Ivar Aasen crib sheet

• Contains 4 fields: Ivar Aasen, West Cable, Hanz, Asha
• PDO approved in March 2013
• Development costs relatively high
• Discovery of Asha in December 2012, and inclusion of Asha in development improves economics
• Edvard Greig and Johan Sverdrup could push cost of services market higher
• Ivar Aasen expected to receive transitional terms , whereas other fields will be taxed under new terms

Participation

• Ivar Aasen Area contains 3 licences
• Ivar Aasen/West Cable (PL001B)
• Hanz (PL028B)
• Asha (PL457)
• Field unitisation expected mid-2014
• Estimated unitised participations are: Statoil (41.15%), Det Norske (28.8%)*, Bayerngas (12.34%), Wintershall (7.08%), EON (3.54%), Spike (3.54%), Verbundnetz (3.54%)
• Note that on 25 June 2014, Det Norske increased its stake in PL457 (above unitisation does not reflect this)
• EON to receive 15% WI in PL613 (Barents) and 10% WI in licence PL676S (North Sea) + Cash
• Det Norske increases interest in PL457 from 20% to 40% WI

Reserves

• WM Commercial reserves: 149mmbbl + 181bcf
• Hanz: good reservoir – expect high RF
• West Cable: strong acquisfer support – expect high RF
• Ivar Aasen and Asha reservoir more complex, varying sand quality

 Production

• Ivar Aasen, Asha and West Cable production from 2016; Hanz in 2019
• High rates of gas production expected from some wells due to gas cap in Ivar Aasen and Hanz reservoirs
• Wells will be drilled in order that gas production can be shut off to maximize oil recovery
• Asha gas initially reinjected

Development

• Ivar Aasen, Asha, West Cable: developed using fixed platform
• 20 well slots with partial processing facilities
• Production and injection wells will be drilled using jack-up positioned next to platform to 2016/17
• Hanz will be developed using subsea tie back to Ivar Aasen platform
• Exports via Edvard Grieg facilities

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Eagle Ford Shale

Intro and history

• Play in South Texas stretching into Louisiana; contributes c.10% towards US production
• Three “windows” to the play – oil, gas-condensate, dry gas; focus has been on development of the liquids section
• Eagle Ford formation not singled out until 2008 although routinely tested before then
• Initial production was gas/condensates by Petrohawk with Apache testing oil around the same time
• Big change in 2010: EOG acquired acreage in oil window, changing Eagle Ford into a liquids focused play

Well economics

• Production and reservoir quality varies greatly in Eagle Ford; EURs can range from 200mboe to > 1mmboe per well
• Drilling and completion costs: USD5.5-9.5m / well
• Early Eagle Ford wells were completed with 10-stage hydraulic fracs; now common for 15-20 stages

Infrastructure

• Ideally located to supply refineries in Corpus Christi and Houston
• Short distance to Gulf Coast refineries reduces costs and allows for more transport options (barges, pipelines, rail and trucks)
• Volume of crude, condensate and NGLs that require processing has led to the construction of several projects; trucks will continue as intermediate solution whilst projects are being completed
• Eagle Ford Crude Oil Pipeline (Enterprise Products): 350mboepd capacity with interconnections to Seaway Pipeline and the new 5mmbbl Echo Terminal in houston
• Kinder Morgan condensate pipeline: Eagle Ford to Pasadena, 300mbopepd capacity
• Koch/NuStar/Arrowhead: 200mboepd capacity
• Plains All American: Eagle Ford to Corpus Christi, 300mboepd capacity

Outlook

• Operators looking to increase resource potential through down spacing and testing additional formations

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Bakken

Intro and history

• Spans western North Dakota, eastern Montana in US and parts of Saskatchewan and Manitoba in Canada
• Named after Montana farmland owner Henry Bakken
• Recoverable estimates continue to increase as more about the play is understood
• First production in 1951, after which, formation began to be mapped
• In mid-90s, Elm Coulee field discovered with significant oil accumulation in the middle Bakken member
• In mid-2000s, EOG drilled the Nelson Farms 1-24H well; demonstrated H-wells with fracture stimulation could produce high IPs
• In 2009, Continental Resources found that the Bakken and Three Forks formations were separate reservoirs and could be produced independently

Well economics

• EURs highly dependent on location: range 200 to >1,000mboe, average 450-650mboe
• Wells average USD9.5m to drill and complete, but can vary depending on length of lateral and material usage
• 10,000ft laterals and 40 fracture stages becoming common
• Implementation of pad drilling is reducing costs

Infrastructure

• c.65% oil shipped via rail; enables access to higher Gulf Coast sales prices (Light Louisiana Sweet “LLS”)
• 2012 production: >700mbopd vs. 2007 production: c.200mbopd
• Transporting to Gulf Coast has been economically more attractive than to the oil congested WTI hub at Cushing, Oklahoma
• Explosive growth meant existing inter and intra-state pipelines quickly reached capacity
• Within play, crude transported by truck
• Outside play, rail and pipeline used
• Rail (USD15-20/bbl) is more expensive than pipeline (USD8-9/bbl), but allows access to LLS pricing

