Back to Gas: Has the oil price bust leveled the playing field for US natural gas producers?
I have to admit I am not sure I understand all the different theories on market forces on oil price. The notion, whether or not OPEC deliberately made it happen, that North American (NAM) Shale Oil is now the global swing producer and thus oil price ceiling is tied to shale oil breakeven prices does make sense to me. Whatever the true causation though, the consensus on effect appears to be that oil price is set for a phase in the range of $50/bbl. The market appears to agree: today's NYMEX WTI strip does not exceed $54/bbl.
In that context for oil, it seems to me that now is a good time to be applying more focus again on natural gas in the US. I am biased to focus first on gas because:
There appears to be more natural gas (388 tcf or 65 billion boe proved reserves end 2014) than oil (40 billion boe proved reserves end 2014) in the US providing a larger resource for the future;
Simple relative permeability considerations indicate that it ought to be easier to recover than oil;
For the most part, there is infrastructure to take the gas to where it's needed (and US LNG is an emerging component);
Natural gas is a better fuel for the environment that oil or coal; and
I've always been a bit of a contrarian!
However, much of what I am going to point out for natural gas is also true for oil. In a prior article, "Upstream Downturn: Time for Change", I argued the case that upstream oil and gas companies face a transformative challenge which will require a new (and lasting) cost of supply mindset, technology and supply chain transformation through collaboration, glued together by a new capability of operating excellence. In this post, I build on that case for US natural gas producers, outlining six elements of strategy that I believe can underpin a successful and lasting gas business.
Some gas price recovery is forecast
When I first had the privilege of working in the US L48 onshore gas business in 2002, natural gas was over $3/mBtu and on a upward trajectory. I had some oil in my portfolio, conventional of course, but it was gas in tight sandstones and carbonates on which we were focusing our exploratory efforts. Others were starting to extend this idea into shale, for example in the Barnett.
At that time, and until 2006, the price of gas in oil equivalent terms was about the same crude oil, WTI pricing. From 2006 onwards, as oil prices soared, a differential opened up with the gas price. That differential has remained since then, growing to about $60/boe during the period from 2009 to 2015, but has recently closed to about $20/boe. Natural gas and oil forecasts predict that the differential will remain there, or perhaps close further if oil stays flat at about $50 and natural gas gains with $3.50/mBtu peaks in the winters. As Al Walker of Anadarko recently pointed out, particularly with a growing globalization of US natural gas through new LNG export, the price should cycle in this area, with a ceiling much beyond $3.50 unrealistic. If this is right, then gas operators exercising financial discipline could plan on $2.50/mBtu, test projects and their business at $2.00 or even $1.75/mBtu, and dream (but not plan) of natural gas prices north of $3.50.
But shale gas breakeven prices appear to be still too high
There are a larger variety of projections available on breakeven prices for gas wells, ranging from public company presentations, through market analyst reviews, to folks like, for example, Art Berman, who try to include all costs of doing business in breakeven calculations. In Berman's work, the best current shale gas breakeven is $3.43/mBtu which is the low end of the range for the Marcellus, so on the face of it appears that there is not much promise for new developments in these established plays. As Berman points out it seems improbable that the growth of US gas production predicted by the EIA can occur with these shale gas economics. With current costs, prices and economics Berman concludes, and for the avoidance of doubt I agree, that believing shale gas is simultaneously cheap, abundant and profitable is "magical thinking". In the remainder of this article I offer some six strategic elements that I believe could converge to drive down cost of supply and hence make this huge resource profitable to produce. In effect, turn some of the magical thinking into a logical business strategy.
A back to gas strategy
Given this context, those that continue to be wary of natural gas are easily forgiven. For the less faint hearted here are six elements of strategy to be successful as a natural gas producer in the lower 48.
1. Financial discipline. Only sanction development projects that return capital at cost at a reasonable bottom end gas price (say $1.75 or $2.00/mBtu) and make required project returns at a mid case (say $2.50 or strip). Note that "project returns" need to make sense within the business plan so that the venture is overall making required returns for the stakeholders. This implies rigorous testing of projected balance sheets, cash flows and income statements, including the burden of interest payments and general and administration expenses. This discipline drives the team to deliver on the remainder of the elements. It entails no hidden costs, no write-offs of access costs, no hiding behind incremental project economics.
2. Get the right rocks. A study on upstream costs written by IHS Energy and recently published by the EIA gives good insight into the cost elements of shale plays. For the aggressive entrants, land can be acquired quite cheaply (at $200 to $400/acre), but of course these companies are taking on the upfront play risk that there is developable hydrocarbon resource that others have previously missed. The only way is to accomplish this have the best prospectors on your team armed with the best tools and all the available data so some up front investment is required, as well as astute landmen to capture the leases.
Systematic searches for previously overlooked conventional pay or unconventional sweet spots could yield superb opportunities. The cost of supply prize is huge though: late entrants into existing shale plays may pay 30 to 80 times the access costs paid by the aggressive early entrant. Another approach is buy HBP leases - paying for the production which will have its own economics (but with an acceptable return!), while at the same time getting the new play/prospect as part of the deal. The final point of right place relates to the expected differential to market price that gathering, processing and transport costs might cause; there are some geographies which may be disadvantaged by this attribute.
