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Cost reductions will be key to international unconventional gas
Executive Summary
Operators will need to focus on driving down costs if many of the international unconventional gas plays that are attracting so much interest are to be proven economic. Our analysis concludes that a reduction in unit capex of around 20% is needed to ensure most of these plays enhance portfolio value.
In Europe, high drilling costs mean that our models for tight gas and shale gas all return less than 10% despite a positive long term gas price and low fiscal take. However, as the industry becomes more active in these areas, we expect returns to improve due to falling costs.
In this Insight we lay out compelling reasons why future costs are likely to fall, including:
These reductions will occur at a slower pace, and to a lesser overall extent, than they have done in North America. In particular, the evolution of the supply chain will depend on the behaviour of local service companies and host governments.
Investors, as a result, will need to take a long-term approach to these plays. Patience could be rewarded though, as a 20% reduction in capex lowers the breakeven gas prices by US$1.12/mcf to US$2.01/mcf from our base case models.
Introduction - the importance of cost control
Managing costs to ensure that gas is extracted efficiently is critical for unconventional developments, as more effort is required to recover each cubic foot compared to conventional plays. To date, no large scale developments have commenced outside North America or Australia, and whether costs can support unconventional developments elsewhere in the world has yet to be fully tested. At this stage, the costs in many areas are prohibitive - for example well costs in Europe can be five times that of the US. We expect costs to come down though as operators focus their efforts on commercialising these resource plays.
Establishing operational scale has been key in reducing costs in commercial plays. Specific benefits can be achieved by sharing gathering infrastructure and common water storage facilities, and utilising pad drilling. Relatively small cost gains can have a significant effect on total value when thousands of closely spaced wells are required in a development.
Cost reductions have also been achieved through drilling improvements. This can involve a more efficient use of casing, eliminating intermediate strings; improved fluid engineering, which leads to shorter drill times; and the use of optimal equipment on the surface such as top-drive rigs.
As well as direct cost improvements, service sector competition also drives down costs. This was striking in some of the first commercial shale plays in the US, where an effective oligopoly for pressure pumping services was broken by the emergence of numerous small, local providers. Eventually, frac jobs could be sourced for 30% less.
How do international plays compare ?
The initial focus in a play is to assess the sub-surface and a focus on costs only comes after this. Hence, these potential cost benefits only emerge as a play matures, and to date, material cost improvements have only really been seen in plays in North America and CBM plays in Australia.
Costs in many of the CBM plays in Asia already look low even before material unconventional gas production. This is partly due to lower labour costs, and the existence of large scale conventional production which means that there is capacity in local service sectors to support new unconventional developments. However, the key feature of these plays is the fact that these are typically much shallower than the emerging shales.
Current average per unit capex is highest in Europe
In Europe, costs are currently high as the industry lacks the scale and complexity of North America. Only a fraction of the number of wells are drilled when comparing the region to North America, and the vast majority of these are shallow vertical wells with simple completions. Drill times are often slow, and for complex wells, it can be difficult to source the right equipment, materials, and expertise. At present, a multi-frac horizontal well will cost over US$20 million and take many months to drill and complete.
Additionally, there are some specific characteristics of the supply chain in Europe which increase our estimates of the cost of operating in these areas:
• Some local rig markets are dominated by state-controlled or heavily state influenced companies,
reducing the effect that competition can have on costs. In Poland, the only two active drilling companies are subsidiaries of the national gas company PGNiG.
• There is an extremely limited supply of key services for unconventional gas drilling. In Europe as a whole, only a small number of rigs are capable of drilling horizontal wells. There are also just a few frac crews and they have to travel from country to country to support operations.
• Drill times are much longer as each well is bespoke and crews are not used to fast efficient operations
- getting one key well right is the typical aim. For example a tight gas well in Northern Europe drilled for 11 months and there have been lengthy mobilisation delays between drilling and fracturing wells in the Ukraine.
• Many of the countries being targeted are members of the European Union, and as such, have similar environmental and working regulations. These are in general stricter than North America and add an increased bureaucratic burden. Common EU regulations do facilitate the movement of equipment between different countries, but local regulations still exist and language differences also compound the bureaucratic burden.
Despite these apparent hurdles, large industry players continue to commit both financial and human capital towards evaluating the potential of international unconventional assets.
How does this translate into returns?
The high long term gas price outlook, and in many areas lower tax rate, mean that costs will not need to fall as far in Europe as they have done in North America. The full cycle returns of each play allow us to examine this trade off between costs and price.
To do this, we selected the six most capitally intensive international plays in Wood Mackenzie's Unconventional Gas Service as a sample set to perform capex sensitivities. These are highlighted in the chart below and consist of European tight and shale gas plays, plus a shale play in Algeria.
Unit capital costs in these plays is expected to be between US$2.00/mcfe and US$3.60/mcfe, roughly double that of commercial North American developments and substantially higher than those in the other international plays, which are primarily CBM.
The costs modelled are those expected for an early, 500 bcf development in the play. They include a substantial discount (of around 25%) on current costs, as there will be economies of scale if a multi well programme is sanctioned and cost savings will have been identified from earlier drilling. The sensitivity we perform later in this Insight represents a further reduction on costs.
