As oil prices reach a four-year high with Brent Crude at $78 a barrel and West Texas Intermediate (WTI) at $70 a barrel at the time of writing, it’s clear that we are entering a new phase in the oil and gas industry.
Furthermore, the fact that OPEC’s supply cuts have remained in place, the free fall in Venezuelan production, and the new sanctions to be reinstated against Iran – alongside strong global consumption forecasts – mean that the holy grail of $100 a barrel is no longer out of reach.
What does this new oil price boom mean for the North American shale industry and what trends should we look out for during the coming months?
A Regional Shake-Up
One result of the increasing oil prices is a regional shake-up of activity hot spots.
Over the last few years, the Permian has been the spearhead for drilling and production activity with the key attraction being its’ position as one of the least expensive places in the U.S. to produce – due to existing infrastructure and oil-bearing rocks that allow better yields per acre – as a recent Wall Street Journal article points out.
Yet, the rise in oil prices is bringing increased attention to other players in regions, such as Colorado, North Dakota and Oklahoma, where there are better pipeline infrastructures and lower costs per acre due to less competition.
According to Baker Hughes, in the same Wall Street Journal article, the number of oil rigs in several basins outside the Permian, including North Dakota’s Bakken region, the Eagle Ford in South Texas and the Cana Woodford in Oklahoma, has more than doubled over the last few years. This has led to operators, such as Continental Resources who favored the Bakken and Oklahoma over the Permian, posting production increases of as much as 48 percent in the first quarter.
With this regional shake-up and transfer of resources and drilling capital, it’s more important than ever for operators with multiple basins to have immediate and accurate access to regional data intelligence on leases; drilling, completion and production metrics; competitor information and other variables, as Drillinginfo provides.
In regard to specific regions, Drillinginfo also provides Oklahoma Spacing and Density – the only proprietary, fully-interpreted dataset of all current and historical spacing units in Oklahoma that allows operators to find open acreage faster, monitor competitor activity and identify hidden opportunities.
Increased Production and Self-Financing
Another impact of rising oil prices is a continued increase in production and more U.S. shale companies are now raising enough cash to cover the costs of drilling new wells.
The last few years have seen a significant drop in breakeven prices for shale producers – as much as a 45 percent reduction on the Permian according to industry analysts, Rystad Energy – leading to significant cash returns as operators look to increase production and rigs. The Drillinginfo daily rig count sat at 1105 as of May 13. That’s up 25 from two weeks previous and likely to keep in rising.
Several operators, such as Anadarko Petroleum, Devon Energy and Hess, have recently announced increased dividends or share buybacks and Continental Resources is prioritizing debt repayments – closing in on its goal of net debt below $6 billion.
This is all part of a new returns-based environment, where the key metrics and good business practices of cost containment, cash generation and returns on capital are over riding the ‘growth at all costs’ and need for continued outside investment approach.
A Focus on Efficiencies and Profitable Growth
Can this returns-based approach be sustained as oil prices remain on an upward trajectory?
The signs are good. At Drillinginfo, we are working with E&P operators who are dedicated to maximizing efficiencies and ROI in their operations. This includes identifying the most profitable leases, monitoring the competition, ensuring optimal well spacing and conducting in-depth analyses of best drilling and completion practices.
While shale production remains on the increase, the Energy Information Administration (EIA) predicts that shale oil production will rise by a record-breaking 144,000 barrels per day from May to June this year, but rig counts are not increasing in the same numbers which has operators ‘doing more with less.’
According to a recent Bloomberg article, current rig counts are less than half of what they were before the price crash in 2014. Analysts at Enercom estimate that modern rigs are delivering 3.15 times more production than those in January 2014.
It’s clear, however, that high oil prices will lead to more production with a cluster of smaller operators leading the way.
In the past six months, companies that aren’t among the top U.S. crude producers made up 42 percent of permits approved for new drilling, according to Drillinginfo in another Wall Street Journal article. Many of these operators have ambitious growth plans.
Ongoing Infrastructure Concerns
One potential constraint to such growth plans and production increases are bottlenecks in pipelines and other infrastructure to take the shale oil and gas to market.
As Drillinginfo discussed in a previous blog, such pipeline constraints are having an impact on both prices and supply. Spot crude from Midland, Texas in the heart of the Permian, for example, has been trading this week at almost $16 a barrel below the grade of oil in Houston – only 500 miles away – due to infrastructure issues. In such cases, it’s vital to get a complete overview of shale activities and midstream infrastructure in specific regions, as Drillinginfo provides.
As oil prices increase, however, so will the pressure to increase infrastructure and pipeline capacity as well as financial investment mechanisms for midstream projects, A number of significant midstream investments in the Permian are due to come online in the near future.
The continued rise in oil prices is good news for shale producers across the U.S., as they look to maximize the opportunities these prices bring. Furthermore, with U.S. and global demand remaining strong and declining global inventories, prices are likely to remain high over the coming months.
Against this backdrop, it’s more important than ever to access the latest decision-making intelligence for better and faster results, and increased profitability. That’s why operators choose Drillinginfo.
