Florida’s electric utilities are turning to natural gas-fired power and renewables for all their incremental generation needs and as replacements for the older coal units they’ve been retiring. The state’s big bet on natural gas has been spurring the development of new pipelines. And, because of big shifts in where gas is being produced and where it’s flowing, the Sunshine State will soon be receiving an increasing share of its gas needs from the Marcellus region. Today, we discuss the slew of new gas-fired power plants that have come online, the additional plants planned, and gas flows on Sabal Trail, the first new gas mainline into the state in almost two decades.
U.S. LNG exports have climbed from zero three years ago to more than 3 Bcf/d now, and export capacity is set to grow to more than 10 Bcf/d by 2023. With the U.S. emerging as a dominant player in the global LNG landscape, international players are now increasingly susceptible to the day-to-day fluctuations of the U.S. natural gas market — a highly liquid, fungible and interconnected arena that’s propelled by constantly shifting transportation economics. The global LNG market inevitably is also moving toward spot-oriented trading based on short-term economic conditions. Thus, prospective buyers of U.S. LNG considering pre-FID projects increasingly need to understand the ever-changing U.S. gas flow and pricing dynamics. At the same time, U.S. market participants trying to understand how 10 Bcf/d of LNG exports will affect the domestic market also will need to closely track LNG activity, including feedgas flows and prices. In today’s blog — which launches our new LNG Voyager service — we look at how U.S. onshore gas market dynamics are affecting gas supply costs at the Sabine Pass LNG facility, and considers what this might mean for several of the pre-FID projects.
Cushing doesn’t call itself the “Pipeline Crossroads of the World” for nothing. Pipelines with the capacity to handle one-third of total U.S. crude oil production flow into the central Oklahoma hub from a number of production areas, including the Alberta oil sands, the Bakken, the Rockies, the Permian and the nearby SCOOP/STACK. There’s almost as much pipeline capacity out of Cushing, with more than half of it bound for Texas’s Gulf Coast refineries and export docks and most of the rest headed for refineries in the Midcontinent and Midwest. Cushing’s inbound and outbound pipes connect to a staggering 94 million barrels of crude oil storage in about 350 aboveground tanks — each company’s set of tanks with its own unique degree of interconnectedness. Today, we continue our series on Cushing with a look at the large, medium and small pipelines that flow into the hub, and what they transport.
U.S. exploration and production companies (E&Ps) are generating such substantial output growth that the International Energy Agency (IEA) estimates their increase in 2018 liquids production could equal the entire growth in global demand. Remarkably, they’re accomplishing this with half the capital investment of 2014. The driver has been a shift to a manufacturing mode that has transformed the E&P industry as dramatically as Henry Ford’s moving assembly line changed the automobile industry in 1913. Geophysical and technological innovations, such as multi-well pad drilling, have allowed the industry to double output per well bore at half the previous cost. With oil prices and margins rising, you’d think the E&P industry, which historically has invested like “there’s never too much of a good thing,” would be pouring every available dollar into drilling more and more wells. But that isn’t the case. Instead, mid-year 2018 guidance shows that producers have adopted the long-term investment strategies usually associated with integrated oil majors, plotting incremental increases in investment to methodically accelerate production growth to 2020 and beyond.
For the first time in five years, takeaway expansions are outpacing Northeast production growth. Major natural gas takeaway capacity additions on large-diameter pipes like Tallgrass Energy’s Rockies Express Pipeline and Energy Transfer Partners’ Rover Pipeline over the past couple of years are allowing Marcellus/Utica natural gas producers to send record amounts of gas supply to the Midwest and, indirectly, to the Gulf Coast region. At the same time, there are some small pockets of unused takeaway capacity appearing on some of the legacy routes out of the region, which means that Appalachian basis levels — prices relative to Henry Hub — have risen to the strongest levels since 2013. For downstream markets like Chicago and Dawn, ON, that’s meant a flood of gas and lower prices. In today’s blog, we continue our series on the Northeast gas market with the effects of these new dynamics on gas price relationships.
To fire on all cylinders — especially during a period of strong high crude oil prices and rising production — the U.S. energy sector depends on midstream infrastructure networks that can efficiently handle the transportation and processing of every type of hydrocarbon that emerges from the wellhead. It’s no secret that rapid production growth in the Permian has left the red-hot West Texas play short of crude-oil pipeline capacity, and midstream companies there have also struggled to keep pace with natural gas takeaway needs too. What’s less well known is that fractionation capacity at the all-important NGL hub in Mont Belvieu, TX, is nearly maxed out, and that some Permian producers — and others — are now scrambling to find other places to send their incremental NGL barrels for fractionation into purity products. We put this issue front-and-center earlier this week in Hotel Fractionation. Today, we discuss highlights from the first of two planned Drill Down Reports on fractionators and other key assets at the nation’s largest NGL hub, and the potentially broader effects of a fractionation-capacity shortfall.