Unit capex calculated for a 500 bcf development in each play. Costs include drilling, completion, leasehold, facilities, pipeline tie-in, and lease acquisition. The total is divided by gross volumes to calculate the unit metric. IRR is calculated using representative regional prices for each respective play.
At our base gas price in Europe, costs are too high to generate a 10% return on these plays. However, operators are at the start of the learning curve and costs are expected to come down further. For the European plays shown, a further drop in unit capex of 20% ensures they all either pass a 10% hurdle rate or get close to it. The Algerian shale play will either need substantially larger unit cost reductions or more attractive fiscal terms.
To give some perspective on the amount costs can fall, Barnett Shale wells currently cost US$2.4 million to drill and complete. Early wells in the play in the 1980s cost US$7.0 to US$8.0 million.
Unit capex calculated for a 500 bcf development. Costs include drilling, completion, leasehold, facilities, pipeline tie-in, and flease acquisition. All of these variables were reduced by 20% for the sensitivity. The new total is divided by gross volumes to calculate the unit metric. IRR is calculated using representative regional prices for each respective play.
What are the most likely cost savings?
The first commercial completion was a trigger event for cost reductions in the US, and this is likely to be the case in the international plays. In the six plays that we have focussed on, we believe that the most likely savings will derive from:
■ Increased competition in the supply chain - As more companies establish positions in international basins, the number of service providers in each play will also increase. Drilling efficiency in these plays is currently low, so the revenue potential for drillers could be significant. Additionally, service firms including Smith and Baker Hughes have expressed intentions of growing their market share outside of North America. This could result in competitive pricing.
The lack of a competitive environment in many areas of the supply chain in Europe means that if genuine competition develops then substantial cost savings could be achieved. The rate at which this occurs though is likely to be slowed by the presence of strong incumbent players and the lack of scale on offer in the near term for service companies.
■ New build equipment - Many of the rigs outside of North America and Australia are not ideal for unconventional developments. They can not be rapidly moved from location to location, nor do they incorporate new technology such as top drive motors, AC power supply, or automated pipe handling. As the demand for rigs increases in unconventional plays, more appropriate equipment will enter the market allowing for cost savings through efficiency gains. Some operators have alluded to building custom rigs to develop specific international plays, once the potential of these assets is better established.
Increased capability of the supply chain - Early in a play's development, expertise and equipment will need to be imported, but as progress is made, the capability of the local supply chain should increase and support driving down costs. To some extent this is all part of increased competition, but this may not always be the driver. In China for example, local suppliers are not driven by competition but the ability of Chinese companies to replicate engineering at low cost. This has been demonstrated across other industries.
Knowledge sharing consortia - In North American plays, these have developed among leading operators once stealth leasing activity is complete. Examples include the Core Lab Consortium in the Haynesville Shale and the Barnett Shale Water Conservation and Management Committee in North Texas. These groups share technical knowledge and collaborate on forming joint solutions to operational challenges. Benefits from this type of work can have a positive impact on many elements of projects, including long term cost savings.
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Profile of larger operators - The likes of ExxonMobil, Shell, and ConocoPhillips are likely to intently focus on continual process improvements, proactively monitor costs, and utilise advanced risk mitigation techniques. In contrast, some North American independents took a more growth-driven development strategy in US unconventional plays. Larger players will be key to cross pollinating technology and subsurface techniques developed in North America.
Partnerships providing scale - Numerous joint ventures and alliances have been formed by domestic E&Ps to share midstream assets, pool leases, and exercise leverage with external stakeholders such as regulatory agencies and vendors. Given the current composition of operators in the international plays we are analysing, and their history of collaboration on large projects, we expect partnerships to transpire in international unconventional plays.
Operators are also expected to partner with service sector companies particularly where competition does not exist. For the operators, it will ensure they get the services they require at an agreed price and for the suppliers, it ensures a material investment opportunity.
The above should certify that further significant cost savings are possible. But in many areas, the decreases are not going to be realised as quickly or to the level seen in North America due to the lack of current scale and complexity of the service sector.
The role of incumbent players will also be key to the speed with which the service sector develops, both in terms of their willingness to adopt new technologies and working practices, and also their openness to increased competition. On the latter point, the role of the governments in ensuring competition will be vitally important.
Conclusions - what does this mean for investors?
The economics of shale gas and tight gas looks marginal in a number of areas outside of North America. Unit cost will need to be reduced by a further 20% over and above our current models to make most of these plays economically viable. We believe this is achievable, but not immediately. The small scale of the industry in Europe and elsewhere, and the lack of complex drilling and completion equipment, means that it will take time to build up a competitive supply chain. There are also strong incumbents in a number of countries and they may slow the pace of progress. More stringent environmental, planning, and working regulations also add a bureaucratic burden.
In order to achieve the cost reductions, operators will have to gain material access and assess scale in these plays. They may also need to look at their business models in order to ensure they are able to secure equipment and expertise when they need it and at the right price.
Timing will not be sudden for costs savings, and investors will need to take a long term view on these plays. Signposts to watch for could include: the first flowing shale gas well in Poland or Germany, announcements of service companies scaling up operations, the development of an A&D market, or alliances being formed between operators and local authorities