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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