A set of attractive targets and specific goals may gain initial buy-in. However it is only by clearly communicating the risks, upsides and context of the opportunity that long-term commitment to the strategy can be secured. A complete exploration strategy clearly outlines both (i) the size of the prize and commitment and (ii) the risks/upsides associated with it.

(i) Defining the size of the prize and commitment
• Setting the scene and being explicit about what can we win in our target areas and why. Companies that have followed a statistical ‘numbers game’ have often ended–up spreading their expertise too thinly, and delivered less success than more focused approaches. Opportunities that are championed based on a compelling argument of the company’s ‘right-to-win’ and its unique capabilities that can support success (e.g. expertise in deepwater exploration), have a higher potential of gaining buy-in. Also setting these opportunities within the business context of the competition and infrastructure constraints etc., gives more confidence to leadership in making decisions.They can decide, from a common level of understanding, which opportunities/challenges the environment offers and how these shape the size of the ‘prize’ in terms of new volumes, costs, etc.

 

• Illustrating how the exploration opportunities align with the overall country strategy across functions. In some cases different functions (production, exploration, BD) prioritise opportunities according to their own agendas (e.g., EOR and exploration only in existing licences vs. focus on new area entry). Such conflicting and fragmented views can become an obstacle in effective evaluation and resource planning and will inevitably make leadership less confident to commit.

 

• Allowing leadership to challenge and test changes to assumptions and choices. For example, an exploration strategy with the objective of ‘early-mover in a new accessible area’ is highly dependent on when and how much the government will open up for exploration.  This is a ‘moving target’ that directly impacts the timing and size of new volumes. Flexibility to test and re-asses such uncertainties as new information comes in, makes the evaluation more robust and helps set realistic timeframes and expectations on key outcomes.

 

• Identifying the necessary resources required to implement.Making a strategy decision has resource implications.  The more explicit this link, the easier it is to prevent falling in the trap, where others are tasked to implement the strategy. It becomes clear to leadership that along with their commitment to a strategy they are asked to commit to the resources required to make it happen. As such, they will want to see a resource plan that outlines exactly what this commitment entails and the contingencies implicit in key uncertainties.

(ii) Bringing insight to key risks and upside

• Focusing the discussion on the uncertainties that affect value the most. Often attention can be falsely directed towards uncertainties that seem intuitively important. However there are a large number of uncertainties to be considered such as timing and access to acreage (opening up of new areas or probability of success in license awards/acquisitions), infrastructure/rig availability, access to market, partnering opportunities, etc. Implications of these uncertainties are complex and wide-ranging. Evaluating and presenting uncertainties in a comparable and quantifiable manner, helps focus on the key value drivers.

 

• Highlighting trade-offs in terms of value metrics important to leadership. Describe the opportunity in the context of corporate portfolio goals, such as booked reserves, production volumes, ENPV, IRR etc. to allow leadership to directly compare against opportunities on the global portfolio.

Bringing a well-structured story to stakeholders, that defines the opportunity within its full context of uncertainty, positions the conversation at a much more constructive starting point. Focus does not linger simply on the outcomes and targets but on the upsides and risks. Leadership gains a better understanding of what uncertainties drive the value and is in a better position to commit to the strategy for the longer-term.

Contact Nassia Inglessis: +44 771 784 8629, ninglessis@strategicfit.co.uk, www.strategicfit.co.uk, for further discussion.

We talked to some senior industry professionals with first-hand experience of working on the leadership teams of a super-major shale gas ventures in Europe. They shared with us what they learnt from their experiences that may help set other ventures up for success in the future:

