In the previous Unconventional Yearbook, Stratas Advisors presented 2018 growth estimates of 18% for U.S. unconventional resources, calling for average production of 16.6 MMboe/d for the year. With 2017 and 2018 largely in the books, it is safe to say that 2018 production is likely to average 17 to 17.5 MMboe/d, approximately 4% above the company’s estimate from last year.
So what did Stratas get right and where did things go astray? For starters, the Permian came on stronger than expected. A quick look at last year’s yearbook forecast confirms Stratas’ call for 3.7 MMboe/d, translating to 1.2 MMboe/d of growth from unconventional resources in the Permian. Comparing the estimate to the 1.6 MMboe/d growth (as of Nov. 13) shows a greater than 30% upside surprise. Additionally, the Bakken accounts for another 0.2 MMboe/d of unexpected upside. Combined, the Permian and Bakken account for almost 90% of the surprise.
Notably, the Wolfcamp in the Delaware sub-basin is the key resource behind the Permian’s remarkable growth. Other surprises in 2018 worthy of mention include the Scoop play, which is surging faster than expected on the back of the Springer Shale, and the Powder River Basin, driven by strength from multiple horizons including the Turner, Sussex, Mowry and Niobrara, among others.
Looking through the windshield
With 2018’s review behind us, Stratas turned its attention to the outlook for 2019. Hydrocarbon production from unconventional resources is forecast to average 20.3 MMboe/d in 2019, up 17% from the 17.3 MMboe/d in 2018. Liquids represents approximately 38% of the barrels of oil equivalent in 2019.
Splitting apart liquids from wellhead gas, changes in the growth rate in Permian oil production become pronounced in the near future. Key factors leading to the slowdown in Permian growth is a flat rig count, a rising “maintenance mountain” and lingering constraints, both infrastructure and other. In 2019 the Permian rig count is expected to remain rangebound at ±50 versus the current count of nearly 500.
The biggest headwind facing Permian growth, and by default U.S. production growth, is slowing growth in field activity. In mid-2016 there were about 130 rigs drilling for shale in the Permian. A year later, the number more than doubled to about 330 rigs. In mid-2018 an additional 110 rigs were added, raising the count to about 440. Clearly, the rate of growth in the number of shale rigs in the Permian is already slowing. At mid-2019, this count will rise by another 20 rigs, plus or minus, thus averaging close to 460 units. Beyond 2019, Permian rig counts will continue growing, albeit more moderately. Prospects for moderating rig additions coupled with persistent challenges to capture greater capital efficiency will be key factors behind slowing production growth.
Slowing growth will manifest through increasing challenges at replacing production declines, previously noted as the maintenance mountain. In the Permian the slowing growth in the number of operating rigs foretells of a rising maintenance challenge. Two factors figure prominently in this challenge: 1) high initial decline rates in young wells will lead to substantial replacement needs in the near term, and 2) slowing numbers of new wells added will extract a greater price in terms of production replacement from each new well added.
Stratas’ framework for analyzing production components lays a foundation for explaining the productive nature of oil and gas resources. Production is apportioned to “base” and “new source” components. Base components represent the stock of wells that were already flowing hydrocarbons at the end of the year prior to the year being observed. New source components represent the stock of wells added in the year being observed. The more wells introduced in the last 12 months, the younger the average age in the stock of wells. The relative youthfulness of the stock of wells is a huge factor on average production declines in a play.
Base wells, without intervention, are always in decline. In the age of shale, declines are far greater in the early years of a well’s productive life. Typical first-year declines in shale wells are well above 50%, while subsequent declines are notably less than first-year figures. Extrapolating this to rigs, as goes the rig count, so goes the average youthfulness of the wells (with some caveats, of course). First, remember that a lag between drilling and first production of five months or more is common. It is important to recognize that the specifics surrounding inflection points and trends with respect to youthfulness varies accordingly.
New source production fulfills two vital roles. New wells replenish spent production capacity, refilling the productive tank from losses arising from declining production. New wells also are the primary source for growth. Analysts often view these two elements as “maintenance” and “growth” components. Analysts pay particular attention to the volumes needed to keep production flat with the prior year’s exit rate.
Consider the Permian, specifically now that the essence of play youthfulness has been covered. Slowing growth in rig counts coupled with drilling increasing numbers of complex and sophisticated wells is expected to lead to an inflection point in the number of new Permian shale wells added by the early 2020s. When this occurs, the full weight of the steep declines on Permian production will begin to show. Transitions like the one envisioned for the Permian in the early 2020s typically result in greater proportions of new source production being consumed by maintenance. Therefore, less production from new wells is available for growth.
Drilling, cutting costs
In the modern shale era, it is no longer good enough to report rising type wells and record 30-day peak rates. Contemporary investors are demanding responsible development and financial results. Initial efforts focused on capturing drilling efficiencies by reducing the number of days for getting wells down. Oftentimes, wellbore quality was sacrificed in the quest to report the best drill times ensued. Severe doglegs constrained completion options and well productivity suffered. Not long after, industry pros adjusted goals, emphasizing both speed and quality in drilling.
