Det Norske-BP: the Norwegian megaforce

On 10th June, Det Norske announced that it will merge with BP Norge through a share purchase transaction to create the leading independent E&P company on the Norwegian Continental Shelf. The company will be renamed Aker BP, with Aker and BP as main industrial shareholders holding 40% and 30% of the company respectively; the remaining 30% in Aker BP will be held by Det Norske’s other current shareholders. Note that Aker is currently Det Norske’s main shareholder with a 49.99% of the company. The effective date of the transaction is 1st January 2016 and it is expected to close at the end of 2016, subject to approval by the relevant authorities.

For some time, BP have been looking to sell down their Norwegian position but having been unable to do so for cash, it is interesting to note that they have now accepted shares and follows the trend of Statoil’s recent acquisition of a shareholding in Lundin. The BP branding on the name of the new company now suggests that they may see themselves as longer term players in the Norwegian Continental Shelf.

Det Norske will issue 135.1million new shares at a price of NOK80/share to BP as consideration for all the shares in BP Norge. BP Norge will subsequently be a wholly owned subsidiary of Det Norske. Concurrently, Aker will acquire 33.8million of these shares from BP at the same share price to achieve the agreed-upon ownership structure. The acquisition of BP Norge includes the assets, a tax loss of USD267million and a net cash position of USD178million. All of BP Norge's roughly 850 employees will transfer to the combined organization upon completion of the deal.

Aker BP will hold a portfolio of 97 licences on the Norwegian Continental Shelf, of which 46 are operated. The combined company will have an estimated 723mmboe 2P reserves, with joint production of c120mboepd, with scope to organically double production to more than 250mboepd by the early 2020s. Aker BP will benefit from the combined strength of Det Norske's efficient, streamlined operating model and BP's long experience in Norwegian offshore operations, asset knowledge, technical skills and international experience. Det Norske and BP believe the larger independent company will be able to actively pursue M&A opportunities on the NCS.

Øyvind Eriksen, chairman of the board of directors of Det Norske commented: "Aker BP will leverage on Det Norske's efficient operations, BP's international capabilities and Aker's 175 years of industrial experience. Together, we are establishing a strong platform for creating value for our shareholders through our unique industrial capabilities, a world-class asset base, and financial robustness."

BP group chief executive Bob Dudley commented: "BP and Aker have matured a close collaboration through decades, and we are pleased to take advantage of the industrial expertise of both companies to create a large independent E&P company. The Norwegian Continental Shelf represents a significant opportunity going forward and we are looking forward to working together with Aker to unlock the long term value of the company through growth and efficient operations. This innovative deal demonstrates how we can adapt our business model with strong and talented partners to remain competitive and grow where we see long-term benefit for our shareholders."

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Barents Sea licence awards

The Norwegian Ministry of Petroleum and Energy has issued ten new production licences in the Barents Sea as part of Norway’s 23rd licencing round, following applications made by 26 companies in January. This is the first time since 1994 that new exploration acreage has been made available to the industry in the southeastern Barents Sea. 

From the International E&P names:

• Lundin has been awarded interests in five licences (three as operator)
• Det Norske has been awarded interests in three licences (one as operator)
• Tullow has been awarded an interest in one licence (non-operated)
• Cairn (through its Capricorn Norge subsidiary) has been awarded three licences (one as operator)

The companies have committed to binding work programmes that primarily include a drill or drop decision to be made within two years.

Barents Sea licence areas
Source: NPD

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Statoil acquires a further stake in Lundin Petroleum

On 14^th January, Statoil announced that it had acquired 37.1 million shares in Lundin Petroleum, corresponding to 11.9% of the company. Statoil says that it paid c.SEK4.6 billion for the shares, which equates to a price of SEK120/share or a 28% premium to the share price close as of yesterday at SEK97. Statoil purchased the shares over the past few weeks and says it is supportive of Lundin management, its board of directors and strategy, but there is currently no plan to increase its shareholding in the company.

This article was originally posted on 14^th January 2016 and has since been updated

Statoil says "this is a long term shareholding. The Norwegian Continental Shelf is the backbone of Statoil's business, and this transaction indirectly strengthens our total share of the value creation from core, high value assets on the NCS". Despite the longer term strategic rationale, the move is unexpected. Lundin is one of the more expensive E&P stocks and the transaction further increases Statoil’s exposure to the giant Johan Sverdrup development. Questions are now being asked by the market on whether Statoil can continue to pay its dividend.

From an E&P sector perspective, the move is encouraging as it demonstrates industry interest in the subsector, and the news should help shore-up Lundin’s share price. Nevertheless, corporate activity is likely to remain muted until the oil price starts to recover and confidence returns to the sector.

**Update**
On 3rd May, Statoil and Lundin announced than it had acquired an additional 15% in  Edvard Grieg (licence PL388) from Statoil in exchange for issuing 31.3million shares to Statoil worth USD578million. The transaction is expected to close on 30^th June 2016, pending regulatory approvals.

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Ophir's Fortuna farm-out terminated

On 29^th April 2016, Ophir announced that it had terminated its Fortuna farm-out discussions with Schlumberger. Back in January, Ophir announced that it had entered into a non-binding Heads of Terms Agreement with Schlumberger for upstream participation in the Fortuna FLNG development that would result in the oilfield service company carrying Ophir to first oil. However, the two companies have been unable to complete the transaction on the terms agreed and discussions have been terminated.

Ophir’s management must now demonstrate its continued confidence in its ability to attract an alternative partner for the FLNG project. Although development costs have continued to fall as studies continue, reservations still exist about any plans for Ophir to self-fund and sole risk this development.

Having completed the upstream FEED studies, gross upstream capex requirement from FID to first gas has been reduced again, to USD450-500million from USD600million. Ophir continues to progress the project, and fully-termed LNG sales agreements are nearing completion. Offtake selection has progressed to a decision between three alternative solutions. But given additional time is required to fully develop these options to binding agreements, FID has been pushed back to Q4 2016 with first gas now forecast for 2020.

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Gran Tierra the Consolidator

On 30 March, Gran Tierra announced the private offering of USD100 million convertible notes which successfully closed on 6 April. The new funds will allow Gran Tierra to accelerate its exploration programme and places the company in a strong position to act as consolidator in Colombia.

Gran Tierra completed two acquisitions in Q1 2016, building out its portfolio particularly in the Putumayo Basin of southern Colombia and supplementing its interests in the Costayaco and Moqueta fields. With development drilling on Costayaco and Moqueta due to end through Q1 2016, the company will be starting its 2016 exploration campaign shortly, commencing on the newly acquired PUT-7 block. The newly acquired assets provide ample opportunities to accelerate reserves and production growth through the drill bit.

