Tuesday, 18 October 2016

Development lead times

By Elaine Reynolds

How long does it take to develop a new discovery to first production? The answer will of course vary greatly and depend on a wide range of factors, from the size of the accumulation, to the maturity of the basin and the presence or lack of existing infrastructure. But in many cases the time taken will probably be longer than originally anticipated.

The recently published Oil & Gas UK economic report contributes some interesting statistics on this subject from a UK perspective. In the North Sea, the current average is 17 years (for those fields entering production since 2005), with all developments during this time taking more than 10 years. This is a lengthy payback time for both operators and investors.

Source:Oil & Gas UK, Wood Mackenzie

For a mature basin such as the North Sea, these numbers are somewhat misleading since discoveries are often considered uncommercial when originally drilled but can become more attractive later due to the application of new technology, access to new infrastructure or an improved economic environment. For example, the Kraken heavy oil field was originally discovered in 1995, but it wasn't until Nautical Petroleum drilled an appraisal well in 2007 that a development looked commercial. Current operator EnQuest expects first oil from Kraken in 2017, though it is worth noting that this will be five years later than the 2012 onstream date that was assumed after the success of the first appraisal well. 

The record for a UKCS oil development is the 85 days achieved by TAQA in tying back its 2012 Cormorant East discovery to the North Cormorant platform. This is an impressive achievement, but ultimately only possible because TAQA was operator of both the discovery and the host facility. EnQuest's Scolty/Crathes were discovered in 2007 and 2011 respectively and are due onstream by the end of 2016.  The field will be tied back to the Kittiwake platform, facilitated by EnQuest acquiring 50% and becoming operator of the Greater Kittiwake Area in 2014. Without this level of control, tie back developments tend to take longer. Serica Energy discovered the gas condensate Columbus field in 2006, but has been unable to agree commercial terms with the operator of the Lomond Platform less than 8km away.

Even those accumulations that look attractive straight away  as stand alone developments can take many years to come onstream. Chevron's 240mmboe Rosebank, one of the largest undeveloped fields in the region, was expected to be onstream within 7 years of its discovery in 2004, but it has yet to be sanctioned, partly because the project sits in the under developed West of Shetland region and requires a new gas pipeline. 

Successful stand alone projects tend to take at least six or seven years from discovery to first oil, with Buzzard, Golden Eagle, Foinaven and Huntington all in this timeframe and to be joined by EnQuest's Catcher if it comes onstream as planned in 2017. More technically challenging fields are likely to take longer. Maersk's HPHT gas condensate Culzean field is due onstream in 2019, eleven years after discovery. The Mariner heavy oil field is also due onstream eleven years after current operator Statoil took over the asset in 2007 (although the field was discovered in 1981).

In less mature Norway the average lead time for an individual discovery is still 11 years and up to 15 years is not uncommon.

Source: Norwegian Petroleum Directorate

 Offshore West Africa, the development timelines are shorter with the majority taking between 7 to 10 years, but can range from 3 to 16 years. 

When a discovery is made, the temptation is to believe that this is the project that will be developed within the most optimistic historical timeframe. It would be more prudent to assume that it will not.

Rockhopper Exploration - A large part of a large pie

By Will Forbes

Rockhopper (RKH) holds a material stake in the major discoveries in the Falklands. The Sea Lion complex holds 517mmboe of 2C contingent resource (900mmboe 3C), while the Isobel Elaine complex could be a similar magnitude (according to management estimates). This resource base (over which RKH holds a >50% working interest) is significant on a global scale and commercially attractive given the cost reductions achieved through the FEED process so far – the project is NPV10 break-even at $45/bbl. Although the timing of project sanction is uncertain (particularly given the financial constraints of its partner PMO), the fiscal regime and resource base makes this a compelling long-term project. Our revised core NAV is 74p/share.

Giant undeveloped resource base in the Falklands
The Sea Lion complex is an important discovery and one of the largest undeveloped fields globally. A combination of political constraints, low oil price and financing issues has meant a slower development timeline than hoped, but this does not diminish the resource in a well appraised, well understood reservoir. With an extension of the licence to 2020, PMO/RKH have time to find the best development arrangement with potential partners and a recent thawing in the political climate gives us hope that a wider range of partners may be interested. Funding an initial development of c 220mmbbl (with pre-first oil capex of $1.5bn gross) opens up fully funded exploitation of the resource and significant value.

Production cash flows give a solid footing
Evolution in the production base over the last year (Civita start-up, successful Guendalina side track and Egyptian acquisition) has given a solid cash flow foundation that should largely cover G&A while giving potential exploration upside (from wells at Abu Sennan and El Qa’a Plain) in 2017. RKH is therefore well-funded to see it through to the development stage of Sea Lion Phase 1. 