Persistently low prices led to more changes. For shale to compete with OPEC and other resources, costs had to come out. Drilling was low-hanging fruit. It wasn’t long before drilling operations were optimized across the major shales. However, savings from drilling fell far short as drilling represents less than half the cost of shale wells. Anxious operators knew they had to go after costs for completions.
Driving out costs in completions proved far more complex than drilling. It was one thing to identify proppant as a major cost factor in completing wells. It was a whole different thing to arrive at solutions. Most oil men will say there is no greater hit on profits than lost production time. Given this, risks were great for operators who contemplated using unproven sand in their wells. Sure, transportation costs were real. But so too is the cost of low production. Therefore, pilots tested the viability of various grades and sources of sand. Ultimately, in-basin sourcing of proppant proved successful.
In time, new business models emerged. Today, direct sourcing is more common among midsize and large independents on efforts to capture margins and squeeze out stranded costs. Direct sourcing demands a certain amount of sophistication, especially when the procurement of goods extends beyond proppant and completions alone. Backward integration appears to be today’s holy grail. Those who successfully link engineering specifications, sourcing and financial administration stand to benefit.
Moving out to the pads, operators have been developing multiwell pads for years. However, early needs to hold acreage led to many pads with one or two wells on them. More recently, operators have been increasingly opting to wring out inefficiencies through zipper fracks. Zipper fracks reduce latent time during completions by leveraging completion equipment across two wells in sequenced fashion. In the world of cost savings on completions, the last man standing really is manpower. Headcounts have been cut dramatically on completion spreads. A few years ago, spreads were manned with 40 or so professionals. Today, fewer than 30 heads on a job is common. Automation and remote monitoring have been contributing factors supporting this effort.
Permian, a resource for the ages
The short-term outlook for the Permian calls for oil production of 4.2 MMbbl/d by the end of the year, up from 3 MMbbl/d at year-end 2017. Production gains were stronger than originally forecast despite infrastructure and labor constraints. The stronger than expected growth was underpinned by a surging rig count. In 2018 the Permian shale rig count averaged about 430 units.
Looking to 2019, a moderating rig count in Permian shale will temper annual production growth and set the stage for even stronger headwinds for growth in 2020. Longer term, Permian production will follow a flatter growth trajectory as the Wolfcamp and Bone Spring mature.
Breakeven economics in the Bone Spring and Wolfcamp remain supportive in spite of expectations of longer laterals and more intense completion designs. Top wells in the Wolfcamp have breakeven prices near $30/bbl West Texas Intermediate (WTI). On the opposite end of the spectrum, bottom performers remain uneconomic at recent prices.
Eagle Ford shows resilience
The Eagle Ford is on track to exit 2018 at 1.4 MMbbl/ d of production, a little more than 100,000 bbl/d of growth versus 2017. Growth was driven by a stable and growing rig count. Looking ahead, 2019 rig counts are expected to climb modestly. In general, the Eagle Ford has entered midlife. Midlife plays are characterized by well-understood resource delineation, ample remaining inventories of undrilled locations and stable operations. The Eagle Ford is forecast to generate relatively stable production into the 2020s. The Eagle Ford generates solid economics and cash flow, which operators use to fund exploration projects both nearby and elsewhere. Portions of the Eagle Ford generate some of the best economics in shale.
Karnes and nearby counties continue to deliver. As the old saying goes, there is no substitute for good rock. Favorable gas-oil ratios and access to infrastructure support ongoing development in this area. Elsewhere in the play, operators have been shifting to extended-length laterals and more intense completions with higher proppant loadings. Extended- length laterals are more common in areas like Atascosa and Frio counties in Texas. The western reaches of the Eagle Ford remain liquids-challenged. Consequently, wells in this area have a greater risk of being uneconomic.
The Bakken found its footing this year as higher crude prices and solid operations bolstered operator confidence. Production this year entered into record territory in recent months. For December, production is expected to reach 1.3 MMbbl/d, up from 1.2 MMbbl/d at year-end 2017. Development has been strongest along the Missouri River, an area with higher gas content. Like the Eagle Ford, the Bakken is maturing further into midlife status.
Rig counts in the Bakken are projected to remain relatively stable and excess cash flow is expected to be deployed to areas like the Powder River Basin, the Midcontinent and other Rockies opportunities. Breakeven prices for the best Bakken wells are well below $40/bbl WTI, and a majority of wells have breakeven prices below $60. These economics, along with ample drilling inventories, will allow the play to attract capital for years to come.
