A PDF of APA 2011 poster downloadable here: http://tinyurl.com/6voccq5

Please note that this poster has been designed to be printed in A2 but if you prefer the zoom function will allow you read the detailed information on your screen.

Contact Selina Ashdown: +44 7812 054 415, sashdown@strategicfit.co.uk, www.strategicfit.com, for further discussion.

This success has generated a rush to secure exploration opportunities in Europe over the past four years where the resource potential is large but unproved. Political and public reaction to unconventional gas exploitation has varied widely across Europe. With far less onshore O&G activity, regulation is immature and in some instances non-existent. O&G companies face the challenge of operating in widely different regulatory environments.

We have written the following presentation on the response in France. It provides insight into the recent fracking ban, the structure of relevant regulations and the process for engaging with regulators.

Click below to view presentation: StrategicFit – French unconventionals regulation

Production forecasters aim to make credible predictions (or ranges of predictions) for production volumes of oil, gas and possibly other flow-types such as water and H₂S, at specific time-steps in the future. It is an essential part of business planning. However for complex fields or regional level forecasts, production forecasting too often becomes a ‘dark art’: various approximations are introduced and debated over to represent the possible impact of specific events or poorly understood factors, e.g. facility constraints on the production forecast. Whether these approximations make for a credible forecast not only depends on the nature of the field, but also the way in which it is used in business planning.

The Basics

Let’s first consider an extremely simplified example to establish principles. In the example three wells are each predicted to be flowing at gross liquids 1,000bbl/d (at a given time-step), with water cuts as represented diagrammatically in the centre of Figure 1. Suppose each well production flows into a facility that has a gross liquids capacity of 2,000bbl/d. For our production forecast number we might choose to defer 1/3 of our rolled up forecast to meet this constraint arriving at a figures of 400bbl/d of water and 1,600bbl/day of oil (Field-Level Approach, Figure 1). However a production programmer might in reality decide to maximise production by shutting in Well C, deferring production to the following month. This will result in total constrained production of 250bbl/d of water and 1,750bbl/d of oil (Well-Level Approach Figure 1).

Scaling Up

How does this affect the forecast over time? In order to see this let’s scale up the example to 100 wells; each having a constant gross liquids flow of 1000bbl/d and an exponential oil decline (with specified oil rates and decline fractions*). The facility constraint on this field is such that only 95,000bbl/d of gross liquids may flow. Figure 2 shows the difference in the forecast oil production rate between the Field- and Well-Level Approach, for 5 years in monthly time steps.

The difference in cumulative production between the Well-Level and the Field-Level Approach for the first 12 months is about 4%, but the large volumes involved mean this equates to nearly 600,000bbl of oil underestimated by the Field-Level Approach for that period, relative to the Well-Level Approach. Over the five years of production shown here, the underestimation in cumulative production is over 1.1MMbbl.

The Reality

What do these principles tell us about a real field? Clearly the more homogeneous production is across a field the better the approximation in the Field-Level Approach becomes. This will also obviously be the case if the constraints in the field cause only a tiny percentage of production to be deferred. The Well-Level Approach, on the other hand, reflects actual production based on the operational reality in all circumstances.

Does this mean that the Well-Level Approach should always be used? Consider a greenfield development: the effect of facility constraints will likely be small, wells will likely produce close to dry oil, and the ranges of uncertainties will be large. The latter is likely to ‘wash out’ the impact of the systematic error in the Field-Level Approach in any analysis of the field level forecast. In such circumstances then, we may consider the Field-Level Approach not only credible, but preferable, requiring less time to implement transparently and allowing more time to focus on the decisions that matter.

Conversely, a mature field will likely have a complex system of facility constraints built up over the lifetime of the field, combined with highly inhomogeneous production as new wells and work-overs are mixed in with existing production. Decisions are ‘high stakes’ – the window of opportunity is narrowing, but the allocation of resources can be difficult in the face of apparently conflicting activities (e.g. a development opportunity vs. a well integrity improvement project). In such circumstances, the Well-Level Approach is vital: not only is credibility implicit, the outcome of a given scenario can be analysed legitimately down to the well level, allowing for a rich exploration of strategic alternatives.

Contact Ian Sollom: +44 7722 065 475, isollom@strategicfit.co.uk, www.strategicfit.co.uk for further discussion.