3. Get the rocks right. The most efficient development of gas resources starts with the most capital efficient recovery plan for the reservoirs. In unconventional reservoirs this comes down to identifying zones of higher gas in place coupled with the highest permeability. Then the trick is to place horizontal well laterals in these identified zones to give the well the best chance of high productivity before adding artificial stimulations. The cost saving prize is large: adding multi-stage fracks to a horizontal lateral typically doubles or triples the cost of the well. Artful collaboration between geoscientists, petrophysicists, reservoir engineers and drilling/completion engineers is required within an increasingly "Big Data" environment. Some developers of oil shales (e.g. EOG) have been making progress - the same capability and technology can be applied to gas.
4. Technology innovation, transfer & improvement aimed at unit cost and returns. The science and engineering of unconventional resources continues to evolve. In the subsurface each prospective zone in each play seems to have its own unique characteristics and hence individual recipe for lateral completion to maximize productivity. Lateral length, number of frack stages, frack pressures, volume and type of proppant are amongst the parameters to optimize and harmonize to maximize productivity. In my financially disciplined model, this "code-breaking" learning curve needs to be targeted at unit cost of supply or returns rather than simply EUR and Initial Production rates. Other technologies such as multi-laterals, multi-well pads that share looped processing and compression, new methods of water management, instrumentation and remote monitoring and management can all contribute to more efficient recovery of the resource. Even in a cost-conscious setting I envisage, experimentation with new technologies can occur in a carefully managed manner.
5. Supply chain shift. The previously referenced EIA report on upstream costs, found that 2015 well costs in five onshore areas evaluated had dropped between 25 to 30% below their 2012 zenith. Based on the expectation of continued depressed oil prices in 2016 IHS, who authored the EIA report, produced a further fall in rig rates of 5 to 105 in 2016, followed by small increases in 2017 and 2017. A byproduct of the shift to shale oil depicted in the graph above from 2010 onwards was that increasing demand for rigs for shale oil, inflated costs, giving gas a double whammy of continued low prices while oil soared, and higher finding and development (F&D) costs. Now with oil in a bust cycle, lots of equipment standing idle, the playing field in terms of costs may just be leveled a little. In addition, as the supply chain adapts to the new oil environment, there must be opportunities such as reintegration or longer term contracts to squeeze further cost out of the operation and for operators to retain a greater proportion of the "rent" benefit from the activities they lead. I have heard anecdotes that some supply chain solutions, posed as specialist technological breakthroughs, or integrated optimizations, have proven to be overelaborate and hence wasteful expenditures. Operators need to take responsibility for their operations and the science and engineering behind them, always driving for the next lowest cost of supply.
6. Operational Excellence. I've already highlighted the need and opportunity gas finders and optimizers to be simultaneously systematic and innovative in the search and optimization of cheaper gas. Once delineated, the opportunity for application of systematic learning and continuous improvement is enormous. Once the code is pretty well broken then continuous improvement can really kick in with a company's operating procedures capturing, in a simple, useable and used manner, the current best way (lowest unit cost of supply) to develop and produce gas. Systematic approaches to quickly test ideas for improvement, small and big, must be in place and then a method to update procedures to capture the next best way and extend across the enterprise. There is an enormous wealth of knowhow and experience in the manufacturing industries ready to be tapped for the benefit of the upstream oil and gas arena.
The bottom line: can the numbers work?
I believe that the strategy outlined above can transform the cost of supply picture for natural gas in the US. To illustrate this I created a simple discounted cash flow model for a single horizontal, costing $6m to drill and complete, on 320 acres that cost $5000 per acre to lease delivering a range of volumes, using typical shale gas profiles. I am trying to avoid all the controversy of what profiles and EURs will really prove correct with much elapsed time in shale wells and keep the modeling very simple. My gas prices are net, by which I mean I have not accounted for gathering, processing and transportation costs. The product of the modeling is depicted in the graph above.
Point one has been apparent from the dawn of our industry! Increasing volumes for the same cost is one easy way to make wells more profitable. From the rocks point of view, that's why I think it's a good idea to focus the search for overlooked sweet spots in shale and conventional pays. But also the application of Big Data science to well placement and completion, coupled with great geoscience and engineering experience can improve well recovery.
However, as I preached earlier in this article, the additional volume cannot be delivered with no account of cost. My simple economics indicate that to get well breakevens into the $2 to $3/mBtu range, F&D cost needs to be less than $0.95/mBtu. Hence systematic continuous improvement aimed at unit cost of supply enables both the numerator (cost) and denominator (volume) to be worked in harmony. The graph above depicts first a shift a 1/3 reduction in well capex across the volume cases and then an early entrant lease cost of $500 per acre. I believe these two big shifts are reasonable estimates of the benefits of the actions described above.
A mindset of delivering an F&D cost of less than $1/mBtU coupled with an operational excellence capability and ethos to continue to eliminate waste and hence drive down cost and/or improve productivity will sustain cost of supply improvement in the face of the head winds of inflation and price cycles. With this approach I believe there is a big niche for US gas producers to not only survive, but thrive.