Through a combination of acquisitions and re-investment in the core producing fields, the company is expected to increase production by c.20% from 2015 levels of 23mboepd to c.28mboepd in 2016. The company retains a strong balance sheet with c.USD180 million of cash following the recent fund raise. The company’s cash position, together with operating cash flow of c.USD100 million (if Brent averages USD40/bbl in 2016) is more than sufficient to fund its 2016 base capex budget of USD107 million and its discretionary budget of an additional USD61 million.

The peace process between the Colombian Government and the FARC is expected to conclude shortly and it is anticipated that southern Colombia, historically an area of focus for the FARC, should benefit from greater stability.

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Further payments by the KRG

DNO and Genel Energy announced on 22 March that the Tawke and Taq Taq participants have been paid by the Kurdistan Regional Government (“KRG”) for oil sales during February. News of another month of payment should help boost sentiment.

Given that the export pipeline was out of service during the second half of February, sales at Taq Taq and Tawke were down materially month-on-month at 62,091bopd and 73,124bopd, respectively. Sales into the local market from both fields were, however, invoiced at the wellhead export netback price, in line with the payment mechanism announced by the KRG on 1 February; this process helped limit the month-on-month reduction in revenues. Flows into the export pipeline resumed on 11 March.

Genel, as operator of Taq Taq received USD12.6 million for oil exports, down from January’s USD16.3million. An additional USD2.5 million payment has been made towards recovery of the receivable, down from USD3.2 million.

DNO, as operator of Tawke has reported receipt of USD11.29 million for exports, down from USD17.99 million in January. An additional USD2.17 million has been paid for past deliveries, down from USD3.46 million in January.

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Troubles at Jubilee

Jubilee FPSO

On 18^th February, Tullow and Kosmos warned of a potential maintenance issue with the Jubilee FPSO’s turret. At this stage oil production and gas export is continuing as normal but the vessel is now set to be held in position by tugs rather than weathervane. The implications are that the turret may require maintenance that results in unscheduled shut-in and additional costs to rectify the issue. The length of any repair work is not yet known. Jubilee is forecast to contribute nearly half of Tullow’s H1 2016 production, and all of Kosmos’ H1 2016 production.

Following a recent inspection of the turret area of the Jubilee FPSO by SOFEC, the original turret manufacturer, a potential issue was identified with the turret bearing. As a precautionary measure, additional operating procedures to monitor the turret bearing and reduce the degree of rotation of the vessel are being put in place. SOFEC will now undertake further offshore examinations.

New field start-up have been a cause of concern for investors, as a number of recent offshore projects have cost more and taken longer to deliver. However, the news is a reminder of the risks of the focussed nature of E&P portfolios – many of the international E&P companies are dependent upon a single asset, and even the largest companies – including Tullow and Lundin (Edvard Grieg) remain heavily depend on just a couple of assets.

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Senegal offshore reaches threshold for commerciality

On 8th February, FAR Ltd announced an updated independent resource report (by RISC) of the SNE discovery offshore Senegal (Cairn 40%, ConocoPhillips 35%, FAR 15% and Petrosen 10%). The report increases contingent resources for the discovery to 240mmbbl 1C (from 150mmbbl), 468mmbbl 2C (from 330mmbbl) and 940mmbbl (from 670mmbbl). This assessment includes the SNE-1 discovery well and subsequently reprocessed (more accurate) 3D seismic. Significantly the update does not include the successful SNE-2 appraisal well. Given the lack of major oil discoveries worldwide, SNE is an important find (largest since 2014) and on further positive appraisal drilling, will be an increasingly desirable asset.

Cairn previously indicated that around 200mmbbl is the commercial threshold to underpin a 'foundation' development offshore Senegal, where fiscal terms would yield a 20% IRR at USD45-50/bbl oil price. The resource report would imply that the discovery now has the scale to support a development and the SNE-2 appraisal well demonstrates deliverability following strong production tests (8,000bbl/d from blocky sands and 1,000bbl/d from hetrolithics). The next element of the appraisal campaign is to test for connectivity and the upcoming drilling should help to determine this. Significant further drilling needs to be completed; however results to date are encouraging.

The second appraisal well SNE-3 has now been cored and logged with production test results expected later in February. This will be followed by the Bellatrix exploration well testing a 168mmbbls P50 prospect, then deepening to test the northern extent of SNE (no production test planned). In addition to a more comprehensive resource update in mid-2016, there is the option for three further wells later this year. With drilling time currently ahead of expectations, there is scope to drill an additional well without extending timeline or budget.

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KRG switches to PSC terms to conserve cash outflows to IOCs

Kurdistan exports and payments to IOCs remain unpredictable with the situation subject to change on a daily basis. The Kurdistan Regional Government’s (“KRG”) monthly export report and news flow from the E&Ps gives a glimmer into the dynamics of operating in and getting paid in Kurdistan.

On 4^th February, the KRG published its January 2016 monthly export report – the KRG exported 602mbbl/d through the Kurdistan pipeline network to the port of Ceyhan in Turkey; this is down from 644mbbl/d in December and the Q4 2015 average of 648mbbl/d. The export line was down for just one day last month. Fields operated by the KRG contributed 452mbbl/d (Q4 2015 average was 476mbbl/d), while the North Oil Company’s fields contributed 150mbbl/d (Q4 2015 172mbbl/d).

Today, Genel announced that the Taq Taq field partners have received a gross payment of USD16.3 million from the KRG for oil exported through the main export pipeline; this is down on the USD30 million paid in recent months, as the KRG employs the terms of the Kurdistan’s Production Sharing Contracts (“PSC”) for the first time, rather than an ad hoc payment system. Genel's share of the gross Taq Taq payment fell to USD9 million, from USD16.5 million. The impact of the shortfall has been softened somewhat by the payment of an additional USD3.2 million (USD1.8 million net to Genel) to cover past receivables.

The change to the PSC was clearly intended to reduce the KRG’s cash outflows, so the payment reduction should not be a surprise. The silver-lining is that payments are now linked to the oil price and the PSC provides greater certainty on asset valuations and the merits of increasing spending to help stabilise and potentially grow oil production. However the payment made in January reflects comprise of a number of components: crude quality adjustment, deduction of transportation charges, handling costs as well as the PSC terms, and in general, greater clarity on these variables will need to be disclosed in order to better forecast future cash flows.

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Lundin CMD: Why doesn't the market understand?

On 3rd February, Lundin Petroleum held its Capital Markets Day, which included new guidance on capex, opex, production profiles and 2016 drilling plans. However, greatest emphasis was placed upon a review of the company's tax position, and the benefit of the weakening Krona on costs. 