1. If you don’t tell the story it will be told for you. At the exploration stage of a shale gas venture there is huge uncertainty around what a development would look like.  E.g., How many wells? With what spacing? How many fraccs? What will the above-ground footprint look like?  The temptation is to wait and see before communicating the ultimate vision.  However, the result of this is a vacuum that is easy to fill by the opposition.  For example, they can show pictures of intensively drilled “moonscapes” in North America.  In the absence of credible visualisations of what the venture could look like, that embrace the uncertainty, you look like either you are hiding something or at best like you don’t know what you are doing.
2. Be clear on which stakeholders matter most: In one European shale gas venture the team were encouraged by local municipal politicians to conduct exploration activities in their boroughs.  So out of a vast potential area the team focused their coring well activity in a small region.  However, one year later local elections changed the municipal politicians.  People in the area had become strongly opposed to the shale gas activity and voted in representatives who would block permitting.   The company hadn’t paid enough attention to the stakeholders that mattered.  The Polish government has been very supportive of shale gas as a solution to its dependency on Russian gas, but it doesn’t necessarily follow that it will be easy for companies to get acceptance at the local level.
3. Focus on the neutrals not the hard core opposition. There will always be people who oppose industrial activity in a new area.  On top of this, fraccing has unique issues, both perceived and real (for instance, accurate or not, the Gas Land documentary makes compelling viewing).  Shale gas exploitation involves huge, potentially disruptive movements of equipment, water, people and other raw materials. There will be a kernel of opposition who just won’t change their minds whatever information they receive: any venture will have to live with this.  However, there is also a much larger group of neutral people who can become supportive if the venture’s benefits and risks are clearly explained. This is especially important in the absence of automatic royalties for land-owners.  Effort should be invested to clearly explain the benefits in terms of jobs, individual compensation and investment in the local community, etc.  It can also be critical to recruit people who actually live in the affected area to act as company liaisons.
4. Don’t under-estimate the opposition. Those opposed to shale gas activity can be well-funded and very well-organised.  In one case in Europe a local group hired a professional PR firm and created a 30-page strategy document for blocking every type of activity related to shale gas.  Companies have been taken by surprise. In January 2012 Cuadrilla sent their CEO to a village-hall meeting in Ballcombe, West Sussex to explain their fraccing plans.  Two hundred people packed the hall and gave him an extremely rough ride that was reported in the UK national press.   “This is how they burn witches I guess,” the director of  Cuadrilla’s PR firm said to the Guardian newspaper: “I can think of dozens of oil companies who wouldn’t put themselves through this in a million years and maybe they have it right.”

It’s important to quickly identify and focus on what matters and to be proactive about communicating uncertainty.  Stakeholder engagement is strategic and needs to be integrated with decision-making across the venture – along with subsurface, commercial and infrastructure considerations.  No doubt there are many more lessons that can be learnt from both historic and future external stakeholder engagements. However it is clear that this is a challenge that needs careful consideration if unconventional venturers are to be successful in Europe.

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

The aspired impact of providing clarity on the UK’s government contribution to abandonment liability is to align the private and public sector trade-offs, resulting in i) removing a temptation to ‘bank’ liabilities to ensure the government pays its way, and ii) facilitating asset transfers to ‘natural owners’.

How achievable are the objectives?

It can be argued that the rules were already very clear so this additional clarity is simply stating the obvious; the bigger risk is that the rules will be changed and the track record of the UK government (under any party) maintaining an unreliable fiscal regime.  It appears that the Exchequer has removed this uncertainty and in particularly has locked in Petroleum Revenue Tax (PRT) relief – assuming this guarantee actually holds, this results in removing the need for an owner to accelerate abandonment ahead of its economic end of life just to safeguard tax relief.

The bigger objective is to encourage change in asset ownership to their natural owners.  The UK has in relative terms a pretty good track record of achieving some flux in ownership with very positive results. BP has pioneered large scale strategic asset transfers, with the transfer of the Forties field to Apache as a notable example.  There is no doubt that this resulted in substantial added value as BP would have found other more attractive investment opportunities for their investments, never being able to prove the highly profitable investment case that Apache made as Forties operator. A key hurdle is that owners stick to their legacy assets just too long to make it attractive for others to embark on and invest in a completely different strategy. Another difficulty is that once an asset is sold, the liability could still find its way to the original owner if the new owner defaults. This leads sellers to demand letters of credit for the potential costs and adding to the expense of deals. The change announced today makes it only a little easier to finance but fails to tackle the bigger issues.

Two other significant changes to note: firstly the new allowances to somewhat offset the negative response to last year’s supplementary tax hike to 32%. Probably a good idea but we believe time will tell whether application is practical and whether the change lasts.  Finally reduced corporation tax for small companies – StrategicFit naturally gives this full marks.

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

The workshop was the first in a new SPE Global Integrated Workshop Series on the topic of production forecasting.

Click below to view the poster that StrategicFit published for the event:
StrategicFit Production Forecasting Poster

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

We have written a short article, published in the latest edition of the Decom North Sea Magazine, exploring the challenges and value of making good quality decisions within this period.

Click here to view the article (page 12).

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

Following on from our previous study on the developments in in France we have written the following presentation on the response in the UK. It provides insight into the fallout from seismic activity caused by fracking, the structure of relevant environmental and financial regulations and the state of current public opposition.

Click below to view presentation: StrategicFit – UK Unconventionals regulation

Contact Chris Jones: +44 7904 092 064, cjones@strategicfit.co.uk, www.strategicfit.co.uk, for further discussion.

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.