Outlook

• Cost reduction
• Expand longevity of play by testing lower Three Forks
• Down spacing
• Secondary and tertiary recovery

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The state of the UK North Sea

• Tax incentives have encouraged capex spend
• ...but this has led to an overheated OFS market
• and rising costs have caused some marginal projects to be postponed or even cancelled (Bressay (Statoil) and Rosebank (Chevron) being well known examples)
• Production decline continued in 2013...
• Increase in planned and unplanned shutdowns
• Ageing infrastructure
• ...compounded by few large field start-ups and poor exploration success
• WM estimates UKNS average discovery size in 2013 to be c.11.3mmbbl, which struggle to meet commercial thresholds in current high cost environment
• Most discoveries have been tie-back opportunities
• This concerning state of UKNS will impact OFS providers; UKNS represents c.20% of global offshore spend
• Poor exploration results in recent years will lead to lower levels of future project development
• Laggan and Tormore start-up in 2014 - accounted for significant portion of UKNS capex previously
• Current backlog will support 2014/15, but backlog growth looks challenging
• Focus of oil companies has shifted to completing existing projects
• Brownfield may be a bright spot for UKNS OFS
• Drivers: increasing recovery, maintaining ever ageing infrastructure, expansion of platforms to accommodate tie-backs
• Seismic may or may not be a growth area
• Poor exploration results may lead to greater spend on seismic, but the UKNS unlikely to be seen as region with further significant potential
• With the industry in a state of strict capital discipline, cash is likely to be spent on regions where exploration is seen as more prolific
• Declining M&A reflects the downside risk perceived by buyers of the UKNS

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Thoughts around using a high discount rate

Higher discount rates may be used to reflect the greater risk averseness adopted by a company/project manager. This may also be used as a screening tool, with lower NPV projects rejected. In O&G, and other fields, higher discount rates should be used in conjunction with other tools to evaluate projects.

At the planning level, the use of higher discount rates has its own limitations due to conflicting interests between the project team (e.g. staying in the job) and management.

• Encourages projects with near term and/or higher levels of early production 
• Implication: capex spent on projects with shorter lives at expense of a developing longer life assets; capex is accelerated
• Capex is low-balled to get projects/wells approved
• Implication: actual costs are inevitably higher leading to under-performance of project; capital not deployed efficiently
• Riskier exploration may be undertaken
• Implication: more optimistic view taken on reserves and costs to push projects forward

The above actually leads to projects that are inherently more risky being undertaken and increases the exposure of the business to risk, countering the original intentional of using a higher discount rate!

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Global upstream review - 2014

Transaction activity declined sharply in 2013

• Record M&A in 2010-12, companies switched focus to developing acquired acreage
• Corporate activity weak – NOCs faced hurdles in NAM, public companies weary of overreaching with strict capital discipline and own paper cheap
• In NAM, prime acreage now leased up; valuations mixed as drilling results and understanding of plays have progressed
• Asian NOCs bidding aggressively on global assets as large corporate opportunities limited or more difficult to transact – have seen spending from this group of buyers up

M&A buyer/seller landscape evolving

• Asian NOCs remain largest buyer group
• Chinese NOCs competing with Asian NOCs who are heavily reliant on import and with mandated overseas growth targets
• Pertamina, PTTEP, CPC and Indian NOCs have focus on Africa
• KNOC has, in contrast, spend USD20bn in past 3 years with poor returns and underperformance
• High debt, looking to downsize portfolio

NAM E&Ps largest sellers of overseas assets

• Retrench to NAM, divest wider international portfolio to focus on core regions, capital discipline
• Financial investors/PE increasing O&G footprint outside of NAM

 
LNG market shifted to emerging basins

• Australia market crowded with competing projects and escalating costs
• East Africa attracting huge Asian NOC investment
• East Med gas in early stages, welcoming experienced LNG players
• Arbitrage opportunity for NAM LNG to APAC/Europe, competing with Middle Eastern basins

 
US conventionals spending falls with shift to liquid plays

• Top performing liquids rich plays have grown market share (Eagle Ford, Bakken); Gas plays (Marcellus) have lost market share
•  PE seeks bargains in nat gas; more efficient tax structures; can wait for gas price to recover

Key themes for 2014

• Majors continue to rationalise portfolios amid shareholder pressure for better returns and weak growth/high capex
• E&Ps - pressure for discipline rather than grow (inorganically); reluctance for large corporate deals unless compelling 
• NAM E&Ps expensive, trades with oil despite gas weighting
• Emergence of Asian private buyers - financial, industrial, OFS and private money looking to diversify into E&P (e.g. Brightoil)

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Repsol hit with further delays offshore Namibia: Welwitschia

• Welwitschia prospect being drilled on PEL0010: Repsol (44%*), Tower (30%), Arcardia (26%)
• Welwitschia-1 spud last month
• Due to issues with wellhead housing, well was plugged and abandoned
• Decision made to drill Welwitschia-1A 50m away, which was spud 1 May 2014
• Welwitschia-1A now at 1,879m but problems with blowout preventer system has halted drilling
• Prospect estimated to have multi-billion bbl potential and is being drilled to test the Maastrichtian and Aptian-Albian reservoir sequences

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