The CEO expressed strong frustration with shareholders and the low valuation being attributed to the company, remarking that closer examination of the company’s financial statements should be undertaken, specifically around the tax and FX hedging position. Indirect reference was made to the recent Statoil transaction, where Statoil was willing to pay SEK120/share, a premium of 28% to the share price at the time and banks’ willingness to extend Lundin Petroleum’s RBL debt facility.
Tax synergies make a sizeable contribute to the value of Norwegian E&Ps such as Lundin Petroleum, which are subject to a tax rate of 78% on their profits. Lundin provided an update on its tax pools, which total NOK16.8bn (c. USD2 billion). However, one quote cut to the chase: "if Brent stays below $65/bbl, Lundin won't pay any cash taxes until the Johan Sverdrup field is brought on stream in late 2019".

In 2015, the company underspent on its USD1.28 billion capex budget by c.USD250 million, and a significant portion (c.50%) was due to the weakening Norwegian Krona. Savings were also achieved on operating costs and salaries in Norway. Looking ahead, management sees potential for further saving – Phase 1 development costs at Johan Sverdrup have fallen as a result of the current deflationary environment, but given 60% of the capex is priced in Norwegian Krona (at NOK6/USD) costs should fall further as the currency now trades at NOK8.6/USD. Importantly, Lundin has locked in a significant portion of this gain – the company has hedged NOK7.5 billion (USD890 million) at c.NOK8.4/USD over the period 2016-19.

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Amerisur makes a move

 

On 26 January 2016, Amerisur announced the acquisition of Platino Energy (Barbados) Ltd, a subsidiary of COG Energy, a private E&P with a focus on Colombia. The consideration for the transaction is USD7 million which we be paid entirely in Amerisur stock, through the issuance of 22.7 million new shares. A further payment of USD500,000 in cash will also be made in respect of fixed assets. As part of the deal, COG is entitled to a 2% overriding royalty if production in the acquired blocks exceeds 5,000bopd.

The transaction adds prospective acreage (190mmbbls unrisked resources) to Amerisur’s Putumayo Basin portfolio at a limited cost with drill ready prospects close to the company’s Platanillo field. Commitments are limited to USD12 million across the next three years. New production from the blocks would have access to Amerisur’s new pipeline to Ecuador, once completed.

The acquired assets include:

• PUT-8 (Amerisur 50%) immediately west of Platanillo with 45mmbbl in unrisked resources in similar structure
• Coati Block (Amerisur 100%) holds 79mmbbl unrisked resources and the Temblon field with long-term testing potential; the next exploration well is partly carried by Canacol (part of farm-in deal for 20%, excluding Temblon)
• Andaquies Block (Amerisur 100%)

The blocks have no or limited X-factors and are covered by 2D and 3D seismic. Drilling commitments include one exploration well on PUT-8 and the Andaquies Block by May 2017 (although some environmental licenses are still to be secured).

On the export pipeline, Amerisur continues to engage with the Ecuadorean authorities to secure the final EIA approval and complete construction of their strategic pipeline connection through Ecuador. This will reduce transportation costs and increase off take capacity.

Amerisur's acquired and existing acreage
Source: Broker research

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Gran Tierra strikes again

On 15th January, Gran Tierra announced the acquisition of PetroGranada’s interest in the highly prospective Putumayo-7 Block, southern Colombia. The acquisition increases the company’s interest in the block to 100% and adds two more drill ready prospects to the inventory of lower risk prospects established through the recently closed Petroamerica acquisition.

Gran Tierra will acquire all of the issued and outstanding shares of PetroGranada (which holds 50% in Putumayo-7) for USD19 million. In addition Gran Tierra  will pay a further USD4 million if the cumulative production from the block meet or exceed 8 MMbbls. The acquisition will be funded from the company’s existing cash resources; the USD200 million debt facility will remain undrawn.

The acquisition adds 1.9mmbbls 2P reserves  and further 50% working interest in the Putumayo-7 Block (GTE now has 100%). The block holds two drill ready prospects (Cumplidor is effectively an extension of the existing Quinde West discovery on the neighbouring Surotiente block). The company expects to drill the wells later this year. Wells in the region are low cost, at less than USD10 million each and the prospects lie close to existing infrastructure, enabling for fast monetisation.

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Statoil acquires stake in Lundin Petroleum

On 14th January, Statoil announced that it had acquired 37.1 million shares in Lundin Petroleum, corresponding to 11.9% of the company. Statoil says that it paid c.SEK4.6 billion for the shares, which equates to a price of SEK120/share or a 28% premium to the share price close as of yesterday at SEK97. Statoil purchased the shares over the past few weeks and says it is supportive of Lundin management, its board of directors and strategy, but there is currently no plan to increase its shareholding in the company.

Statoil says "this is a long term shareholding. The Norwegian Continental Shelf is the backbone of Statoil's business, and this transaction indirectly strengthens our total share of the value creation from core, high value assets on the NCS". Despite the longer term strategic rationale, the move is unexpected. Lundin is one of the more expensive E&P stocks and the transaction further increases Statoil’s exposure to the giant Johan Sverdrup development. Questions are now being asked by the market on whether Statoil can continue to pay its dividend.

From an E&P sector perspective, the move is encouraging as it demonstrates industry interest in the subsector, and the news should help shore-up Lundin’s share price. Nevertheless, corporate activity is likely to remain muted until the oil price starts to recover and confidence returns to the sector.

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PTTEP may pre-empt BG Bongkot process

On 12th January, it was reported that PTTEP, Thailand’s state owned oil company, is keen to acquire BG’s stake in Bongkot. The Bongkot area is located in the Malay Basin in the Gulf of Thailand and consists of various gas accumulations. It is currently owned by PTTEP (44.45% operator), Total (33.33%) and BG (22.22%). PTTEP’s potential desire to acquire this asset is in line with the strategy of Asian NOCs’ of security of supply. For BG, the disposal represents an exit of a non-core asset which supplies gas only to a domestic market and a tidy-up of the portfolio ahead of its merger with Shell.

Southeast Asia M&A environment
The Southeast Asian M&A market has historically accounted for a small portion of global M&A activity (c.7% by deal value and volume between 2009 – 2014); this is largely due to the relative sporadicity of assets that come to market. High quality assets that become available generally garner strong interest from regional players seeking to consolidate around existing positions and competencies in a part of the world which has experienced strong energy demand growth over the last decade (c.3.5% p.a. since 2000 according to the IEA).

The region is dominated by majors, select large-cap E&Ps and regional NOCs and independents. A number of North American players have recently made divestments in the region as part of wider international retrenchment plans (e.g. Hess, ConocoPhillips) – asset sales have generally been met with strong interest. Recent international new entrants include Ophir Energy (acquired Salamander Energy, RBC acted as a joint financial advisor to Ophir) and CEPSA (acquired Coastal Energy).

