Two months ago, the Federal Energy Regulatory Commission shook up master limited partnerships (MLPs) and their investors by deciding that income taxes would no longer be factored into the cost-based tariff rates of MLP-owned pipelines. We said then that there was no need to panic — that all this will take time to play out, and that the end results may not be as widespread or dire as some feared. Today, we provide an update, dig into FERC’s other actions on changes in income taxes, and discuss the phenomenon known as “FERC Time.”
The new, larger locks along the Panama Canal have been in operation for almost two years now, enabling the passage of larger vessels between the Atlantic and the Pacific. The timing couldn’t have been better — when the expanded canal locks came online in June 2016, exports of U.S. LPG, crude oil, gasoline and diesel were about to take off, and Cheniere Energy had only recently started shipping out LNG from its Sabine Pass export terminal in Louisiana, with Asian markets in its sights. Hydrocarbon-related transits through the canal soared through the second half of 2016, in 2017 and so far in 2018. But the gains are mostly tied to LPG and LNG — even the expanded canal isn’t big enough for the Very Large Crude Carriers (VLCCs) favored for Gulf Coast-to-Asia crude shipments, or for fully laden Suezmax-class vessels. And there already are indications that the canal’s capacity may not be sufficient to meet future LNG needs. Today, we consider the expanded canal’s current and future role in facilitating U.S. hydrocarbon exports.
U.S. crude oil exports have averaged a staggering 1.6 MMb/d so far in 2018, up from 1.1 MMb/d in 2017, and the vast majority of these export volumes — 85% in 2017 — have been shipped out of Texas ports, with Louisiana a distant runner-up. The Pelican State has a number of positive attributes for crude exporting, though, including the Louisiana Offshore Oil Port (LOOP), the only port in the Lower 48 that can fully load the 2-MMbbl Very Large Crude Carriers (VLCCs) that many international shippers favor. It also has mammoth crude storage, blending and distribution hubs at Clovelly (near the coast and connected to LOOP) and St. James (up the Mississippi). In addition, St. James is the trading center for benchmark Light Louisiana Sweet (LLS), a desirable blend for refiners. The catch is that almost all of the existing pipelines at Clovelly flow inland — away from LOOP — many of them north to St. James. That means infrastructure development is needed to reverse these flows southbound from St. James before LOOP can really take off as an export center. Today, we consider Louisiana's changing focus toward the crude export market and the future of regional benchmark LLS.
Natural gas production in the Permian has increased by about 1 Bcf/d since last November to about 8 Bcf/d today. That incremental gas production has used up virtually all of the remaining interstate and intrastate pipeline capacity out of the region, including the all-important pipes that move gas to the Houston area and East Texas. There’s considerable takeaway capacity still available on pipes from the Waha Hub to the Mexican border, but they can’t fill up until connecting pipelines and new gas-fired power plants are completed within Mexico. Permian supply is coming on faster than takeaway pipelines and demand can’t handle it. Something’s got to give. But what? Today, we continue a series on Permian gas with a look at the effects of Permian and Gulf Coast gas supply growth on Texas gas flows and pricing.
After years in the doldrums, ethane prices are increasing, not so much in absolute terms, but where it counts — relative to the price of natural gas. That means less ethane will be rejected — sold as natural gas — and more will be recovered as liquid ethane and sold as a petrochemical plant feedstock. As still more new ethane-only petrochemical plants come online over the next couple of years, ethane demand will increase, boosting ethane prices and resulting in still less ethane rejection. Does that mean ethane rejection will be a thing of the past? No, not even close. U.S. natural gas production, especially gas with a high ethane content, is growing so fast that ethane supply will continue to outstrip demand for the foreseeable future, with important consequences for ethane prices. Today, we continue our review of NGL market developments.
It’s no surprise that the plunge in crude oil prices between mid-2014 and early 2016 was a five-alarm wake-up call for the 44 exploration and production companies we follow. To deal with the trauma of the crude price collapse — and generally soft natural gas prices to boot — the industry undertook a dramatic strategic and operational transformation that enabled it to climb out of a huge hole and return to profitability in 2017. Key factors driving this impressive turnaround included the high-grading of portfolios, intense capital discipline and a heightened focus on operational efficiencies. However, the trajectory of recovery has varied from company to company because of the pace of their portfolio transformations, their geographic focus and, most significantly, the commodity mix of their production. Today, we look at how specific E&Ps within our three peer groups — Oil-Weighted, Diversified, and Gas-Weighted — have been working their way back to black.
The basis blowout at the Waha Hub in the Permian Basin arrived in full force over the last few weeks, with natural gas prices reaching discounts to the Henry Hub not witnessed since 2009. Available takeaway capacity has been quickly eroding on the existing pipeline corridors out of the basin, leaving many in the market pondering where all the incremental gas production will go before a new greenfield expansion pipe relieves the market in late 2019. Last week, a partial answer came in the form of a pipeline expansion project by Enterprise Products Partners and Energy Transfer Partners slated for completion later this year. While the project’s estimated size is far too small to preclude additional greenfield pipelines beyond 2019, it does highlight the attractive economics of brownfield expansions on the Texas intrastate pipelines at Waha. Today, we analyze announced and possible intrastate pipeline projects around Waha.
Even with crude oil prices down $1.67/bbl yesterday, the wide differential between Permian prices and those in destination markets held up, with WTI Midland trading at $15.60/bbl below the same quality of oil on the Gulf Coast. This has become a red-hot topic for all Permian-watchers. For example, in first quarter earnings calls, a number of producers not only reported their Permian well productivity and drilling plans, they also reviewed how much firm pipeline space they have signed up for in the Permian and how they plan (or hope) to avoid negative financial consequences from the differential blowout. With so much demand for new pipeline space, shouldn’t it be easy to get a bunch of shippers signed up for long-term commitments to fund a new project? Today, we’ll look at what it takes for commitments to pay off massive pipeline projects, the hurdles midstream companies go through to achieve it, and the possibility of new pipeline projects getting added to the development schedule.