Increased gasoline prices have caught the attention of the public. Prices have increased steadily over the last couple of years and the March price average so far sits at $2.69/gal, a whole $0.25/gal higher than this time last year (Fig. 1). As driving season begins, the $0.25/gal will begin to strain consumers’ budgets. What are the reasons behind the higher prices?
Figure 1 – US Retail Gasoline Prices (All Grades), Source: EIA
What is going on right now?
Gasoline prices have spiked this week, bewildering consumers. As big oil conspiracy theories continue to make their way around the grapevine, we explore the main drivers behind the rise in gasoline price.
Two main (and fairly simple) reasons underlie the rise in gasoline prices.
Changing Gasoline Specifications
Gasoline has two main performance specifications (among a host of others that are there for performance, safety, & environmental concerns): Octane & Reid Vapor Pressure (RVP). The octane content is the one everyone is used to seeing posted at the pump (premium 91, regular 87, etc.). The octane number captures the anti-knock properties of gasoline. The higher the octane number, the more valuable the gasoline. However, the RVP is not posted. The reason for this is the fact that the RVP specification changes every season with the weather. The RVP changes to regulate the volatility and the emissions from the combustion of the gasoline in the engine. In the summer months, the RVP specification is lower (harder to attain), meaning that the blend of intermediate refined products used in the mix are more restrictive and require higher value parts of the feedstock. Refineries have started to make the more expensive summer specification gasoline in preparation for driving season, meaning that the market for winter grade gasoline has become tighter. As weather has continued to warm up recently, demand has reached a March high according to the latest EIA Weekly Petroleum Status Report.
Rising Crude Oil Prices
The most marked reason behind the rise in gasoline prices is the price of the feedstock, crude oil. Crude oil prices have been trending higher on speculation that the oversupply that caused the price crash and led to an extended period of low prices has been reversed and inventories are being drawn down (Fig. 2). The $0.25/gal increase in gasoline prices since last year equates to an increase of 10%. That increase should come as no surprise, since the main feedstock for gasoline has actually increased 20% in the same time frame.
Figure 2 – WTI Spot Prices, Source: EIA
So What Next?
Gasoline prices are likely to climb higher in the coming months, due to the implications of the two factors highlighted above. Rising crude oil prices have already had an impact on the price of gasoline, but most refineries buy the crude oil they refine at least a month in advance, meaning that there is likely going to be higher feedstock prices for the incoming barrels that were bought more recently. The changing gasoline specification not only means that there is relative tightness in the short-term for winter specification gasoline available in storage, but that the higher priced summer specification gasoline will be hitting the market in June (also made from high cost feedstock). Driving season will also boost demand during this time frame as families hit the road for the summer. The combination of these factors means that gasoline prices will at least stay high, and likely go higher, barring another dip in crude oil prices. To track the progression of crude oil prices, follow our blog (https://info.drillinginfo.com/di-blog/) as we continue to track the speculatively induced crude oil price bubble and wait for fundamental realities to set in.
The Northeast region has traditionally been a demand market for gas produced in the SE/Gulf, Midcontinent, and Canada. But, this changed when the Marcellus and Utica formations were discovered and then developed.
Over the past 10 years, natural gas production in the Marcellus and Utica basins has risen sharply — from about 2 Bcf/d in 2008 to more than 26 Bcf/d as of February 2018 — and now represents about 33 percent of total U.S. dry gas production. While other basins also experienced growth during the same time period, the rates were much lower: Eagle Ford at 3.3 Bcf/d, Permian at 3.2 Bcf/d, and Anadarko at just 1.2 Bcf/d. The graph below shows historical dry gas production by region since 2010 and forecast through 2018.
U.S. Dry Gas Production by Region
This massive growth has created a lot of challenges to producers in the Northeast, the most significant being bottlenecked pipeline takeaway capacity. This became a real challenge in 2013, when production levels reached capacity limits.
Because of this, as shown below, pricing dropped in the region: trading at a premium (basis higher than Henry Hub) plummeted to trading at a discount (below Henry Hub), with basis as low as $2/MMBtu below Henry Hub.
Key Northeast Natural Gas Pricing Hubs
Pipeline infrastructure operators have responded to this new dynamic by changing flow direction in existing pipelines and expanding capacity through looping and compression as well as by installing new (greenfield) pipeline capacity. But so far, capacity additions haven’t kept up with production growth, and price basis has remained depressed. In fact, from 2013 through 2017, producers have filled up all capacity additions as soon as they became available.
Northeast Dry Gas Production and Takeaway Capacity
However, there’s good news ahead. As shown in the chart above, Drillinginfo expects pipeline capacity constraints to end in 2018, when key takeaway projects will come online and add over 5.0 Bcf/d of additional Northeast takeaway capacity. Energy Transfer Rover Phase 2, Transco’s Atlantic Sunrise, Nexus Gas Transmission, and Columbia’s Gulf Xpress projects will, in effect, debottleneck the region during the third quarter. Regional gas basis is therefore expected to trade within variable transport costs of about $0.20–$0.30 per MMBtu below Henry Hub.
