While the recently enacted federal tax cuts have been widely viewed as a boon to corporate America, including businesses in the energy sector, a new report by our friends at East Daley Capital finds a major drawback in the law for midstream companies. By slashing the corporate tax rate from 35% to 21% — and by allowing partnerships and “pass-through” entities to take a 20% deduction on their income pre-tax — the new law will increase the return on equity that midstreamers earn on their crude oil, NGL and natural gas pipelines. That may well lead the Federal Energy Regulatory Commission (FERC) to re-set its formula rates for at least some gas pipelines, and also is likely to heighten regulatory scrutiny of the rates charged by the owners of oil and NGL pipelines. Today, we continue our review of East Daley’s new “Dirty Little Secrets” report with a look at the tax law, the higher pipeline ROEs resulting from the tax cuts, and the midstream companies that may be affected most.
Daily energy Posts
Crude oil production in the Western Canadian Sedimentary Basin (WCSB) has risen by more than 50% over the past seven years to about 4 MMb/d, driven by new projects and expansions in the oil sands of Alberta. And while growth has slowed since the 2014-15 downturn in crude oil prices, oil sands output is expected to continue climbing — particularly over the next year as the new, 194-Mb/d Fort Hills project ramps up toward full operation. Most forecasts put total WCSB production at near 5 MMb/d by the mid-2020s. But while Western Canadian crude oil supply has been rising, there has been only a modest expansion of pipeline capacity out of the region, and lately takeaway constraints have had a devastating effect on the price relationship between benchmark Western Canadian Select (WCS) and West Texas Intermediate (WTI). Today, we continue our series on Canadian crude and bitumen production, existing and planned pipelines, and the effects of takeaway constraints on pricing, this time focusing on the supply side of the story.
Canadian natural gas production has rebounded to the highest level in 10 years. At the same time, Canadian producers are facing tremendous headwinds. On the upside, regional gas demand from the Alberta oil sands is increasing too. But competition for market share in the U.S. — which currently takes about one-third of Canadian gas production — is ever-intensifying as U.S. shale gas production is itself at record highs and expected to continue growing. On the whole, net gas flows to the U.S. from Canada thus far have remained relatively steady in recent years, apart from fluctuations due to weather-driven demand. But the breakdown of those flows by U.S. region has shifted dramatically and will continue to evolve as Appalachia takeaway capacity additions allow Marcellus/Utica shale gas production to further expand market share in the Northeast and other U.S. regions. Today, we begin a series looking at what’s happening with gas flows across the U.S.-Canadian border and factors that will influence Canada’s share of the U.S. gas market over the next several years.
The opening of Mexico’s refined-products sector to competition after 80 years of Pemex monopoly is spurring the development of new motor fuel-related distribution infrastructure on both sides of the U.S.-Mexico border. A number of these pipelines, rail loading/unloading facilities, storage and other projects aren’t advancing as quickly as their developers may have hoped — replacing the old order with the new is taking time. But the need for new infrastructure is evident. Today, we continue our series on efforts to facilitate the transportation of motor fuels from U.S. refineries to — and within — Mexico, this time focusing on rail-related projects.
The U.S. exploration and production (E&P) sector roared out of the starting gate in 2017 with a new optimism that fueled a more than 40% surge in capital investment. First-quarter results were strong, but an ebb in oil prices and some operational headwinds significantly lowered results in subsequent quarters. When final 2017 results are tallied in the next few weeks, the industry is on track to record its first profitable year since 2013 after posting more than $160 billion in losses in the 2014-16 period. The critical question is whether E&Ps are regaining the momentum that could drive a steady increase in profitability in 2018. Today, we analyze the clues contained in third-quarter 2017 results.
Natural gas production from the Permian Basin is expected to grow considerably over the next several years, taxing existing takeaway capacity. Nearly 8.0 Bcf/d of takeaway capacity expansions are proposed to help address impending transportation constraints from the region. When will new pipeline capacity be needed and will it be built in time to avert constraints? In today’s blog, we assess the timing of potential constraints based on production growth, existing takeaway capacity and potential future capacity additions.
There has been growing concern regarding NGL pipeline takeaway capacity out of the Williston Basin and the Niobrara — particularly the DJ Basin — over the past year, with one of the major pipes through those regions now running full. Finally, ONEOK has announced plans for the Elk Creek Pipeline, which will have an initial capacity of 240 Mb/d and be expandable to 400 Mb/d. The new pipe will transport mixed, unfractionated NGLs from eastern Montana to the Conway/Bushton fractionation hub in central Kansas, and provide long-term relief for a lot of Bakken, Powder River and Denver-Julesburg (DJ) Basin producers. But with an end-of-2019 in-service date, will the new capacity come soon enough to avert NGL takeaway constraints? Today, we discuss the Elk Creek project, the flows on existing NGL pipes to Conway/Bushton, and the growing significance of ethane as pipelines fill.
The recent collapse in the price of Western Canadian Select (WCS) versus West Texas Intermediate (WTI) and the 12-day shutdown of the Keystone Pipeline in November 2017 put the spotlight on a major issue: Alberta production is rising, pipeline takeaway capacity out of the province has not kept pace, and pipes are running so full that some owners have been forced to apportion access to them. Storage and crude-by-rail shipments have served as a cushion of sorts, absorbing shocks like the Keystone outage and the apportionments, but with more production gains expected in 2018-19, that cushion seems uncomfortably thin and unforgiving. With all this going on, we decided that it’s time for a deep-dive look at Western Canadian production, takeaway options and WCS prices — the whole kit and caboodle. Today, we begin a new series on Canadian crude and bitumen production, the infrastructure in place (and being planned) to deal with it, and the effects of takeaway constraints on pricing.