In the current oil price environment, gas assets with long term gas sales agreements are viewed as particularly attractive, although may not fit the strategy of players (particularly NOCs) seeking oil-weighted production exposure and more flexible supply or off-take. Although oil-weighted assets are a clearly stated preference, assets with strong production cash flows, such as BG Bongkot are also of interest irrespective of the oil/gas weighting.

Thailand is seen as an attractive area for upstream investment, despite the high level of government take. The country is a net importer of hydrocarbons with the domestic supply shortfall expected to increase as a result of continued economic growth. Economic growth supported by government spending on large infrastructure projects and improvement in political stability, whilst gas demand growth driven by switch to gas-fired power plants. The basins are established and proven with further exploration potential and licensing rounds are held regularly.

BG Bongkot sale process
Feedback from various industry players on the BG Bongkot sale process indicates that there is select interest. It is understood that the Chinese NOCs have entered the process, however the opportunity has only attracted weak interest internally; their ability to be competitive in a time critical auction situation is also questionable given increased internal procedures now required following corruption probes. Other regional players, including local NOCs, see limited strategic rationale in acquiring a domestic supply asset and some have limited financial capacity; Indonesian focused players see more compelling opportunities in their home market which are currently live or upcoming (e.g. ConocoPhillips’ interest in South Natuna Sea Block B).

PTTEP’s pre-emption has already been flagged as a key concern by a number of potentially interested parties which is likely to have discouraged some companies from participating in the process. PTTEP’s pre-emption is a key risk given its active strategy to secure supply in the region (as demonstrated by recent acquisitions of Hess’ assets in Thailand and Indonesia) and its strong balance sheet position. PTTEP pursue an active M&A strategy with 10 acquisitions made globally since 2010 and with a total disclosed deal value of ~$6bn. The state company generally acquires acreage in Thailand through licence awards, but will consider M&A for strategic assets that come to market; in 2014, PTTEP acquired Hess’ 35% in Sinphahorm and 15% in Pailin gas fields in which PTTEP was an existing partner in both.

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Kurdistan producers receive fourth consecutive payment from the KRG

Tawke processing facilities
Source: KRG

On 6^th January, DNO and Genel announced that partners of the DNO-operated Tawke field have received a gross payment of USD30 million from the Kurdistan Regional Government for oil exported through the Kurdistan Region of Iraq-Turkey pipeline. This represents the fourth export payment by the KRG since payments recommenced in September.

On 5^th January, Genel also confirmed that the Taq Taq field partners had received a gross payment of USD30 million from the KRG for oil exported through the Kurdistan Region of Iraq-Turkey pipeline with Genel’s share of the payment being USD16.5 million.

It is interesting to note that payments to the oil companies have remained flat (at USD75 million per month) during the past four months, despite a collapse in the oil price from c.USD50/bbl at the start of September to c.USD36/bbl at the end of December 2015. This means that the international oil companies' share of Kurdistan's oil revenues is slowly creeping up.

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Saudi Arabia: fissures within

King Salman

The lack of agreement between members at the 168^th OPEC meeting on 4^th December means that Saudi Arabia can continue to pursue its strategy of maintaining market share over price for a little longer. In fact, recent production figures show that Saudi Arabia is pumping record amounts of crude this year, a sign of its commitment to this strategy.

However, with oil prices reaching recent lows of c.USD40/bbl and little sign of a recovery anytime soon, questions are being raised on whether this was the right strategy to pursue. The country’s 2015 budget was based on an oil price of USD90/bbl, but with the ongoing war in Yemen and King Salman handing out money to stave off public discontent, the fiscal breakeven oil price is now approaching USD110/bbl, almost triple of where Brent is currently hovering.

Members of the royal family have begun questioning King Salman and his son, Prince Mohammad bin Salman’s, ability to run the kingdom, culminating with letters written by an anonymous Saudi prince calling for a coup against the King – these letters were published in The Guardian newspaper in September 2015. The letters assert that King Salman and his son are pursuing dangerous policies that will lead to the kingdom’s ruin. Apparently the call for the change in leadership has widespread support from within the royal family and wider Saudi society, although few will publicly acknowledge this given the history of harsh crackdowns on any dissenters.

Aside from scepticism over oil policy, the Saudi intervention in the Yemeni conflict has also become a serious source of unease inside and outside the palace walls. Prince Mohammed bin Salman, who is in his early 30s, and has been educated domestically with limited military training is viewed as lacking the necessary experience in running the country’s defences. His unofficial nickname, “Reckless”, reflects an increasingly held view that he rushed into Yemen without a well thought-out strategy and the war is now consuming a significant part of Saudi’s budget with no end to the conflict in sight.

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The Egyptian gas landscape

The Egyptian gas sector has historically suffered from underinvestment and the country has experienced a domestic supply shortfall since the beginning of 2015. Subsidised gas pricing encouraged strong demand growth during the 1990s and 2000s and at the same time, declining gas reserves in the onshore and the high cost of offshore gas developments have resulted in investment being diverted away from gas to onshore oil.

The state of the gas market has led to two major concerns for the government: (i) the energy subsidies have become habitual and a key contributor to the fiscal deficit which is unsustainable at current levels; and (ii) persistent energy shortages and brownouts have been a cause of public discontent in recent years at a time when the government is trying to restore stability post the Arab Spring. President Sisi and his administration are keen to entirely phase out energy subsidies in an attempt to tackle the fiscal deficit, encourage more responsible energy use and reinvigorate investment in gas development. The move, which should lead to gas pricing increasing over time, is welcomed by international investors and the E&P industry.

In 2015, Egypt became a net gas importer in the face of a domestic supply shortfall. This followed the diversion of LNG export volumes to the domestic market with the Gas Natural operated Damietta plant and BG operated ELNG plant being placed into force majeure in 2013 and 2014 respectively. During 2015, two LNG regasification facilities were installed at the Port of Sokhna and multi-year supply deals were concluded with LNG sellers; the lease of a third regasification unit is under consideration. Discussions are also ongoing to import gas from Israel by pipeline to supply industrial customers and the grid.

LNG imports are an expensive source of gas supply and the government is keen to boost domestic production and reduce dependence on imports. The government has envisaged a gas supply shortfall for a number of years and has agreed to increase the gas pricing or improve fiscal terms for a number of developments since 2008; the pace of these revisions has increased in recent years. In 2015, Dea agreed a new gas price of USD3.5/mcf, BG and Eni agreed up to USD6.06/mcf for new phases of offshore developments and Apache’s shale gas production will receive USD5.45/mcf.