Once the capacity constraint is lifted, production economics — the difference between market prices and breakeven prices — will start to dictate growth in the Northeast going forward. Based on Drillinginfo’s pricing expectations of Henry trading somewhere between $2.65 and $2.75 MMBtu over the next five years, by 2021, production will reach almost 30 Bcf/d, an increase of more than 5.0 Bcf/d from current levels.
Henry Hub at 3 and change, my prospect econ’s now in range!
Forgive the drivel but we, like you, are really excited about the near- and long-term future of the ‘patch’. The improvements in pricing have affected operations in EVERY basin, providing good to excellent margin support for deals and prospects far and wide.
Whether it’s someone trying play mid-Devonian carbonate reefal analogs out of the Alberta, Canada’s Golden Spike field (39,718,044 BBO, 37+ BCF–one well!!)
Drillinginfo Web app- Golden Spike field, Alberta,Canada—bubbled by cumulative oil
DI Web App-Mid Devonian Paleo-environment layer tied to Golden Spike field
DI Desktop-Well historical production, Golden Spike field
or someone else who’s gotten a farm-out in Eagleford country and wants to chase stray Wilcox of the kind that Pioneer found at Sinor West , Live Oak county
DI Webapp-Historical Production-#5 Sinor Ranch A, Live Oak Co, TX, L.Wilcox sand ,TD 8286’
there’s a lot of creative geology just waiting to be tested….probably with YOUR money.
So sign up for our Deal Desk at NAPE and check out the context of the hot deal that you’ve just seen—review type curves, water cuts, cum water, drilling activity, leasing opportunities…or walk through evaluation workflows on operators like Bonanza in the DJ Basin or Alta Mesa Holdings in the STACK.
If you wish to meet with our executive team to learn how to leverage DI’s enterprise value for your organization, sign up here.
We’re looking forward to meeting you at NAPE!!
Natural gas storage inventories decreased by 69 Bcf for the week ended Dec. 8, per EIA. The report was bearish and extended the losses in natural gas prices following the EIA release. The Jan18 futures contract is down $0.05 to $2.67 per MMBtu, at time of writing.
Weather forecast uncertainties continue to put downward pressure on prices this week and have now added to a total ~$0.65 per MMBtu drop in gas prices in the past four weeks.
Working gas storage inventories dropped to 3.626 Tcf, level 201 Bcf below last year 36 Bcf below the 5-year average.
See chart below for projections of end-of-season storage inventories as of April 1, the end of the withdrawal season.
This Week In Fundamentals
The summary below is based on PointLogic’s flow data and DI analysis for the week ending 12/14.
- Supply: dry gas production is up 150 MMcf/d recovering some of the losses from last week. Canadian imports are up 660 MMcf/d.
- Demand: cold temperatures push demand higher again this week, up 13.7 Bcf/d with total demand reaching a 3-digit average (106 Bcf/d) for the first time this winter. All sectors reported weekly gains led by res/com which increased by 12.2 Bcf/d
- Total supply is up 880 MMcf/d to 82.4 Bcf/d. Total demand increased 13.7 Bcf/d to 106.4 Bcf/d. Market is significantly shorter this week, therefore expect the first 100+ Bcf draw in next week’s storage report.
Natural gas storage inventories increased by 2 Bcf for the week ended Dec. 2, per EIA. An injection in the middle of the winter caused gas futures prices to plummet following the EIA release. The Jan18 futures contract is down $0.13 to $2.79 per MMBtu, at time of writing.
In addition to today’s bearish storage report, uncertainty in weather forecasts continues to put downward pressure on prices. Following the cold front currently covering most of the US, weather expectations are calling for a return to more normal and even mild temperatures. The lack of demand while production has increased by almost 2 Bcf/d over the past month will continue to put a lid in gas price gains in the short term.
Working gas storage inventories increased to 3.695 Tcf, level 264 Bcf below last year and below the 5-year average by 36 Bcf.
See chart below for projections of end-of-season storage inventories as of April 1, the end of the withdrawal season.
This Week In Fundamentals
The summary below is based on PointLogic’s flow data and DI analysis for the week ending 12/07.
- Supply: dry gas production is down 0.5 Bcf/d week-on-week with losses shared in the Northeast, Texas and Gulf of Mexico. Lower production was offset by Canadian imports, which increased this week by 380 MMcf/d.
- Demand: winter like temperatures push demand higher this week including a jump in residential/commercial due to heating demand, up 5.6 Bcf/d week-on-week. Power demand increased by 2.2 Bcf/d, while industrial was basically flat. LNG and Mexico exports were down 0.08 Bcf/d and 0.31 Bcf/d week-on-week, respectively.
- Total supply is down slightly only by 100 MMcf/d to 81.8 Bcf/d. Total demand increased 8.2 Bcf/d to 89.5 Bcf/d. Market is significantly shorter this week, therefore expect withdrawals to come back in next week’s storage report.