*In the example field of 100 wells, the initial oil rate and decline fractions is 900 bbl/d and 0.025 per month for the first 20 wells, 500 bbl/d and 0.015 per month for the next 60 wells, and 100 bbl/d and 0.01 per month for the final 20 wells

The EU is seeking to further reduce CO₂ emissions with the 2013 introduction of the Emissions Trading Scheme III (ETS-III): the EU’s cap and trade mechanism for CO₂ reduction. This third phase is characterised by tighter caps for each EU member state and a move from freely granted allowances to partial auctioning. The change is aimed at increasing the cost of emissions, giving governments more direct control and incentivising emitters to act. The power sector will be affected differently across the EU as the marginal cost profile of the fuel mix varies. The impact will be accentuated by the recent decision to phase out 20GW of nuclear capacity in Germany by 2022. Combined with increasing demand and renewable targets, the generation sector faces big investment decisions on new capacity.

Large domestic coal deposits have led to more than 90% of Poland’s electricity being generated by coal. Gas accounts for less than half the remainder, alongside hydro. As a result Poland has double the average EU CO₂ intensity. More than two-thirds of the coal power generation fleet is over 30 years old. Much of this has low efficiency compared to modern coal plants, with higher emissions per unit of electrical energy. Gas demand in Poland is running at around 1.6bcf/d and has stayed relatively flat over the past 5 years. Russia supplies around 65% of Poland’s gas demand; the rest is produced from conventional gas fields domestically. Sustaining conventional domestic gas production will become increasingly difficult as the basins mature. The current generation of combined cycle gas turbine (CCGT) power plants have around 60% lower CO₂ emissions per unit of electricity than Poland’s existing coal fleet. In comparison, new high efficiency coal plants emit around twice the CO₂ of CCGT.

The Polish government’s resistance to paying a low carbon premium complicates the outlook.

In June 2011 Poland blocked the EU Low Carbon Roadmap agreement, delaying ratification on setting tougher emission reduction targets. This is just one example of the political manoeuvring that the Polish government has pursued over the past 5 years to slow the pace of EU carbon reduction regulation. The ETS III sets a target of 20% CO₂ reduction by 2020, with 30% of allowances being auctioned for the power sector in new member states (NMS) from 2013. The scheme requires auctioning in NMS to rise to 100% for the power sector by 2020.

Parliamentary elections to both the Sejm and the Senate will be held on October 9^th 2011, raising key questions on how energy and climate policy will develop in 2012 after Poland ends its 6 month presidency of the EU. The Polish government has countered commitments made to the EU on gas and power deregulation by dividing state monopolies with the aim of creating national champions and limiting international ownership. A confluence of uncertainties will affect investment decisions in the power sector in Poland.

Integration across Europe will set the course in Poland.

The challenge for generators will not simply be deciding between whether to build coal or gas power plants. Winners will need to create more integrated business models and commercial arrangements across the value chain; hedging uncertainties outside core competencies in order to respond to policy decisions and market developments.

In the lead up to the elections there is little to differentiate the political parties on key energy policy issues. Subsidies in the coal sector have largely been phased out and coal-based employment has declined by 70% since 1990. Shale gas development has a high profile and strong political backing, unlike in other European countries where there is fierce resistance to fracking. The unity on shale gas comes from a strong desire for increased energy independence from Russia as well as the potential economic benefits of becoming a gas exporter to Europe. Another area of broad agreement is resistance to passing on emission reduction costs to consumers. The chart below illustrates the impact of these uncertainties, and the resulting CO2 and gas prices, on the dispatch curve in Poland.

The complexity surrounding the future generation energy mix is characterised by three key areas of uncertainties:

• Pace of introduction of auctioning in ETS III. To what extent will Poland be able to get derogation to delay or exempt existing and planned plants?
• The degree and speed of market liberalisation in Poland. Uncertainty over ongoing discourse between Poland and the EU on gas and power market liberalisation and pan European investment and ownership. Investment continues to expand cross border transmission capacity opening the question of how policy makers will respond to generators arbitraging CO₂ allowances between countries.
• Gas supply and price. Poland has the largest potential recoverable shale gas resource in Europe[1], with the EIA’s estimate of 187tcf representing 300 years of current demand. However resolving recovery, production and cost uncertainties will take many more years. The potential has attracted many leading international oil and gas companies to explore. Poland has expanded and extended long-term gas supply contracts with Gazprom. It’s uncertain how flexible these contracts are, both in terms of take-or-pay volumes and oil indexation pricing. The Great Recession nearly broke the decades old oil price indexation, but supplier flexibility has seen it largely remain intact.