Valuation: Core NAV of 74p/share
We have revised our core NAV to reflect our uncertainty on project timing (we now assume first oil in early 2022) and commercial terms, as well as moving to a 2017 valuation date and increased discount rate. With our assumed long-term oil price of $70/bbl, the development of Sea Lion will create significant free cash flows and value. A material move toward sanctioning the project (perhaps by the introduction of a new partner or financing structure) has the potential to increase this markedly, while firming up of Isobel Elaine complex volumes could add materially in time.

Investment Summary
Company description: A large part of a large pie
Rockhopper is a London-listed E&P and a major holder in the significant discoveries in the Falkland Islands. The Isobel Elaine complex discovery has the potential to match the 517mmboe 2C resources currently ascribed at the Sea Lion complex, although further appraisal drilling will be required to confirm this. If proven up, it would leave Rockhopper with a >50% working interest in around 1bnbbls of resources with attractive fiscal terms.

FEED for Phase 1 of Sea Lion (of c 220mmbbl) is well advanced, with major contractors able to generate material cost savings in the current oil price environment – capex to first oil is currently expected to be $1.5bn (vs $1.8bn previously), while we model a life-of-field opex rate of $25/bbl (vs $30-35 previously). Phases 2 (Southern part of Sea Lion and additional Sea Lion complex reservoirs) and 3 (the Isobel Elaine complex) will more fully exploit the resource base.

Given the $45/bbl NPV10 break-even and attractive tax and royalty terms, the project should benefit from a firming of oil prices that many expect in the long term. Certainly, the phase one project returns are attractive (IRR of c 25% in 2017 at the forward curve, and 40% with our long-term assumptions of $70/bbl real).

However, there is a risk of slippage to the project. Although the project is NPV10 break-even at $45/bbl, industry should require a notably higher return than 10% to give the go-ahead, and we expect that a strengthening of the oil price (or lower costs) will be required for project sanction – something that the forward curve implies is not likely in the near term. Premier’s financial position has been under scrutiny in recent months and it is currently unable to finance the >$1.2bn (net) required to first oil, so a project sanction pre-2018 may be dependent on a third party entry to the project. On top of this, the carry arrangement with Premier (PMO) means its economics of NPV10 break-even are slightly higher than RKH’s at $48/bbl (according to our modelling).

Balancing these factors is the enormous NPV to which a full exploitation of the resource would lead for those involved in the project. Although an earlier production start-up is very possible if FID is reached quickly, we model first production in 2022 to factor in a delay. Even modelling this relatively late start-up, the unrisked project value for Phases 1 and 2 (combined) is above $4bn (@ 10% discount rate) or $2bn (@ 15% rate), and Phase 1 cash flows should largely fund the capital investment in further phases. Gross peak volumes considerably above 100mb/d should be possible even without a development of Isobel Elaine complex (and ignoring the potential 3C upside in Sea Lion). As a result, we believe management of both Premier and Rockhopper are open to approaches to get the project sanctioned.
Elsewhere, the acquisition of the Egyptian assets from Beach Energy should provide steady, low-risk cash flows that, when combined with cash flows from Italian gas production should broadly offset G&A expenses. Furthermore, the portfolio contains a number of exploration targets that could add longer-term value (incremental exploration targets at Abu Sennan, a committed exploration well at El Qa’a Plain in late 2017, and Monte Grosso in Italy could be drilled under ENI’s operatorship).

Valuation: Core NAV adjusted to 74p/share
The Falklands remain the core of the value for investors in Rockhopper. Although the timing and commercial arrangements that will eventually see Sea Lion’s first production are unclear, the exploitation of a 500mmbbl discovery with good fiscal terms means development is surely inevitable in time. However, the current low oil prices and investment appetite in the industry mean we assume a delayed FID (vs previous thoughts) and first oil in early 2022, while uncertainty on commercial terms under which development will occur means we have lowered our risking. These changes, together with consolidation of the Beach Energy assets and a move to a 2017 discount year, lead to a revised core NAV of 74p/share (from 93p/share), using a 12.5% discount rate. This would fall to 56p/share at a 15% discount rate (and 34p at a 20% rate). 

Financials: $75m of cash in September 2016
Cash flows from Italian gas production and Egyptian oil production should be enough to largely offset administration expenses, enabling management to focus on its use of the remaining c $60m cash that we expect it to have by end 2016. Availability of capital to develop Sea Lion is key among the considerations, although minor expenses in exploration in Egypt, and possibly in Italy, will need to be catered for.
The existing development carry with Premier implies that RKH will need to find more than $250m to get to first oil in Phase 1 assuming current cost assumptions. While our base case is that this will come from the loan arrangement with PMO as a backstop, other (cheaper) sources should be available (the bond market and later a reserve-based lending facility as production nears) – though given our current assumption of first oil in early 2022, there is plenty of time to arrange alternative sources if required.