The Rockies appear to be ground zero in the energy-environmental battle being waged. Proposition 112 in Colorado, while defeated, raised the stakes in this battleground area. The recent decision by a judge to once again delay the Keystone Pipeline demonstrates the resiliency of challenges the industry faces in the region. Despite all this, momentum in the Niobrara grew stronger this year. In the Denver-Julesburg (D-J) Basin, oil production is forecast to reach 0.3 MMbbl/d in December, up about 60,000 bbl/d year-on-year. In the Powder River, gains were impressive as several operators made strides on stacked opportunities.
Economically, the region delivers competitive options. Breakeven prices for more than 75% of wells in the D-J Niobrara are below current prices. In the Powder River Niobrara, the same is true for a majority of wells.
The Midcontinent remains largely a story of the Scoop and Stack. December 2018 production in the Scoop and Stack are estimated at 0.1 and 0.3 MMbbl/d, respectively. The leading development in 2018 is the Springer Shale, a subset of the Scoop. Rig counts have been climbing fast, driven largely by Continental Resources. Advertised type curves for the Springer Shale show great promise.
Economically, the Midcontinent has been a mixed bag. Plays like the Scoop and Stack have highly competitive performers. On the other hand, the Granite Wash, Mississippi Lime and the Arkoma Woodford have disappointed.
In general, complicated geology is largely to blame. High levels of natural fracturing combined with more complicated depositions make for serious challenges. The best breakeven prices in the Midcontinent are below $40/bbl for the top wells in the Scoop/Stack.
Appalachia and Haynesville go head to head
As prospects for LNG exports loom on the horizon, look for gas-on-gas competition between the Marcellus and Haynesville. The Marcellus will remain the tour de force in dry gas, while the Haynesville will ply the latest completion designs in an effort to capture share. Insulation from transportation risk and proximity to LNG export terminals are favorable for the Haynesville.
Breakeven prices are below $4/MMBtu, NYMEX for more than 75% of Marcellus wells. Top Haynesville wells have breakeven prices in the mid-$2/ MMBtu range.
Both the Marcellus and Haynesville contend with increasing associated gas volumes from the Permian and other shale oil plays. Economics for associated gas will remain extremely competitive.
Peering through the kaleidoscope
The rebound in drilling from the trough was pronounced and sustained through 2018. The need for U.S. operators to remain competitive through the downcycle in prices led to draconian measures. Fortunately, survivors of this most recent downturn came out stronger. Unfortunately, the easy fixes are in. Drilling and completions are highly optimized, captive capital has been wrung out of business processes and lingering challenges for raising production remain. The key challenges are labor shortages, infrastructure and an intensifying regulatory environment. Therefore, look for activity levels to remain relatively stable in the coming years.
As highlighted in the overview of this issue, industry participants find themselves in the cross-currents of key themes—changing energy mix, shifting energy flows, intensifying regulatory environment and an evolving transportation sector. Of these themes, the first three are set to weigh heavily on the industry in the near term. The mix of energy is in flux.
The success of U.S. shale since the early 2000s has been critical to reshaping energy around the globe. This is true for both crude and natural gas. The U.S. is fully entrenched as an energy powerhouse for both liquids and gas. In liquids, rising production has led to rising exports, which is reshaping global trade flows. Prospects look strong for ongoing growth in liquids production, particularly from the Permian. That said, production growth will come at a slower pace.
Two maturing shale oil plays, the Bakken and Eagle Ford, have more fully transitioned to harvest mode. To be clear, the outlook for these plays remains bright. Established operators in both plays control large portions of the capital deployed to them. A modicum of capital discipline is almost ensured.
In natural gas, the Marcellus will continue to reign supreme in shale gas plays, followed by the Haynesville. Power sector demand and rising LNG exports remain the drivers of growth for gas in the mid- to long-term outlooks.
Looking deeper into 2019, infrastructure will remain a topic. Projects in multiple basins have become entangled in regulatory approval processes within the states impacted. Stratas anticipates most of the entangled projects will get sorted out within the next year. Progress on infrastructure in the Permian and Appalachia is expected to positively affect flows in late-2019. Elsewhere, transportation is less of an issue.
Spending on the upswing
While operators have learned to embrace their newfound passion for living largely within cash flow, capital spending will remain on an upward sloping path as the Permian powers overall higher spending in the U.S., driven in part by more complex and bigger wells. The estimates in the capex chart are based on current technology and cost escalations based on recent observations. Additional cost pressures could arise in select industry segments (i.e., labor and trucking) as constrained resources get bid up.
Good thing for the industry that this comes when commodity prices also are projected to trend higher. To be sure, regardless of the price environment, energy investors are likely to insist on transparent, returns-based exploration and development programs. The days of drilling for growths sake are over, at least for now.
It’s too soon to gauge the price impact on fuel or the data impact to Colonial Pipeline after a cyberattack forced its systems offline, experts say.
Oil prices are expected this week to drift sideways with an upward bias, while product prices in the Atlantic Basin will move upward until the Colonial Pipeline is back in service, says Stratas Advisors in its latest forecast.
Nearly half of the fuel consumed in the eastern U.S. passes through the Colonial network.