These uncertainties will not get resolved in isolation. A complex dynamic between investment and markets will play out over the next decade as the Polish generation mix is re-powered.

Contact Adam Mitchell: +44 7876 243 480, amitchell@strategicfit.co.uk, www.strategicfit.co.uk, for further discussion.

Since 2001 the Norwegian Government has implemented several policies to attract new players and encourage exploration activity. The changes have included quickly recycling acreage through Applications in Predefined Areas (APA), and introducing an exploration tax rebate. The number of companies that are active in offshore Norway has increased from fewer than 30 to more than 70 since 2000. The new policies have driven a 300% increase in wildcat exploration drilling since new entrants started applying for licenses (2002-2005 vs. 2008-2011).

Some companies have pursued a “numbers game” exploration strategy. Several factors have encouraged this.  The low post-tax cost of drilling (78% tax rebate); fast pace of licensing; eagerness of small company investors to see results; and long drilling lead times (in a tight rig market companies need to commit twelve to eighteen months ahead of drilling) all create a tendency towards a statistical exploration business model.

However, a “numbers game” approach doesn’t suit several aspects of the Norwegian Continental Shelf (NCS) as a mature basin. Except for the frontiers, large discoveries will be the exception rather than the norm. There are large quantities of data available for companies to deepen their understanding of play systems and work-up prospects.

A statistical approach also ignores the complexities of developing a discovery, once made. In a mature setting, the commerciality of smaller discoveries is critically dependent on exploiting existing facilities. Differences in equity groupings, operator preferences and the optimisation of technical solutions and cost allocation all need to be understood to build a clear picture of what success could look like. Failure to do this causes many technical exploration successes to remain undeveloped on the NCS. So, in effect a statistical approach to exploration does not lead to commercial success.

Focus, full-cycle value and competitive advantage are all essential to successful exploration.

A select number of companies take a very different approach to exploration. These companies have demonstrated a consistent run of commercially successful exploration programmes.

The chart below shows the contrast in success across the selected peer group of active explorers on the NCS.

A comparison of the strategies pursued by these NCS explorers reveals a set of success factors:

• Targeted clusters: Focus on one or more plays where expertise and analysis can reduce risk. Carry out extensive technical work to deepen understanding and identify above ground commercial solutions prior to drilling.
• Quick hub development: Quickly build a licence position around discoveries that may justify a new hub development, to enable the full upside potential of the play to be exploited. Take steps to align facility owners early in the exploration cycle to maximise the chances of commercial solutions.
• Commitment to exploration: Companies have generally drilled several exploration wells in each area to fully explore the potential.  They pursue an extensive exploration campaign to build on understanding gained from early wells and give a realistic chance of a material commercial success. The successful companies in the peer group have on average participated in twenty-one exploration wells over the last five years. Building the capability to demonstrate commitment to Norway helps support licence applications and prospect evaluation.
• A business model to support exploration: The business model needs to support a string of bad exploration outcomes and support appraisal of successful wells. Strategies can support this in a number of ways: (i) equity in existing production; (ii) substantial parent company capital support; (iii) divest commercially successful discoveries.

The combination of these strategies has led to the three top-performing companies delivering on average more than three times the commercial volumes, when compared to the rest of the peer group (177mmboe vs 53mmboe) over the past five years.

This evidence points to the potential limitations of a statistical exploration strategy in a mature province where extensive data is available. Successful companies play to the strengths of their unique capabilities whilst also understanding the business environment of Norway.

Contact Jana Rieck: jrieck@strategicfit.co.uk, or Adam Mitchell amitchell@strategicfit.co.uk, www.strategicfit.co.uk, for more information or further discussion.

Source: StrategicFit assessment, NPD data, company websites (2011). Peer group: Chosen to reflect a group of new entrants with active exploration campaigns.

Norway’s government wants to increase recovery from mature fields on the Norwegian Continental Shelf (NCS). Mature fields are defined as having produced over 60% of their recoverable reserves; most producing fields in Norway meet this description (see fig 1).

In 2010 Norway’s oil production fell more than any other nations’, by 9.4%. The previous year Norway was in the top ten producers: it now occupies the 13th position. Production from large mature oil fields in Norway is declining and the window of opportunity to slow this decline is dwindling.  The NCS already has one of the highest average recovery factors of the world’s offshore petroleum regions. The Norwegian Petroleum Directorate (NPD) studied 36 oil producing fields on the NCS and found, on average, that 29 fields had doubled their reserves compared with the estimate in their original development plan. It will be tough to improve on this.

