Forties Pipeline System reopens in time for the New Year

On 11^th December, INEOS the owner of the Forties Pipeline System, had discovered a hairline crack in the pipeline at Red Moss near Netherley. The crack continued to grow upon monitoring and the entire system was subsequently shutdown. INEOS announced this morning that the repairs are "mechanically" complete with the system being restarted - export rates should resume to previous levels around the new year.

The system carries c.450mbbl/d of production from the North Sea to the Kinneil processing facility in Scotland. The 235 mile pipeline links more than 80 North Sea fields and delivers almost 40% of UK North Sea production. Upon its outage, Brent crude jumped to USD65/bbl signalling the importance of North Sea production to the global oil markets.

Read More

Amerisur putting plans in motion

Amerisur is a story of slow and steady wins the race. The company had targeted 10mbbl/d to be reached a few years ago - with current production only at c.7mbbl/d, this target has clearly fallen by the wayside. Amerisur has learnt, and is continuing to learn, that doing business in Colombia (and Ecuador) is not straightforward and getting necessary government approvals can take months and sometimes years rather than weeks - the OBA pipeline being a case in point. Layer on top of this the local community liaisons and security issues in the Putumayo Basin, one begins to understand the impediments to Amerisur's progress over the past years.

Nevertheless the Amerisur team has managed its portfolio and navigated the winding road of being a Colombian E&P carefully and is now one of a small handful of successful producers in the Putumayo Basin. As well as building up its asset base beyond what was effectively a single asset company in Platanillo, Amerisur has made good progress on the exploration and appraisal front which will set the company up for the longer term.

Amerisur is a company we continue to watch with interest and with enough patience, is a rare success story that will materialise over time.

Drilling Update

North Platanillo
At the start of 2017, Amerisur had success at Plat-22 encountering 43ft of U-sands and flowing at 800bbl/d, extending the Platanillo field north. This was followed by Plat-21 which derisked the extension further testing 430b/d.  Plat-25 came in below expectations, but was sidetracked to target better reservoir quality and additional pay thickness, and was brought on production at 180 bbl/d. In December, Plat 27 encountered net pay of 12ft in the U and 9ft in the T sands. This success could add up to 10mmbbl of reserves.

In 2018, drilling activity on Platanillo switches to the N sand stratigraphic play with the upcoming planned three-well programme targeting the 18.8mmbbl N Sand Anomaly (expected to start in Q1 2018).

Mariposa (CPO-5, Amerisur 30%, ONGC 70%)
Mariposa-1 was successfully drilled in May 2017 which flowed at 4.6mbbl/d 41API light oil. The well was drilled to a total depth of 11,556ft with an indicated 120ft net pay in the L3 Sands. The well is now producing around 3,200b/d (gross) on Long Term Test on a restricted choke.

Further drilling is planned on the block in 2018 (including Indico-1 and Sol) which could add material reserves to the portfolio.

Read More

Premier's Christmas present

Premier Oil announced today that the Catcher field achieved first oil on 23^rd December, on schedule and almost 30% below budget. Initial production will be c.10mbopd as gas processing and water injection modules are commissioned. Production will be ramped up in phases through H1 2018 as the Varadero and Burgman fields are brought onstream increasing production to 60,000mboepd (gross).

The Catcher partners are Premier Oil (50% operator), Cairn Energy (20%), MOL (20%) and Dyas (10%). For Premier Oil, Catcher will account for c.25% of 2018 production with successful ramp up of the field important to deleveraging the balance sheet next year. For Cairn, this will diversify the production base following first oil at Kraken (29.5% interest) earlier this year.

Read More

Kosmos: An unfinished West African story

Kosmos has had a busy 2017 chasing a high risk high reward oil play and working up its Senegal/Mauritania gas resources.

In the second half of the year Hippocampe and Lamantin both came in dry ending the company's campaign for higher value oil. It can now focus on developing the c.40tcf of gas found at Tortue, Teranga, Yakaar and BirAllah. It has hopefully found the right partner in BP who farmed-in in late 2016. Although not generally seen as a big gas player, BP is increasingly focussed on gas as it turns to the future - the major is shifting to investing in large scale gas projects and look to increase global production to c.60% gas from the current c.50%.

When we met with Kosmos earlier this year, they noted that they had their choice of Supermajor when seeking a partner with attractive offers from the usual suspects. Kosmos see BP as the partner who is fully aligned with them, with BP going as far as setting up Senegal/Mauritania a separate profit centre to demonstrate their seriousness.