In July 2015, Eni made the Zohr discovery which is estimated to hold 30tcf of gas in place. The large resource base has the scope to help Egypt regain gas self-sufficiency (potentially with a return to gas exports), although in the near term, the country remains in a gas shortage and reliant on imports. Zohr’s ability to effectively address Egypt’s future gas shortfall could potentially limit the liberalisation of gas pricing. Despite the discovery being in deepwater (~1,500m) and 200km offshore, initial estimates suggest that a gas price of USD4.5/mcf could result in a 15%+ IRR for the project due to the large volumes and low operating costs once onstream. However, with the government’s plan to remove subsidies and IOCs’ desire to maximise gas pricing for developments/production, the outlook for the Egyptian gas sector appears positive. In the near term, costlier gas developments may be delayed or their ability to achieve higher gas pricing may be impacted by more favourable Zohr economics, however domestic gas pricing has the potential to increase significantly from current levels of USD2.73/mcf.

Egypt gas supply excess / (deficit)
Source: Wood Mackenzie, BMI research, BP Statistical Review of the World, EIA, OGInsights

Egypt gas pricing for producers
Source: Wood Mackenzie

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Repsol and Statoil announce asset swap

Alfa Sentral platform in the North Sea

On 11th December, Statoil and Repsol announced that they had entered into number of asset swaps as part of a packaged deal:

• In the North Sea, Statoil farms down a 15% WI in Gudrun (Norway), whilst retaining operatorship and will acquire a 31% WI in Alfa Sentral (UK portion), a field which spans the UK-Norway border
• In the US, Statoil acquires a 13% WI in the Eagle Ford JV and becomes operator, taking its interest to 63%; Repsol’s interest reduces to 37%
• In the Brazil Campos Basin, Repsol-Sinopec will transfer operatorship of the BM-C-33 licence to Statoil

Summary of asset swaps

From Statoil's perspective, sole-operatorship on the Eagle Ford JV will allow the company to have more control of the project going forward and improve efficiency of the operations. The JV was previously jointly operated with Repsol operating one-half of the acreage and Statoil operating the other half, leading to sub-optimal development. In the North Sea, Statoil will remain the largest partner in Gudrun and will consolidate its position in Alfa Sentral. Statoil increased its interest in the Norwegian part of Alfa Sentral to 62% in October 2015 (from First Oil) and the 60mmboe gas condensate field is a priority project for Statoil and will be developed as a tie-back to the Sleipner Area. The assumption of operatorship in Brazil will further Statoil’s strategy of growing in the country and enable the company to build on its deepwater experience.

Alfa Sentral tie-back to Sleipner

For Repsol, the key swap is the reduced interest in the Eagleford, alongside acquiring a producing asset in the form of Gudrun. The transaction will support Repsol’s financial position and stretched balance sheet with cash flows expected to improve by €500m in the period 2015-17. Furthermore, the transfer of operatorship in Brazil is consistent with Repsol’s focus on three themes (onshore, shallow offshore and unconventionals) as outlined in its 2016-2020 strategic plan.

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Bienvenido Victor Hugo

Amerisur's pipeline into the Victor Hugo field

On 1 December, Amerisur provided an operational update on its interconnector pipeline from Platanillo to the Ecuadorian export pipeline. Once operational, oil export will benefit from the low cost, under-utilised Ecuadorian infrastructure bringing transportation costs to below USD5/bbl. In addition to improved netbacks, the excess export capacity will support increasing production levels at Platanillo.

The pipeline is expected to be operational at the beginning of 2016 compared to the original expectations of end 2015 due to an outstanding environmental approval, which has been delayed by personnel changes at the Ecuadorian Environment Ministry. The permit is expected to be issued imminently and will allow the drilling of the 1.4km under-river crossing from Platanillo to the Ecuadorian river bank and construction of the 3.8km pipeline from the river bank to the connection point (under construction) at the southern point of the Victor Hugo field.

Pipe laying operations have commenced from the facilities on the Victor Hugo field to the new connection point – this 14km stretch of pipeline should be fully welded and trenched by year end. At the Victor Hugo field itself, civil works to prepare for the receipt and handling of Platanillo crude are c.80% complete with tankage, piping and instrumentation largely in place.

The pipeline should be ready for operational testing and commissioning around year end with initial transportation of oil through January. Aside from the environmental approvals, certification of the LACT units (fiscal measuring points) on the Colombian and Ecuadorian sides will take around two weeks once the pipeline is operational.

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Fortnum & Mason: the true cost of Christmas

Spending became complacent when oil prices were high and now with oil prices in a lower for longer environment, oil companies are tightening the purse strings. All costs are scrutinised, projects are being sent back to the drawing board to be re-engineered and no dollar of spend is approved unless it is absolutely necessary. In the spirit of Christmas, the team at OGInsights thought we would do a little cost scrutiny of our own following stories about the cost inflation of Christmas hampers.

Fortnum & Mason's Imperial Hamper costs £5,000

We had a look at the Fortnum & Mason’s Imperial Hamper which can be purchased for the small sum of £5,000. How much would it cost if all the items were bought separately? We looked at the maths and the answer is £3,036.55 (excluding the tea caddy which isn’t available to buy standalone). This implies one of two things, both of which are extraordinary and outrageous! Either Fortnum & Mason’s are charging a mark-up of £1,963.45 on top of the profit of the individual items, simply for the service of putting everything into a hamper for you or the basket, packaging and tea caddy are worth £1,963.45! Full workings below - all credit to our guest contributor Alistair F.

What about all the trouble of going around the store picking up all the items you say? Well, you can either order online, or if you are spending £3,036.55, we are sure the personal shoppers will be more than happy to help out in store.

Actual cost of the Fortnum & Mason's Imperial Hamper

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ExxonMobil - finding a needle in a haystack

We met with ExxonMobil in the first week of December to catch up on what they have been up in 2015 on the M&A front. The low oil price has certainly prompted an internal flurry of screening for targets and the teams have been looking at “a lot of opportunities” with billions of dollars ready to be spent on acquisitions. Despite a desire to do something, finding the right opportunity is still like “finding a needle in a haystack”.

ExxonMobil’s corporate development team is split into two divisions – Upstream Ventures which look at deals up to USD20 billion and Corporate Strategic Planning which look at deals above USD20 billion. Acquisitions broadly fall into three categories which are generally independent of size:

• Bolt-ons – these are generally small acquisitions to supplement an existing position although larger acquisitions will be considered on a case-by-case basis 
• Expansions – these are to materially grow an existing position into a wider position; size is opportunity specific and considered on a case-by-case basis
• New entry – these are always sizeable acquisitions as they must have sufficient critical mass in order to establish a new position

Outside of North America, Africa and the Middle East are regions of keen interest and we discussed two themes around current market developments.