Shipowners and refiners are struggling with how to prepare for January 1, 2020, when all vessels involved in international trade will be required to meet significantly stricter limits on emissions of sulfur oxides (SOx), either by using fuel with a sulfur content of less than 0.5% or by “scrubbing” the exhaust of ship engines when using the much higher-sulfur bunker fuel that most ships now rely on. The International Maritime Organization’s (IMO) new sulfur rule isn’t a minor tweak. It’s a game changer that already is causing widening spreads on the futures market between 3.5%-sulfur heavy fuel oil (HFO) — the traditional global bunker fuel — and rule-compliant low-sulfur distillates. The rule also promises to be a boon to complex Gulf Coast and other refineries that can break down residual-based HFO into higher-value, lower-sulfur distillates. Today, we begin a new series on how shipowners, refiners and the markets for HFO and low-sulfur marine fuel are responding (or not) to the coming change in global bunker requirements.
Production of crude oil and associated gas in the Permian continues to rise, despite pipeline takeaway constraints that have widened crude spreads and depressed natural gas prices at the Waha Hub. But while oil can be — and is being — transported by trucks and railroads when crude pipelines are full, natural gas needs to be either piped away or flared, and Permian gas production is now approaching the effective maximum takeaway capacity out of the basin. While a slew of new projects have been announced to relieve the Permian gas takeaway problem, the new capacity won’t arrive soon enough to keep Permian production from hitting the takeaway-capacity wall sometime in 2019. Today, we begin begins a series examining Permian production trends and their implications for pipeline flows and pricing in Texas.
The plunge in crude oil prices that started in mid-2014 had a major and lasting impact on the 44 exploration and production companies (E&Ps) we’ve been tracking, triggering a $188 billion swing in net results — from $57 billion in pre-tax operating profits in 2014 to $131 billion in losses in 2015. Defying predictions of widespread bankruptcies, the industry undertook a dramatic strategic and operational transformation that enabled it to emerge from the abyss and return to profitability — albeit just barely — in 2017. Key factors in the industry’s impressive turnaround include the high-grading of portfolios, intense capital discipline and a laser-like focus on operational efficiencies. Today, we dive into the 2017 financial reporting of these companies to identify how these changes have affected income statements and set up the industry for future profitability growth.
The U.S. gas market in April — the first month of the official storage injection season — was anything but typical. Production was at record highs, nearly 8.0 Bcf/d higher than last year. At the same time, weather in April was exceptionally cold, which meant storage activity remained in withdrawal mode on a net U.S. basis through the first three weeks of the month — a first for the April gas market going back at least eight years. That anomaly, in turn, led to an expanding deficit in storage compared to previous years, deferring the inevitable — shoulder season weather and supply surpluses — for another month. But now, in May, with the cold-weather effects on gas demand fading and record production levels here to stay, the market is bracing for a storage tsunami. The question is, will it be enough to erase the massive inventory deficit compared to recent years? Today, we update our analysis of the gas market balance and implications for the 2018 injection season.
For a month now, the number of active drilling rigs in the U.S. has topped 1,000, the first time that’s happened since the spring of 2015, when the rig count was in the midst of a frightening tailspin — it fell from more than 1,900 in November 2014 to only 400 in May 2016. What a long, strange trip it’s been, not just for the rig-count total but for gains producers have seen in drilling productivity and in crude oil and natural gas production per well. Exploration and production companies are doing far more with less, trimming costs and increasing returns in the Permian, the Marcellus/Utica and other key production basins to levels few would have thought possible a few years ago. Today, we review the key changes we’ve seen in drilling productivity, and what they mean for U.S. E&Ps and midstream companies and the rig count going forward.
For years, the U.S. Midwest has been a perennial net exporter of natural gas to Eastern Canada. But with Marcellus/Utica and Canadian gas supplies barraging the region, that’s changing. Less Midwest gas is flowing across the border into Ontario. At the same time, Canadian gas supply that used to serve U.S. Northeast demand is being displaced to the Midwest. That’s on top of Marcellus/Utica gas that’s physically moving to the Midwest via new capacity on the Rockies Express and Rover pipelines. The result is that the Midwest’s net exports to Canada are declining and even flipping into net imports during some summer months when the market is in storage injection mode. Thus far, this reshuffling of supply has occurred at the expense of Gulf and Midcontinent gas that historically has served the Midwest. But now there’s little of that left to displace from the Midwest, even as still more supply is expected to move there. Canadian producers are banking on capturing more of the Midwest market, as are Northeast producers via expansions like Rover’s Phase II and NEXUS. In other words, there’s a fierce battle brewing for Midwest market share. Today, we look at flow dynamics and factors affecting Canadian gas flows to the U.S. Midwest.
Seems like just about everything to do with energy markets is up these days. Crude oil prices are back to the levels of late 2014. Crude production hit a 10.6 MMb/d record volume last week, while lower-48 natural gas has been bouncing around an 80 Bcf/d record level. Exports of crude, gas and NGLs are at all-time highs. But all those hydrocarbon molecules must find their way from the wellhead to market, and in several high-growth regions, that is becoming increasingly problematic, as midstream infrastructure struggles to keep up. In our recent School of Energy, we examined these developments, considering their impact on production trends, domestic demand and the outlook for growth in export volumes. Did you miss it? Not a problem. We taped the whole conference, and School of Energy Online is now available in 12 hours of streaming video, along with all the Excel models, slides, and graphics that we use to tie energy markets together. Today, in this unabashed advertorial, we review some of the highlights of the conference.