The West African gas play continues to be derisked with the 60tcf Requin Tigre prospect being drilled and results expected in early 2018 which would increase gas resources in the basin to c.100tcf if successful. This could add a significant leg to a multi-phase LNG project. However, a dry well would dampen the high mood in the basin with the growth outlook more constrained.

FID around Tortue is planned in 2018, although success at Requin Tigre could change the development order with Tortue (which straddles the Senegal/Mauritania border) delayed. It should also be noted that gas would come onstream at a time of a gas glut with LNG in North America, East Africa and Australia coming onstream.

Read More

AWE: an unexpected union

The AWE Board has unanimously recommended a revised bid by Mineral Resources (“MinRes”). The offer terms are A$0.415 in cash and between 0.0198 and 0.0277 MinRes shares per AWE share. The exchange ratio will depend on the VWAP for the 10 days prior to the scheme vote. The previous offer was a full scrip offer at A$0.81.

This values the offer at an implied price of c.A$0.83 per AWE share and will be implemented by a Scheme of Arrangement, which will require 75% shareholder approval with the shareholder meeting to be held in mid-April 2018. Shareholders will have the option to receive 100% cash or 100% scrip subject to scale back to ensure total transaction consideration is 50% cash and 50% scrip.

After four years of “tug-of-war” between AWE and various bidders (Senex in 2013, Lone Star in 2016, CERCG in 2017 and various others which have not been made public), it looks like the AWE Board have finally selected a suitor. Although AWE could have gone down the “do it alone” route, the uncertainty on timing of new production from Waitsia and/or Ande Ande Lumut cast a shadow over the company’s story and its future with a declining production profile.

MinRes immediately answers the question of future gas offtake: Min Res has a requirement for c.30TJ/d of gas based on current plans to convert all of its internal power generation to gas fired plant and to use as the primary fuel source for its Lithium/Graphite related downstream processing plants. This gas requirement is expected to grow with the likely conversion of 26 mine sites (growing to 40) to gas as well as potential for more downstream projects. The rationale for MinRes acquiring AWE is so that it can lock in its gas costs for the next 20–30 years. Min Res also plans to provide gas to its mining clients under long-term gas supply contracts.

AWE shareholders will buy into a new story of a miner/mining service provider with its own growth story. The variable cash and scrip components will likely promote higher acceptances and will provide a way for AWE shareholders to fully realize their investment if they choose not to go into MinRes.

MinRes offer is c.14% above the previous all cash A$0.73 bid from CERCG – MinRes would have the right of response to match any competing offer if CERCG or another party came back with a superior proposal. The deal is subject to a break fee of A$5.2 million.

Read More

Zohr record breaker

In record time for a deepwater gas development of this scale, Eni has announced first production from Zohr. The field was discovered in August 2015 and FID taken in early 2016 - Eni achieved first gas from discovery in 2.5 years.

Zohr is the largest gas discovery ever made offshore Egypt and is located in the Shorouk block. The field has begun production at 350mmcfpd and is expected to grow to 1bcfpd by mid-2018. The speed of development is a testament to Eni's "Dual Exploration Model" which was adopted in 2013. Under this model, Eni works the exploration, appraisal and development planning and phases in parallel while bringing in minority partners at the same time to help fund the costs.

Zohr has >30tcf of GIIP and forms an important piece of the jigsaw to solving Egypt's short gas problem. The new production will help feed the hungry and growing domestic gas demand which Egypt has been trying to manage by raising domestic prices on the one hand and incentivising further gas exploration/development on the other.

The Zohr partners are Eni (60%), Rosneft (30%) and BP (10%). Eni is co-Operator of the project through Petrobel, which is jointly held by Eni and EGPC.

Read More

Kurdistan producers get paid for September

DNO and Genel Energy have reported receipt of USD54 million from the KRG for September crude sales from the Tawke licence - shared by DNO (USD40.7 million) and Genel (USD13.6 million) in line with the interests in the licence.

In addition, a payment of USD10.8 million has been received by Genel and DNO, representing 7.5% of gross Tawke licence revenues during October 2017, as provided for under the receivables settlement agreement.

Separately, the Taq Taq field partners have received a payment of $9.7m from the KRG for September oil sales - Genel's net share of the payment is USD5.3 million.

This is the first set of payments that has been made following Kurdistan’s independence election and the choking back of oil exports from the Kirkuk Area, which has limited the KRG’s cash flows. Although a positive, concerns will continue around the continuity of payments.

Read More