The Africa Oil farm-out to Maersk was viewed as interesting and ExxonMobil remarked that more innovative structures, such as the one adopted by Maersk, was likely needed to get deals which weren’t clear winners over the line in the current oil price environment. East Africa is an area which ExxonMobil’s technical team have evaluated before and they remain cautious on the prospectivity (noting that no-one outside of Tullow/Africa Oil has been successful in the region) and timing to first oil (given the export pipeline infrastructure is yet to be built).

On Kurdistan, ExxonMobil are comfortable with the region geologically but see very few opportunities of sufficient size to justify building up a full-scale presence. This likely limits the opportunities to a handful such as Genel and Gulf Keystone. Payments for exports by the Kurdistan Regional Government remain a key issue and ExxonMobil noted that any slippage of payments could severely depress project economics as well as delaying any development spending. The Kurdistan Regional Government have implemented payment schedule on multiple occasions in the past which subsequently collapsed and it yet remains to be seen whether the current payment plan, implemented in September 2015, can be sustained.

ExxonMobil will continue to scour the international E&P landscape for opportunities and believe that current environment is a good time to act, but finding the perfect opportunity remains a challenge.

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CNOOCNexen on the prowl

Last week, we met with the CNOOCNexen corporate team to discuss their thinking in the current low oil price environment and the possibility of using the opportunity to make acquisitions.

At the beginning of 2015, CNOOCNexen expected oil prices to settle at c.USD60/bbl and the second drop in June came as a surprise. Similar to the view held by many oil companies, the oil price is now lower for longer than originally anticipated. CNOOCNexen anticipates oil prices in 2016 to be similar to 2015 levels.

The company’s UK portfolio, which mainly comprise of its 43.21% interest in Buzzard and 36.54% interest in Golden Eagle, is in a relatively good place with operating costs of below USD20/bbl. While the UK operations are not making a fortune at current oil prices, it is keeping its head above water which is more than what can be said for many North Sea fields.

M&A remains on the radar with Beijing head office looking for opportunities in the UK, Brazil, West Africa and Southeast Asia. In fact, the UK North Sea has been cited as one of the top desired areas for further investment and growth. Corporate and farm-in opportunities at all stages of the lifecycle from exploration through to production are of interest. CNOOCNexen did not disclose their oil price assumptions for evaluating acquisitions, but noted that they are beginning to see convergence between buyers and sellers in the market. In terms of acquisition size, USD5 billion would be the top end of what could be do-able. However, CNOOCNexen are still waiting for some stability in oil prices and cost indices before they can feel comfortable with valuations internally and start to make moves.

In the UK North Sea, acquisitions would be to “keep the engine running” rather than building a new business. CNOOCNexen are looking for assets where there is scope for upside and their team could add value; in this regard, assets which have demonstrated reserves creep are of interest such as Apache’s Beryl field and Shell’s Pierce field. Upcoming disposals from the majors, whether piecemeal or as a portfolio, are opportunities coming to market that CNOOCNexen are keeping a close eye on. Development assets are not ruled out given the current North Sea portfolio is in a tax paying position and development expenditure could be used to offset against profits. CNOOCNexen are now beginning to explore heavy oil opportunities as the size of the resource and progress in developing technology to exploit heavy oil (such as by the likes of Statoil) means it can no longer be ignored as a strategy. 

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Premier Oil exits Norway

Premier Oil Norwegian operation
Source: Premier Oil

On 16 November 2015, Premier Oil announced that it had agreed to sell its Norwegian business to Det Norske for USD120 million. The Norwegian business consists of the Premier Oil Norges subsidiary and includes the Vette development, adjacent Mackerel and Herring discoveries, a non-operated stake in Froy and seven exploration licences.

The transaction is expected to close before year end and proceeds will be used pay down debt. The exit of the business will give rise to a G&A saving of c.USD20 million p.a. as well as remove capital requirements for the Vette development that was progressing towards sanction.

For Premier Oil, the sale is in line with the company’s ongoing portfolio management strategy and is an important step to managing the high debt levels.

For Det Norske, the acquired business will bolster its Norwegian portfolio and Det Norske will be able to offset its production against the tax losses in Premier Oil Norges (from spend on Vette and Froy) which stood at USD146 million as at mid-2015. Det Norske will fund the acquisition from internal cash resources.

Tony Durrant, CEO of Premier Oil commented:

“We are pleased to have reached agreement to sell our Norwegian business to Det norske, one of our long term partners in Norway. Our team in Norway has done an excellent job in bringing the Vette project close to a sanction decision in a low oil price environment. The transaction will realise immediate value from the project as part of our strategy of active management of our portfolio.”

Karl Johnny Hersvik, CEO of Det Norske commented:

“Following the recent closing of the Svenska transaction, the acquisition of Premier is another bolt-on acquisition that further underlines our firm belief in and commitment to the Norwegian Continental Shelf.”

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Petroamerica’s call for cash

A sign of the times, another independent raises funding as the low oil price environment continues to hit small producers hard. On 27th October 2015, Petroamerica became the next in line to ask for cash, raising USD20 million in debentures. The expensive cost of the debt at 13.5% reflects the high risk which investors are attributing to the sector, and also that of Petroamerica. The USD20 million will consist of two USD10 million tranches, with the first expected to close on or around 16 November 2015, and the second six months later.

This fund raise comes shortly after the acquisition of PetroNova and raises the question of whether Petroamerica acquired more than it could take on. A review of the PetroNova asset base suggests that the acquisition appears sensible – the CPO-7 and CPO-13 blocks provide existing production with commitment wells not required to be drilled until July 2016 and July 2017 respectively, the Tinigua block has attractive fiscal terms (0% X-factor) although a commitment well is also required by July 2016 and Petroamerica’s Put-2 position is consolidated to 100%.

Petroamerica - PetroNova combined portfolio
Source: Petroamerica

In hindsight, it can be seen that Petroamerica’s woes stem from pre-PetroNova. At the end of 2014, the company had seven exploration wells and seismic commitments and balance sheet cash of USD73 million, out of which the redemption of a c.USD40 million debenture would be required (essentially leaving the company with c.USD33 million to fund its activities). The exploration portfolio is clearly one for a USD100/bbl oil price environment where production cash flows would have funded drilling. However, at current low oil prices, Petroamerica has been loss making – balance sheet cash as at the end of June 2015 was USD23 million; netbacks fell to USD9.1/bbl for the six months ended 30 June 2015 compared with USD54.2/bbl for the same period last year. The company has spent minimal capex in 2015 to date, conserving precious cash and only spending what it needs to maintain or manage production at its producing assets (Los Ocarros and Sur Oriente).

