has agreed to sell interests in a portfolio of 11 licences in Norway to AkerBP for a cash consideration of USD205 million. The portfolio includes four discoveries with net recoverable resources of 83mmboe.

The acquisition allows AkerBP to consolidate its position around the Alvheim, NOAKA and Skarv hubs as well as adding exploration acreage near its operated Ula field (AkerBP 80%). Increasing stakes in fields and discoveries and having control of tie-backs will help improve the economics of hubs for AkerBP.

For example two of the discoveries, Trell and Trine, are located near the AkerBP-operated Alvheim field (AkerBP 65% operated interest) and are expected to be produced through the low-cost Alvheim FPSO.

One important part of this transaction is the NOAKA area (North of Alvheim and Krafla Askja) where AkerBP and Equinor are pursuing the development for this complex with FID scheduled for 2020. Resources in NOAKA remain stranded until the partners agree a development concept and export route, but adding acreage and discoveries builds further critical mass on the path to bolstering the case for project sanction. Note that NOAKA is estimated to contain over 500mmboe in resources, but scattered across 15 discoveries hence the complexity of the development. Nevertheless this deal shows further intent by AkerBP to maximise recovery from the area.

Separately the Alve Nord discovery is located north of the AkerBP-operated Skarv field (23.8%) in the Norwegian Sea, and can be produced through the Skarv FPSO as another example of synergy.

The transaction is subject to regulatory approval. The full list of licences being transferred is as follows:

Source: Wood Mackenzie

Read More

Map of the day: Ghana near-field tiebacks and upsides

#Ghana #Jubilee #Kosmos #TEN #Tullow

Read More

Trump administration hampers US oil

Plains All American Pipeline company has been denied a request for an exemption from steel import tariffs. This will hit plans to build much needed takeaway capacity for the evacuation of oil from the Permian Basin. The capacity bottleneck has already manifested in large discounts for Midland-Permian crude which is trading at a discount of c.USD12/bbl to WTI.

Plains sought an exemption for high-grade steel from Greece for its 585mbopd Cactus II pipeline to the port of Corpus Christi. However the government purports that the steel is domestically produced in “sufficient and reasonably available” quantities in denying the request. Plains is now looking to challenge the decision.

Plains released a strong statement criticising the government following the decision: “Collecting a tariff on steel pipe orders for projects like this constitutes a tax on the construction of critical U.S. energy infrastructure…and is a significant unintended consequence of current trade policy and risks U.S. energy security and American jobs.”

Read More

Kosmos hit by rig contract as dry hole is announced in Suriname

Kosmos could be liable for a share of the onerous contract in Ghana entered into by Tullow Oil, operator of the Jubilee and TEN fields. This could equate to over USD100 million for Kosmos which would wipe out Q2 2018 revenues and earnings since the beginning of the year.

Tullow, on behalf of the field partners entered into a long-term rig contract for the West Leo rig in 2012 for work in the Jubilee and TEN area. In 2016, Tullow declared force majeure under the contract, driven by the border dispute between Ghana and Côte d’Ivoire which forbid any further drilling around the TEN fields until the matter was resolved.

Although the partners had a choice to redeploy the rig at the Jubilee field to undertake further work, it decided not to given issues with the FPSO turret and therefore uncertainty over ongoing development at the field. In an effort to save costs, the partners declared force majeure on the rig contract, which England’s Commercial Court has now ruled was not a valid reason to trigger force majeure. The liability between the TEN and Jubilee partners stands at USD254 million.

This comes on the back of bad news for Kosmos in Suriname where the Anapai-1 well was dry. This extends the dry run of Kosmos and follows the high profile dry well at Requin Tigre (see Kosmos' end of a winning streak with dry well at Requin Tigre).

Read More

The nonsense of releasing US Strategic Petroleum Reserves

Trump is on a mission to contain oil prices and has been sending strong tweets and messages blaming OPEC and supposed ally Saudi Arabia for the current levels of “high” oil prices. The Trump administration’s policies are in complete dissonance as tampering with the Iranian sanctions is a key cause of the tightening of global oil supply and strong noises around US energy independence is in complete opposition to Trump asking OPEC to pump more oil, which illustrates that the US is far from energy independence and still needing to call up OPEC in times of need.

Trump is now considering tapping the US strategic petroleum reserves (“SPR”) in an attempt to lower oil prices in the run up to the US midterm elections; logic being that this will translate into lower prices at the pump. However, his administration may be wrongly conflating the two with no guarantee that a release of SPR will lower gasoline prices.

