Melissa Stark
Accenture, London
When oil prices went into free fall in the fourth quarter of 2014, the question on everyone's mind was whether US unconventional development would slow down. After all, many of the US shale and tight plays had oil price breakeven costs estimated at $60-65/bbl (some even higher). Here we are, more than 6 months later, and the role of US unconventional development in the global energy mix is even stronger than it was before the oil price falling.
True, virtually all players have reduced their capital expenditure; true that the number of rigs has fallen dramatically; and also true is that despite production per rig and well productivity being at an all-time high, keeping US production flat is probably the best that will happen in 2015 in this ~$50 oil price environment.
But none of these factors mean that unconventional development will decline in the long-term.
The real significance of continued US tight and shale development (even under lower oil prices) is linked to the value oil companies can create by including more unconventional assets in their portfolios.
The emergence of shorter-cycle time and more flexible unconventional resource development programs is changing the way companies manage their US oil and gas assets. An unconventional well can go from exploration to production in less than a year. We are now seeing companies like Anadarko, EOG, Carrizo, and others drill their wells but wait to complete them (UOGR, May/June 2015, p. 1, p. 4).
For example, EOG Chairman and Chief Executive Office Bill Thomas said, "We're starting out 2015 with about 200 uncompleted wells in our inventory. That uncompleted well inventory will grow throughout 2015. And if oil prices improve and they look something like the forward curve in the $60 range, then we would begin completing many of those wells starting in the third quarter of 2015."1
This allows them to use the rigs they have under multiyear contracts while also waiting for the completion costs to go down and/or the oil price to go up. Over the past few months, EOG, Anadarko, ConocoPhillips, and others have publicly stated that large parts of their portfolio are economic at $40-50/bbl.
However, under weaker oil prices, the value question is "why monetize at ~$50/bbl when you have the option to defer development?" The answer is the increasing inventory of wells that are drilled but not completed can be brought onstream quickly. For example, EOG executives stated that it would take about 1 month to see the impact on production of completing the wells that were drilled but not completed.1
For oil companies having both conventional and unconventional assets in their portfolios, the short-cycle, cash-flow profile, and potential upside with respect to productivity and operational cost (discussed later in the article) of unconventional shale and tight plays have influenced the way they calculate the risk-weighted value of their portfolios and potential investments.
For example, in today's low oil price, a conventional multi-billion-dollar mega project in a high-risk geography that is still in concept or pre-investment (high risk, higher return) might be less attractive than the $5 million per well, short-cycle US investment that can be started/stopped more flexibly and has potential upsides (lower risk, lower return).
It's no wonder that ConocoPhillips, ExxonMobil, and Anadarko are directing more of the capital they are spending towards unconventional assets vs. their other conventional plays. ExxonMobil's Chief Executive Officer Rex Tillerson said in March that Exxon will double the amount of oil it pumps from its US shale fields during the next 3 years, even as it moves more cautiously on investments in big projects elsewhere.2
There is significant upside in unconventional development not found in conventional assets for the following reasons:
1. In most of the US tight and shale plays, well productivity is still very low, averaging less than 10% recovery rates for tight oil and less than 25% for shale gas. Anadarko, Conoco, EOG, and others continue to stress that they are not cutting down on the technical research and pilots they are doing to improve characterization of the plays and completion techniques. EOG stated, "As a result of cost in oil productivity improvements in the Eagle Ford western acreage, we can now generate better returns with $65/bbl oil than we did with $95/bbl oil just 2 or 3 years ago."1
2. There are significant cost reduction and continuous improvement opportunities available in the high-well-count environment of shale and tight plays. Costs continue to fall. Referring to Eagle Ford asset where, currently, lifting costs are less than $2.50/bbl., ConocoPhillips recently stated, "Since 2013, we've been able to reduce our drill and complete cost per well by 30%. At the same time, we've increased our ultimate recovery per well by 30%, and we've been able to take our cycle time from spud to first production down by 40% in that same time period."3 This is similar to the efficiencies achieved by Anadarko, EOG, Carrizo, and others.
3. Finally, lower oil prices are expected to drive down services costs and therefore well costs. EOG has said that sees the potential for 10-30% savings in vendor costs during the downturn,1 with Anadarko confirming that it significantly improved its cost structure at a time of relatively lower oil prices over last year, through continued operational efficiencies and savings achieved by working with service providers with Chief Executive Officer Al Walker stating, "The benefits we're getting from lower service costs have significantly improved our economics…we invested less than expected in the quarter and delivered sales volumes that surpassed the high end of our guidance." Anadarko's drilling and completion costs went down 14%-15% in the Eagle Ford shale of South Texas and Wattenberg field of Colorado during the same periods.4 Also even if the weaker oil price is leading to a downturn in the US service sector and pressure on costs and margins, the softening of demand in the US is improving the availability of services needed to support international unconventional development. Accenture's International Development of Unconventional Resources report found the development of an unconventional services sector is seen as a key challenge to any large-scale shale and tight resource development outside of North America. Given the downturn in the US, services companies and other unconventional suppliers are now looking towards other markets (e.g., Argentina, Saudi Arabia, and China) for new opportunities.
Far from stopping unconventional development, the low oil price has the US unconventional industry focusing on operational efficiencies, forcing it to drive down costs and increase productivity as well as supporting the spread of US shale and tight services expertise internationally. This sector is also expecting to see more merger and acquisition activity as the most efficient players get bigger and the smaller, less-efficient players are squeezed out and bought.
In 2015, US unconventional production is likely to stay flat or decline as players wait for the oil prices to increase. For companies having cash flow, it is a prudent business decision to exercise the option of seeing whether oil prices will rise. But if oil prices seem to be settling at $50-$60/bbl, producers who can achieve a return at these prices may start releasing production, and unconventional development will start to grow again. For those players who also have conventional plays in their portfolios, lower oil prices also are demonstrating the value of having short-cycle investments allowing them to reduce overall risk and create optionality.
References
1 EOG Resources Inc. fourth-quarter earnings call, Feb. 19, 2015, CQ FD Disclosure.
2 "Exxon Looks to US Shale Fields to Drive Global Growth," Mar. 5, 2015, Bloomberg.
3 ConocoPhillips analyst and investors meeting, Apr. 8, 2015, CQ, FD Disclosure.
4 "Anadarko sees Q1 output jump with less rigs; raises 2015 production target 2%," May 5, 2015, Platts Commodity News.