Some of the exploration commitment deadlines have now passed without being met (no drilling has been reported to date), yet no licences appear to have been relinquished. It is expected that Petroamerica are negotiating hard with the ANH to extend these deadlines; most likely, other cash-strapped Colombian E&Ps are doing the same. Petroamerica should be able to keep the lights on for now with the new USD20 million funding going towards satisfying the commitments. However, unless Petroamerica makes a significant discovery which it can bring onstream quickly, it will be stuck between a rock and a hard place as it continues to battle a declining production base, dwindling cash flows and a shrinking cash balance. It would not be a surprise if the company brings in partners to help with some of its commitments or raises more financing. In the meantime, Petroamerica’s case is not unique and there remains a long line of E&Ps that need more cash.

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Petroceltic: A review of Worldview's concerns

Brian O'Cathain, CEO of Petroceltic

Over the last year, Worldview has been very public about its dissatisfaction with Petroceltic's performance and has openly criticised the board of the company. Earlier this year, it tried to remove Brian O'Cathain as CEO and replace the board with two of its own directors.

Worldview believe the assets are not being managed properly and that the Ain Tsila development in Algeria could be brought onstream at a third of the cost and much more quickly. In this post, we review the key arguments that Worldview have come out with and provide our view on each of these.

Production decline in Egypt
Worldview notes that 2015 production guidance for Egypt of 16.5 - 18.5mboepd represents a 18-27% drop vs. 2014 levels and views such significant drop to be caused by poor management of the wells. Worldview believe they could boost production by a third within months.

We say: The Egyptian assets are mature and production has been steadily declining for the past four years at a rate of c.16% p.a. from 38mboepd in 2010 to 19mboepd in 2014. Unfortunately since the production guidance given in January 2015, reservoir issues have led to a further decline in production and guidance was revised down at the July AGM to 12-13mboepd. The infill programme is now on hold to allow detailed reservoir studies to be carried out. We also agree with Petroceltic's position that attempts to significant boost production as per Worldview risks damaging the reservoir and wells.

Capex being spent in the wrong places
Worldview say that development capex of USD59mm in 2015 on the Egyptian and Bulgarian assets "do not make sense" given the assets are mature and in decline.

In Egypt, Petroceletic notes that the capex is to be used for production optimisation, whilst in Bulgaria, this is required for a tie-back well given the compartmentalisation of the reservoir leading to lack of communication between pools.

We say: Given the halt of the infill drilling programme, capex in Egypt may come in below guidance at the end of the year. Nevertheless, given declining production, the spend is necessary to maintain production levels and to halt decline through infill drilling and optimisation. Similarly for Bulgaria, this capex appears to be rather essential as opposed to nice to spend.

Unnecessary exploration spend
USD35mm has been budgeted for exploration in 2015 with the bulk going towards Egypt. The company aims to rejuvenate its Egyptian portfolio through the drill-bit and had acquired four new licences between 2013-15. Worldview notes that a better strategy might be to acquire low-risk acreage with proven and undeveloped reserves.

The exploration licences cover onshore (South Idku), deepwater (North Thekah and North Port Fouad) and Gulf of Suez (El Qa'a Plain) acreage.

• South Idku is viewed as low risk with geological similarities to Petroceltic's existing acreage with 400-1,900bcf of prospective resources
• The offshore licences are believed to be an extension of the proven Levantine play where >40tcf has been discovered although water depths reach up to 4km 
• The Gulf of Suez block is in an oil-prone area

We say: We agree with Petroceltic's view that this is an opportune timing for operations in Egypt given the country's short gas position. There are three commitment wells over the next three years with two on South Idku and one on El Qa'a Plain. The company is in active discussions with farm-in partners for carry. We note that these licences were signed historically prior to the collapse in oil prices and that spending commitments are now unavoidable. While the onshore licences are generally viewed as lower geological risk, the deepwater licences are a large gamble although there are no well commitments on them.

High opex

Worldview notes the high opex structure and makes comparisons around employees/well.

• Petroceltic: 16 employees/well
• Apache: 9.5 employees/well
• TransGlobe: 6.7 employees/well

We say: Employee/well is not a standard metric. In addition, Worldview are assuming Petroceltic headcount of 365 vs. disclosed headcount of 171 as at the end of December 2014. We note that Petroceltic has a substantial number of staff dedicated to the Ain Tsila development and should not be directly compared with TransGlobe. Apache is a top-tier player in Egypt with its substantial success since entering the country in the 1990s. In June 2015, the company noted that a staff reduction programme had been implemented with 27 reduction in headcount to 144.

Timing and high cost of Ain Tsila

Worldview believe that the development cost of USD1.5bn (gross) is unjustified.

"In our view, the current approach to Algeria is outdated with its unreasonably large budgets and long schedules, aimed to deliver a "gold-plated" custom-designed plant where one is unlikely to be required."

Worldview believe that the project could be completed at USD500mm using off-the-shelf modular gas plants which can be constructed with much shorter lead times.

We say: Significant FEED work has been completed on Ain Tsila with a wide range of options and concepts studied. "Off-the-shelf" gas plants as used in the US are unlikely to be fully compliant with Sonatrach's stringent specifications for gas and target of >95% uptime. Furthermore, the field is 1,700km from the coast with limited infrastructure and the plant has to be designed with minimal risk of breakdown/need for repairs, especially when operating in an environment of c.50 degrees Celsius in the summer. There is additional cost in transporting and constructing a plant in such a remote location and extra costs need to be factored in for security arrangements. We view Worldview's proposal as unrealistic with a lack of understanding of the timescales required when working with National Oil Companies.

Concerns on the bond issuance

Worldview has said that it will take all steps available to stop the bond issue arguing that Petroceltic’s proposed pledging of “the company’s crown jewel”, its interest in the Ain Tsila asset, “will result in squandering shareholder value”. 

Petroceltic notes that the bond has been contemplated for a long time and shareholders have been made aware of the plan for months.

We say: Petroceltic clearly needs the financing unless, as Worldview believe, that production in Egypt can be restored, costs can be cut further and Ain Tsila brought onstream more quickly and cheaply than currently planned. Concerns around pledging Ain Tsila are unjustified since it would need to be security against any future debt that is raised, regardless of whether it is bank or bond debt. In fact, Ain Tsila is already part of the security package for the USD500mm facility that the company put in place in April 2013.

Borrowing powers

Worldview wishes to limit the borrowing powers delegated to the board under its Articles and has proposed that no new debt be raised which contain any of the following provisions:

• Interest rate above Libor + 8%
• Granting of security over the company's assets or subsidiaries
• giving rights over equity securities
• including any structured elements such as contingent coupon

Petroceltic has reviewed guidance from the Investment Association which recommends that companies should limit borrowings that can be incurred without shareholder approval. In this regard, Petroceltic has proposed a resolution to amend the articles that limit the company's borrowings to USD650mm with shareholder approval required for debt in excess of this amount.