A release of SPR crude will likely do little to alleviate pump prices. US refiners are already running at near full capacity and additional crude will have limited ability to be absorbed and converted to gasoline domestically. In fact, additional crude on the market will likely depress WTI and increase the profits of the refiners rather than the benefits trickling through to the pumps. Furthermore, the SPR holds light crude whereas the feed slate for US Gulf refiners is typically heavy crude from South America.

The SPR was established in 1975 following the Arab oil embargo in 1973. The US, together with 28 other countries, are required by the International Energy Agency to hold no less than 90 days of import cover measured against the previous year’s net imports. It is designed to meet domestic demand in the case of supply disruptions. In the US, the SPR is held across four sites on the Gulf Coast with a total of 660mmbbl of mostly light crude. They can be released with a 13-day window once the POTUS gives the decision.

Read More

Ophir lost in space

Ophir’s Equatorial Guinea Fortuna FLNG project faces further uncertainty as the government threatens to pass the Block R licence which contains the gas field to another company in December when it expires. It has given Ophir an ultimatum to present a firm financing plan and progress the FLNG project.

The FLNG concept is still relatively new technology and together with the geography, Ophir has found it challenging to raise bank financing or secure partners over the past few years when the global LNG outlook was uncertain. With the improving LNG demand outlook, Ophir now faces competition from US LNG which has accelerated miles ahead.

The government has not named who it will pass the licence to in December, but this could be the likes of Perenco, who started export at its own FLNG project in Cameroon earlier this year, or Kosmos who is pursuing the Tortue FLNG project with BP in Mauritania/Senegal.

Shortly after the government’s intention were made public, Ophir announced that it had entered into a farm-out agreement on its EG-24 licence in Equatorial Guinea to Kosmos, further lending credence to the hinted company being Kosmos. Under the farm-out, Kosmos will acquire a 40% non-operated interest and fully carry the cost of a block 3D seismic survey. For Kosmos, the deal supplements its recently acquired positions in Okume and Ceiba back in 2017.

Read More

Karish and Tanin to supply Cyprus

Energean announced earlier this month that it is seeking approval to build a pipeline from its Karish and Tanin fields to the shores of Cyprus from the Cypriot government. The company has already contracted 4.2bcm p.a. from its fields with Israeli buyers and is progressing with further gas supply contracts. The Karish and Tanin project has already been sanctioned, so further supply contracts are not necessary for FID but will strengthen the commercialisation of the project. Energean’s FPSO once online will have capacity to handle c.800mmcfpd.

There are ample of buyers in the Eastern Mediterranean for gas given gas shortages and growing demand in the region. Cyprus in particular is a country keen to secure more gas as it has just put out a tender for LNG import and Floating Storage and Regasification Unit construction.

Reuters noted that Energean will bid for further supply contracts in Israeli power plants with the coal-to-gas switching initiative providing further opportunities for the company.

Read More

ConocoPhillips' mix of a North Sea portfolio

ConocoPhillips' is one of the largest operators in the UK North Sea, being the operator of the Britannia area, the J-Area and large swathes of the Southern North Sea. ConocoPhillips is also a non-operated partner in the giant Clair field.

Clair is one of the largest oil fields in the UK offshore and located in the West of Shetlands which is making a name for being the last frontier of the UK and is increasingly attracting further exploration activity. The Clair field was brought onstream in 2005 and is currently undergoing a second phase of development (Clair Ridge). Clair Ridge is planned to come onstream in Q4 2018 with operator BP targeting an additional 640mmbbl which will extend the life of the Clair Area beyond 2050. As soon as Clair Ridge is onstream, the partners will be planning for the Phase 3 of the development known as Clair South.

On the operated assets, Britannia is one of the largest gas fields in the UK which has acted as a hub for various tie-backs over the years. The J-Area, although now beginning to mature, has been a highly successful gas hub in the Central North Sea where more infill drilling and exploration activity is planned into 2019 and 2020.

The Southen North Sea assets are the most mature with some going into decommissioning. ConocoPhillips has widely announced the closure of the Theddlethorpe gas processing plant which is the terminus for its CMS pipeline. This will lead to early/forced decommissioning of all the fields which currently utilise the CMS pipeline as the export route including the Faroe and Tullow Schooner and Ketch fields which will cease production in August 2018.

The ConocoPhillips' UK portfolio is concentrated around a few hubs and excluding the Southern North Sea, has a good amount of life remaining with current production at c.80mboe/d.

Read More