Improvements in technology have driven the shale revolution. Among these improvements are both cost cutting by oilfield service providers and longer laterals from E&P companies. While capacity constraints from a lack of infrastructure has led to pricing differentials (particularly in the Permian Basin), a lack of inventory in the global oil market is expected to support higher prices, while also increasing price volatility.
As we plan to do every quarter, we take a look at some of the earnings commentary of large players in the oil and gas space to gain further insight into the challenges and opportunities developing in the industry.
Theme 1: Regardless of Region, Longer Laterals are Driving Efficiencies for E&P Companies
- [W]e continue to capture efficiencies through longer laterals. Last year, our program averaged 8,000 feet, but our portfolio high-grading efforts and asset swaps are enabling us to push beyond that, especially in New Mexico. Our average lateral length for the entire program will increase 20% next year to 9,700 feet. – Jack F. Harper, President and CFO, Concho Resources, Inc.
- We expect to continue to improve returns through the use of longer laterals and optimizing completion techniques. – Taylor L. Reid, Director, President, and COO, Oasis Petroleum, Inc.
- [T]here’s quite a bit of room for 15,000 foot and even longer laterals in the Eagle Ford, particularly in the Western area. […] On the Permian, it’s really driven by the existing well in the lease geometry. So there’s areas where there’s quite a few 15,000 foot wells. – Herbert Vogel, EVP – Operations, SM Energy
- The well mix in the Eagle Ford during the third quarter included a higher proportion of western acreage wells. While the pay is thinner in the west, there’s less faulting, which allows for longer laterals. The longer laterals you can drill, the better the efficiencies to be gained during drilling and completions. – Ezra Y. Yacob, EVP of Exploration and Production, EOG Resources, Inc.
- When you break down the value of drilling long laterals, there are three areas to consider: development efficiency; well performance; and capital efficiency. [… Development efficiency] is our ability to maximize access to the reservoir with a single wellbore, allowing us to develop more acreage and resource from a much smaller footprint. […] It’s still early in the game when it comes to evaluating well performance for long laterals […] but none of our reviews have indicated any adverse impact of lateral length to well performance. […] Longer laterals can significantly reduce and even eliminate a number of costs in areas such as well pad and road construction, top-hole drilling, drilling and completion mobilizations, surface facilities and reduce cycle times. […] We are now at the point where the time to drill an additional 5,000 to 10,000 feet of lateral length may only be a couple of days requiring minimal incremental capital to being spent. – Jeffrey L. Ventura, President and CEO, Range Resources Corp.
Longer laterals allow companies a host of advantages in terms of cost, while not necessarily negatively impacting performance. While longer laterals have been used in the industry for some time now, industry players have been more vocal about the possibilities created by drilling longer laterals. Lateral length has consistently increased over the years. For example, the average lateral length per well in West Virginia was 2,500 feet in 2007, compared to more than 7,000 feet in 2016. Although they are not the common place, many operators have reported laterals in the 12,000 to 13,000 feet range.
Longer laterals lower costs for E&P companies which increases firms’ values with more revenue reaching the bottom line. Of course, there are limitations. Longer laterals generally require the consolidation of acreage ownership.
Theme 2: Oilfield Services Costs are Expected to Remain Steady
- New technology is increasing drilling speeds, drilling more consistent targets and lowering cost, all at the same time. Combined with cost reductions from local sand, water recycling and infrastructure projects, we are well on our way to achieving our stretch goal of reducing average cost 5% by year-end 2018. […] As we near the end of 2018, industry activity is slowing. Consequently, the service sector is experiencing a period of softness in the market. To take advantage of market conditions, we elected to secure some of our existing service providers through the fourth quarter for next year’s program. This will capture favorable prices and sustain the operational continuity of these high-performing service providers into 2019. – Lloyd W. Helms, Jr., COO, EOG Resources, Inc.
- My perspective long term on service costs is that what [oilfield service] companies really needed was utilization and now we’re seeing that across the industry. A lot of them are pretty much fully utilized. And we still see a lot of expansion within our industry today. That’s what’s going on when you look broadly. So, these service companies are getting healthier all the time. And so, instead of just forcing prices up, continually getting more efficient and with more utilization, we think it could stay in about the same plane that it’s in today. – Harold G. Hamm, CEO, Continental Resources, Inc.
- [W]ith respect to service costs, what we’re seeing at least at this point is not a lot of move overall in the service costs. There are pockets of small things that we’ve seen bump up. We’re optimistic on the pressure pumping side that it’s going to be flat to down. And so we’re not anticipating a big move in service costs for 2019, but we’ll continue to monitor that. – Thomas B. Nusz, Director and CEO, Oasis Petroleum, Inc.
In regions where drilling has ballooned, service providers are fully utilized. New players are entering these markets to deal with the expansion, which has helped keep prices steady. In regions where there is less activity, some players are looking to lock in longer-term contracts to take advantage of lower costs. Regional market dynamics are different, though the impact on oilfield service costs appears to be the same.