After six years of output declines, Haynesville Shale natural gas production surged 25% in 2017, with the lion’s share of the increase coming in a remarkable second-half growth spurt. Preliminary 2018 guidance indicates that producers intend to keep the pedal to the metal, either sustaining or boosting the investment that has brought the play’s output to nearly 8 Bcf/d. Such increased activity indicates that producers have found new advantages in the region. But even though new drilling and completion techniques and producer strategies have significantly enhanced the economic viability of the dry gas Haynesville, it is much more highly dependent on natural gas prices than liquids-rich plays. Today, we continue our series on the rebounding Haynesville play with a look at RBN’s production forecast for the region.
Discussions about “peak oil” long ago shifted from when crude oil supply might reach its apex to when oil demand will peak and start to decline as the world becomes ever more energy-efficient and shifts to lower-carbon sources of energy. The date at which oil demand will stop growing is highly uncertain, and small changes in assumptions can lead to vastly different estimates. Also, there is little reason to believe that once oil demand peaks it will fall sharply — the world is likely to demand large quantities of oil for many decades to come. More importantly, the shift in paradigm from an age of perceived oil scarcity to an age of oil abundance poses major challenges for oil-producing countries as they try both to ensure that their oil is produced and consumed, and at the same time diversify their economies to prepare for a time when they can no longer rely on oil to provide their main source of revenue. Today, the Oxford Institute for Energy Studies and BP Group Chief Economist Spencer Dale summarize their recent report on future trends in oil supply, demand and prices.
Prices for heavy NGLs (propane, butanes, natural gasoline) have been rising fast since the middle of 2017, but the same cannot be said for the price of ethane. For most natural gas processors/producers, low ethane prices mean that ethane continues to be worth more when sold with natural gas (rejected) than when it is extracted and sold with the other liquids. But as NGL production continues to grow, hitting a record-high 3,968 Mb/d in October 2017, and new steam crackers are just starting to come online, there is a limit to how much ethane can be left in the residue gas stream without violating dry gas pipeline Btu specifications. How do processing plant designs, gas pipeline specs and economics play into a gas processor’s decision regarding whether to extract or reject ethane? Today, we continue our discussion of RBN’s MQQV gas processing model — this time focusing on the Quantity and Quality principles.
Refiners in the five Rocky Mountain states that make up the U.S. Energy Information Administration’s Petroleum Administration for Defense District 4 — or PADD 4 — enjoy higher margins than their counterparts in every other part of the country except California. Quarterly crack spreads for domestic crude in PADD 4 averaged $25/bbl between 2014 and 2017, while those for Canadian crude averaged $31/bbl. Today, we explain that these lofty cracks reflect an abundance of crude — both from indigenous Rockies production and Canadian and North Dakota supplies passing through the region — as well as higher-than-average diesel and gasoline prices.
Energy Transfer Partners’ 3.25-Bcf/d Rover Pipeline recently began service on its next phase — Phase 1B — opening up additional natural gas receipt points for its Mainline A and increasing westbound gas flows from the Marcellus/Utica. The project will help relieve takeaway constraints for growing gas supply in the Marcellus/Utica region, while also increasing gas-on-gas competition for supply basins targeting the Ontario and Gulf Coast markets. This latest launch brings the project closer to achieving full completion, which is expected by the end of March 2018, but volumes on Rover are already changing regional flow and pricing dynamics. Today, we provide an update on Rover’s progress.
A number of Permian producers and their contractors are working to rein in well-completion and operating costs by developing extensive pipeline networks to efficiently deliver fresh, brackish or treated water to new wells for use in hydraulic fracturing — and deliver produced water from producing wells to treatment and disposals sites. This water-related infrastructure build-out is driven by a combination of necessity and economy, and is made possible in part by the trend among producers to assemble very large, contiguous leaseholds so they can drill longer horizontal wells. Today, we continue our series on water-related pipeline, storage and treatment infrastructure.
During the oil market’s downturn from mid-2014 through 2016, the Bakken Shale, primarily located in North Dakota, was at the forefront of the collapse. The Bakken rig count dropped from a high of 219 to a low of 24 as production fell by 300 Mb/d, or 24%. For many, it was time to write off the Bakken as a one-hit wonder. But as drilling productivity increased and prices rebounded, so did production. Crude oil output is again above 1.1 MMb/d and the rig count has doubled from its low point. Today, we begin a blog series on recent developments in Bakken production, well productivity and market pricing, and discuss RBN’s latest production forecast for the play.
The U.S. midstream sector is clamoring to build takeaway pipelines for ballooning natural gas production volumes in the Permian Basin and get ahead of any developing takeaway capacity constraints. In the past year, a number of companies have floated plans for moving Permian gas supply east to the Gulf Coast, spurred on by two primary factors — expectations for accelerated supply growth in West Texas; and on the other end, emerging demand from a combination of LNG export facilities being developed on the Texas and Louisiana coasts, and the slew of export pipeline projects targeting growing industrial and gas-fired power generation demand in Mexico. These expansion projects are in a bit of a horse race, not just to beat the clock on potential transportation constraints, but also competing against an increasingly larger field to secure shipper commitments and make it to completion. Among the factors affecting their progress will be their in-service dates and their destination markets. Today, we provide an update on these competing pipeline projects, including the newest entrant, Tellurian’s Permian Global Access Pipeline.