We say: The inability to pledge assets is unrealistic and would essentially mean no further debt could be raised. Petroceltic's resolution to limit borrowings to USD650mm is unlikely to appease Worldview and is seen as a token gesture.

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Why Kenyan crude will be exported and not domestically refined

Mombasa refinery
Source: http://mygov.go.ke/national-treasury-sets-aside-funds-to-buy-essar-stake-in-refinery/

Kenya currently has no crude oil production and relies solely on imports to feed the domestic refinery in Mombasa. Aside from feedstock for the refinery, there is no other demand for crude oil in Kenya.

In 2012, domestic consumption of refined products was 73mbbl/d – this was satisfied by 20mbbl/d of domestic production from the refinery and 53mbbl/d of imports. The shortfall in domestic production has been met by imports for many years and this has steadily grown from 22mbbl/d in 2005 along with the increasing demand for refined products. The shortfall suggests that there is scope to increase throughput of the refinery and reduce the level of imports.

Kenya Refined Products Production and Consumption
Source: Kenya National Bureau of Statistics, Kenya Petroleum Refineries Limited, OGInsights

The refinery has a design capacity of 80mbbl/d, but has continually operated at c.40% of capacity. This low utilisation is due to a number of reasons including regular utility supply outages, limitation on size of cargoes it can accommodate, low profitability (some batches of processing are loss making), limitation on product slate and general inefficiency of the refinery. The refinery has a reformer and a catalytic hydro-treater, but no upgrading units; the refinery’s two complexes were commissioned in 1963 and 1974 with minimal investment since. The profitability of the refinery was further hit in 2013 when the incoming government removed the price protection previously provided to the refinery, making it uncompetitive relative to refined product imports.

The refinery’s current configuration is designed to handle heavy crude grades from the Middle East. In 2012, a refinery upgrade project was considered by the then owners (50% Essar Energy, 50% Government of Kenya). The plans included changing the configuration to handle lighter crudes and would incorporate the ability to process Lokichar crude. However, the $1.5bn cost of the upgrade was deemed to be too expensive and uneconomic; as a result the upgrade was abandoned, following which, Essar Energy decided to exit the joint venture. In December 2014, Essar Energy sold its 50% interest in the refinery to the Government of Kenya.

The refinery has been mothballed since mid-2013 and now acts as a storage facility for imported refined products. All demand for refined products are now met by imports. There are currently no plans to restart the refinery, and without further investment, it is unlikely the refinery would be able to operate profitably. Until there is a plan and willing financing to upgrade the refinery, the destination for Lokichar crude is most likely to be the export market - in its current state, the refinery configuration is not designed to process Lokichar crude.

In a scenario where the refinery was upgraded and being wholly fed by Lokichar crude, then feedstock requirements could reach c.100mbbl/d by 2020 in order to fully meet forecast domestic demand for refined products (96mbbl/d estimate by Kenya Petroleum Refineries Limited). However, this scenario is deemed to be highly unlikely in the foreseeable future.

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Colombia calling: Petroamerica acquires PetroNova

Cartagena, Colombia
Source: http://www.backtrackers.nl/colombia/

The Colombian E&P landscape is characterised by a few IOCs with 100mmbbl+ of reserves (e.g. Repsol, Chevron, Occidental) and a large number of independent E&Ps. The smaller end of the scale is dominated by many small players with more than 25 companies with less than 2.5mmboe of reserves.

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The Apache Egypt treasure map

Source: Houston Geological Society, HGS

Apache is a significant acreage holder onshore Egypt with an extensive infrastructure network which allows new discoveries to be brought onstream quickly and at relatively low cost. Its acreage can be broadly split into four areas, the most significant of these is the Western Desert Gas area which underpins the portfolio’s gas reserves and is a key supplier of gas to the domestic market.

Source: OGInsights

 The highlights from each area are below.

Western Desert Gas

This area has been a key source of growth in recent years and accounts for 80% of Apache’s Egyptian 2P reserves (Wood Mackenzie). The area comprises three sub-areas with the Khalda Area, which has been producing since the 1970s, being the most established. The Fahgur, Sushan and Matruh Areas all commenced production post 2005 and have all been a target area for exploration. Production in the Western Desert is currently constrained by lack of gas processing capacity (currently 900mmcf/d) and further investment to debottleneck the facilities is dependent on increase in gas prices.

Apache Merged Area

The blocks in this area were acquired from BP in 2010 with production underpinned by two fields: Abu Gharadig and Razzak. Both of these fields are mature and in terminal decline, although horizontal drilling and water flooding efforts have been successful in arresting declines. The area is considered as underexplored and exploration success will be important to maintain production levels in the longer term. A seismic programme in 2010/11 and subsequent simulation studies has helped Apache identify new targets for future exploration and development.

East Bahariya Area

Apache aggressively explored the East Bahariya block between 2000-2005 bringing on-stream a number of discoveries. Since 2005, Apache has implemented water flooding on all the fields in the block which has boosted production. In 2008, the Heba Ridge cluster of fields were discovered which is now a key growth area on the block. Apache acquired the nearby El Diyur and North El Diyur blocks after recognising the

extension of one of the East Bahariya reservoirs into these blocks.

Qarun

The fields on the Qarun block are mature and in decline with production expected to cease in the next few years. The East Beni Suef block is also in decline, although Apache has been able to sustain production through water flooding. Exploration success on East Beni Suef has also helped to maintain production, although discoveries have been small in size (1-5mmbbl).

Apache exports its production via an extensive network of oil and gas pipelines and facilities. A schematic of the network is shown below.

Source: OGInsights

Source: Apache Egypt EIA
https://www.miga.org/documents/Apache_Egypt_2004_Egyptian_Oil_and_Gas_Activities_EIA.pdf

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Apache exits LNG business through sale to Woodside

Source: OGInsights

On 15 December 2014, Apache announced the sale of its interests in the Wheatstone and Kitimat LNG projects to Woodside for USD2.75bn. The move was widely anticipated with Apache announcing in its Q2 2014 results its intention to completely exit LNG; this message was reinforced in the company’s Q3 results on 7 November 2014.

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Lundin stops funding Africa Oil

Africa Oil’s history dates back to 1983, when it was founded as Canmex Minerals with funding from the Lundin family. The company was officially renamed to Africa Oil in June 2009 to reflect its strategic and geographic focus. Since 2009, the company went through a series of acquisitions to consolidate its position in Kenya and Ethiopia.

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