The overriding factor in the valuation of Rockhopper is the timing of the development of Sea Lion. Although the project break-even (NPV10) is $45/bbl, project sanction is more dependent on PMO’s higher NPV10 break-even (which we calculate as $48/bbl) and its financial position, which may not improve towards an acceptable level (net debt/EBITDA of <3x) until 2018. The resulting time to first oil (of five to six years) reduces unrisked value materially and makes it more sensitive to increasing discount rates. A 2.5% decrease in the discount rate (from our assumed 12.5%) increases Phase 1 NPV by c 25% – we would expect the effective cost of capital to decrease as the risk of the project reduces as production nears and ramps up.
The uncertainty on project sanction also leads to uncertainty on the exact commercial terms at which Rockhopper will participate in the project. Given the size of the prize, it makes sense for the company to take a view on sacrificing some working interest/value (as it did when the development carry was renegotiated and split between phases 1&2) if it means a faster project sanction and first oil. This is equally true of Premier (if not more so given its financial situation).

Once up and running, cash flows should benefit from increases in oil prices. For Phase 1, our modelling indicates that a $5/bbl increase in Brent oil price would see NPV12.5 rise by c 15% (although we would estimate that accompanying cost inflation in this scenario would dampen this).

For the full note, click here

Wednesday, 5 October 2016

Skipper oil - heavier and more viscous than expected

by Elaine Reynolds

Independent Oil & Gas(IOG) drilled its Skipper appraisal well in August this year, but despite initial indications that the heavy oil was moveable in the reservoir, the company has now announced that sample analysis points to a significantly higher viscosity than expected, forcing a rethink on potential development options.

Skipper sits in a heavy oil prone region to the south of heavy oil fields Bressay, Mariner, Kraken and Bentley and is estimated to contain 2C resources of 26.2 mmstb. 

Source: Schlumberger

The key uncertainty prior to drilling the appraisal well was the viscosity of the oil, so the primary objective was to recover good quality reservoir samples from the well. Viscosity is seen to be a more useful indicator of flow properties for heavy oil fields, and a higher viscosity than expected would require different processing considerations and a higher well density. The discovery well, 9/21-2, was drilled in 1990 but failed to flow on test. Samples recovered from the well indicated the oil was 14 - 16 deg API, but uncertainty remained regarding the viscosity of the oil, since the samples were dead oil and there was no representative pressurised sample from the well. These samples indicated a dead oil viscosity of 750cP, which was considered to be pessimistic and taken as the low case for the well. In the 2013 CPR the oil viscosity at saturation pressure at reservoir conditions was then calculated, using a range of correlations, to be 160cP in the mid case.

Source: Edison

A viscosity of 160cP would have put Skipper alongside Captain, the only heavy oil field producing in the North Sea to date and Kraken, due onstream in H1 2017. First sample results indicate that the oil is heavier than expected at 11 deg API and that the viscosity is significantly higher, though no actual figure is given. Although a higher viscosity would make a development more challenging, such oil can still be developed, with Statoil going ahead with the 508cP Heimdal reservoir in Mariner and  Xcite demonstrating that commercial rates could be achieved in the 1500cP Bentley when it produced from the 9/03b-7 well at up to 3,500 bopd through an ESP. Both Bentley and Mariner are however significantly larger than the 26mmbbl Skipper. 

Tuesday, 4 October 2016

Mexico shale potential

by Elaine Reynolds

Mexico's Secretary of Energy, Pedro Joaquin Coldwell, indicated in a speech in Houston last week that the country's first auction for its northern shale fields, delayed because of low oil prices, could now take place as early as Q2 2017.

According to an EIA assessment report carried out in 2013, Mexico holds technically recoverable resources of 545TCF of shale gas and 13.1blnbbls of shale oil and condensate. The bulk of this sits in the Eagle Ford Shale of the Burgos Basin which is estimated to contain 343TCF and 6.3bnbbls. Since the reservoir in Burgos is an extension of its commercially successful equivalent in South Texas there are hopes that the US fracking successes can be repeated here. In the basins to the south and east of Burgos the shale geology becomes more complex and shale development potential is less certain.

Source: EIA/AIR

National oil company Pemex began exploring for shale oil and gas in 2011, but early wells have been expensive with reported costs of $20-25m per well, three times the cost of a Texas Eagle Ford well.  Rates have also been modest at 2 -3 mmscfd. With some wells located close to successfully producing Texan wells, it should however be possible to increase these rates through operational improvements. Mexico needs access to technology and financial resources in order to fully exploit its shales resources and hopes to achieve this through its ongoing energy sector reform, including the auction process.

Despite the geological similarities with Texas, there are further issues that will complicate shale gas extraction in Mexico. The Burgos basin sits in an arid region of Mexico, so that ensuring a supply of sufficient water to carry out fracking will be challenging. Finally, security is a major issue, with the basin sitting  in an area of organised criminal activity. This activity includes the illegal tapping of pipelines, with incidents expected to exceed 4000 this year, up from 710 in 2010. For the first round, the Mexican government have selected areas where the cartels are not as dangerous, but the stituation will need to be tackled for large scale shale development to succeed.