Figure 1: NPD data and StrategicFit assessment, 2010. The bubbles on the chart represent individual fields on the NCS.  The chart starts in 1971 and can be played through time up to 2010. Press the play button to initiate.  You can experiment with different axes.  Hold the cursor over a bubble to see the field name.

On 24th June 2011, a number of policy measures were announced by Norway’s Ministry of Petroleum and Energy (MPE) as part of a White paper. Among them were several actions to stimulate NCS operators to improve recovery from mature fields. For example, the Norwegian state’s direct investment in oil and gas fields, Petoro, will have a stronger role in challenging operators on mature field investment. Also operators will be required to submit plans to show how recovery will be improved.

These measures are being evaluated by the industry. The key to making them work will be overcoming the complexity inherent in making the right decisions in mature asset settings. Decision making for mature oil and gas assets must address several sources of complexity:

1. Forecasting production can be difficult for mature assets. As fields get older, gas and water constraints come into play with complex implications for production deferral. Surface uncertainties (availability, unplanned maintenance) and subsurface uncertainties (well integrity, reservoir connectivity) don’t necessarily become better understood as a field ages.
2. In most mature asset situations there is a mixture of old infrastructure and fields and discoveries with new potential. How do you balance the requirements for each? Is it worth investing to keep the infrastructure going?
3. There is often a highly interconnected system of platforms, processing hubs and onshore facilities. How do you untangle this and allocate costs to get to a clear picture of where the remaining value lies?
4. Across a given mature “cluster” of assets there is usually a mixture of owners and operators who often have conflicting aims. Some are big and may have regional trade-offs and strategic goals involving several different fields. For smaller partners, a single field may make up 100% of their entire production. It is also key to proactively engage with the authorities to explore a full range of alternatives at an early stage – this requires incorporating yet another set of perspectives.
5. There is a narrow window of opportunity as the end of field life approaches. Yet there can also be a broad range of options, including cost cutting, production acceleration, increased and enhanced oil recovery etc. These options all have different investment levels and payback schedules and often can interact with each other.

These complexities will require a combination of analytical and organisational expertise in order to make the best choices for Norway’s ageing fields, and thereby bring the MPE’s policies to fruition.

Contact Duncan John: +44 7771 562 500, djohn@strategicfit.co.uk, www.strategicfit.co.uk, for further discussion.

The majority of energy intensive companies see carbon emissions as a critical business issue; usually as a threat but for some an opportunity. Formal reporting structures to benchmark carbon emissions have emerged (e.g. www.cdproject.net), and as a result it will challenge companies to explore improvements and set targets.

Carbon emissions are associated with most activities and every investment that a company makes can affect future emissions. When making these investment decisions, project advocates as well as decision makers will apply judgment on how to incorporate emissions in the recommended way forward. At present, the cost of carbon emissions is often zero or so low that it does not significantly affect decisions (approximately €10-20/tonne in Europe).

It is not a trivial exercise to credibly assess the implications of future regulations; it requires judgement and interpretation. Left to the responsibility of individual project teams, these numbers will vary widely based on personal value judgements, facts and logic.  As the same issues apply to most investment decisions, the same discussions could take place simultaneously across the company leading to confusion, inconsistency and suboptimum trade-offs.  Finally, the carbon exposure added up at the corporate level may have strategic implications (e.g. portfolio mix, advocacy approach, technologies) that leadership would like to consciously choose rather than have forced upon them as a result of decisions made lower down the organisation.

Rather than seeing carbon emissions as something that needs to be minimised, carbon exposure should be seen as a business risk that a company needs to manage and value as such.

The leadership question

With this in mind, how can you deal with carbon exposure in a consistent, credible and transparent way?

1. First, each routine decision needs to consistently incorporate the value of carbon emission exposure. This will avoid wasted discussions and inconsistent judgements, as a single policy with trade-offs that reflect the corporate exposure can be established.
2. Secondly, to prevent strategy to be the result of all bottom-up decisions, leadership must be able to clearly distinguish those decisions that are material to the strategic direction of a company – and deal with these as a strategic decision making process.

The diagram above illustrates this framework. The distinction is helpful but it does rely on organisational discipline to implement the policy and leadership to demand choice where decisions are strategic

The distinction is helpful but it does rely on organisational discipline to implement the policy and leadership to demand choice where decisions are strategic.

Contact Jan Paul van Driel: +44 7740 765 944,  jpvandriel@strategicfit.co.uk, www.strategicfit.co.uk,  for further discussion.