Increased activity means more revenue for E&P companies and oilfield service providers. However, if oilfield service providers are able to command a higher price, E&P companies, valuations will suffer. However, the majority of industry players believe that oilfield servicers will not continue to raise prices next year.
Theme 3: Infrastructure Issues Persist
- Costs have started to stabilize as the industry awaits new long haul pipe capacity before increasing activity […] the drilled but uncompleted backlog has reached new highs and will likely be a catalyst for activity once the new pipeline projects are completed. The Midland discount to Cushing’s WTI has narrowed as capacity may come online sooner than previously expected. The futures curve indicates that Midland barrels will be priced at a premium WTI in 2020 and beyond. – Timothy A. Leach, Chairman & CEO, Concho Resources, Inc.
- Range has also seen significant, improved in-basin pricing compared to last year as the Appalachian gas market is benefiting from new pipeline capacity additions in both northeast and southwest Pennsylvania […] Over the next couple of years, we expect basis to remain strong in southwest Pennsylvania as additional pipelines are placed into service that will keep that portion of the basin free-flowing in the other markets. – Jeffrey L. Ventura, President and CEO, Range Resources Corp.
- Although we expect to see oil differentials to be wider for the fourth quarter, we retain our existing annual guidance, although likely in the upper half of the guidance range. The productivity of the Bakken is driving a significant expansion of basin takeaway. We expect to see the expansion of existing pipeline capacity as well as new pipelines entering the basin. Some of this capacity will come online in the next few months with a strong ramp-up through 2019 and entering 2020. On the gas side, we expect fourth quarter gas differentials to remain strong and reiterate our annual guidance. Looking forward to 2019, we expect a significant expansion of gas processing capacity in the Bakken, expanding as much as 50%. – John D. Hart, SVP, CFO, and Treasurer Continental Resources, Inc.
- If you look at the DAPL [Dakota Access Pipeline] and size that line until you know that you’ve got expansion capabilities there that it’s going to be almost 40% more capacity that’s going to come on with that eventually. That was from their initial projections to where that’s going to go. So, that’s a good bit of capacity right there that they’ll be adding. And the next is new construction. Obviously […] there’s a lot more oil to come out of the Bakken. And so, these new pipeline projects are going to pay off beautifully as time goes on. So, there’s going to be a lot of brownfield, greenfield pipe to be added. – Harold G. Hamm, CEO, Continental Resources, Inc.
As we’ve discussed, differentials between the standardized Cushing, Oklahoma prices and more localized Midland prices have been climbing for much of the year and remained wide until the end of the third quarter due in large part to capacity constraints from a lack of infrastructure in place to bring the product to market. As we see from these quotes, infrastructure issues aren’t confined solely to the Permian as many operators are dealing with in basin pricing differentials.
Infrastructure issues are curbing the gains that are typically associated with rising prices and production.
Theme 4: Less Inventory in the Global Market Leads to Higher Prices and More Volatility
- Looking at the macro environment, with the oil markets in a more balanced position, OECD commercial stocks have declined to below the 5 year rolling average. U.S. crude and product stocks, which account for around 40% of total OECD inventory, have reduced significantly over the last year to the middle of the range. With lower stock levels, the oil price remains volatile to any uncertainties, particularly around supply and geopolitics. Recent factors include the impact of U.S. sanctions on Iranian exports, supply disruption from Venezuela, together with production uncertainty from Libya and levels of spare capacity within OPEC. In summary, the oil price outlook has strengthened. We expect the oil market to remain volatile in the near term, characterized by lower stock levels and ongoing geopolitical factors. We expect current supply concerns to ease and continued robust demand growth to be matched by growth in the U.S. tight oil production and additional supply from non-OPEC countries. – Brian Gilvary, CFO, British Petroleum
- It all comes back to supply and demand in the world, and we still see demand strong, about 1.5 million barrel to 1.8 million barrels of new oil. And on the supply side, hopefully, we can keep up with that. About 65% of that will come from the U.S. But if we go forward with the Iranian sanctions, as I anticipate, take another 800,000 barrels off the market, long term, things are going to get tight. And so, we expect it to be pretty close going forward through the end of the year. So, oil prices are going to be strong, and hopefully we’ll have a cold winter to keep us there with natural gas. – Harold G. Hamm, CEO, Continental Resources, Inc.
When there are supply constraints, price tends to go up. Despite increases in production in the United States, global oil production has experienced declines, causing global oil inventories to be drawn down amid strong demand. When there are lower levels of global inventory, there is less supply available to smooth volatility in the energy market.
Higher crude prices should be a positive sign for the E&P industry. However, it must be viewed in the context of the global environment. With significant differentials experienced regionally, companies are not reaping the benefit of global price improvements. Further increased volatility makes it more difficult for companies to make accurate projections, which is particularly important given the size of the capital budgeting decisions required in the industry.