It’s no secret by now that Permian natural gas pipelines have been running near full the last few months, jam-packed like Southern California traffic while trying to whisk away copious volumes of mostly associated natural gas to markets north, south, west and east of the basin. Despite every major artery running near capacity this summer, Permian prices had so far managed to avoid falling below the dreaded $1.00/MMBtu threshold, a precipice that historically defines a gas producing basin as definitively oversupplied. That all changed yesterday, as word came in that Southern California Gas Company, one of the largest recipients of Permian gas, has nearly filled its gas storage caverns and will soon need far less gas hitting its borders. That’s particularly bad news for the Permian, which has few other options if it needs to reduce the supply that is currently flowing west out of the basin to California. A large unplanned outage for maintenance was also announced on one of the pipelines leaving the Permian and heading north to the Midcontinent. As a result, the SoCalGas news and maintenance combined to put a huge dent in Permian gas prices, some of which plunged as low as 50 cents in Wednesday’s trading. Today, we detail this most recent development and the implications for Permian gas takeaway.
It’s been more than a year since Hurricane Harvey dumped 50 inches of rain on Houston and its environs, but memories from those fateful days remain remarkably fresh. Harvey is not only unforgettable, it put a spotlight on just how important Texas refineries — and the refined-products pipeline infrastructure connected to them — are to the rest of the U.S. For several days, more than half of the Gulf Coast’s refining capacity was offline. Major pipelines transporting gasoline, diesel and jet fuel to the East Coast and the Midwest shut down too. But how do Harvey’s impacts on refining and refined products markets compare with the effects of other major hurricanes this century? Today, we conclude our series on Gulf Coast refining and pipeline infrastructure, and how a natural disaster along the coast can impact the rest of the country.
The crude oil hub at Cushing, OK, has more than 90 MMbbl of tankage, 3.7 MMb/d of incoming pipeline capacity and 3.1 MMb/d of outbound pipes. That’s an impressive amount of infrastructure by any standard. The real marvel of the place, though, is the variety of important roles it plays and services it provides for a wide range of market participants — producers, midstream companies, refiners and marketers, as well as producer/marketer and refiner/marketer hybrids. To truly understand Cushing — what it does and how it works — you need to know the hub’s assets and how they fit together. Today, we continue a series on the “Pipeline Crossroads of the World” with a look at the companies that own Cushing storage capacity and how that storage is put to use.
Y-grade, welcome to the Hotel Fractionation. You can check in any time you like, but you can never leave! OK, so that’s a bit of an overstatement. But there is no doubt that the U.S. NGL market has entered a period of disruption unlike anything seen in recent memory. Mont Belvieu fractionation capacity is, for all intents and purposes, maxed out. Production of purity NGL products is constrained to what can be fractionated, and with ethane demand ramping up alongside new petchem plants coming online, ethane prices are soaring. But that’s only a symptom of the problem. Production of y-grade — that mix of NGLs produced from gas processing plants — continues to increase in the Permian and around the country. Sooo … If you can’t fractionate any more y-grade, what happens to those incremental y-grade barrels being produced? How much can the industry sock away in underground storage caverns? Does it make economic sense to put large volumes of y-grade into storage if it will be years before it can be withdrawn? — i.e., “you can never leave.” And what happens if y-grade storage capacity fills up? Today, we begin a blog series to consider these issues and how they might impact not only NGL markets, but the markets for natural gas and crude oil as well.
Any joint venture has its pros and cons for each party, and in an ideal world, everyone involved in a JV sees net benefits from pairing up with a partner. A quarter-century ago, state-owned Petróleos Mexicanos (Pemex) purchased a 50% stake in Shell’s Deer Park, TX, refinery. The JV partners also entered into a 30-year processing agreement under which each would purchase half of the refinery’s crude feedstock and own half the output. Separately, Pemex agreed to supply as much as 200 Mb/d of Mexico’s heavy sour Maya crude to Deer Park and Shell agreed to supply Pemex with 35-40 Mb/d of gasoline to help meet Mexico’s refined products deficit. The partners recently agreed to an early extension of the deal by 10 years from 2023 to 2033, while reducing the supply of Maya crude after 2023 to 70 Mb/d, to be sold at a fixed price. Today, we continue an analysis of the JV and the new changes to it.
For the first time in years, natural gas takeaway capacity constraints from the Marcellus/Utica producing region appear to be easing, even as production volumes from the area continue to record new highs. That’s allowed regional supply prices this year to strengthen dramatically relative to national benchmark Henry Hub. A closer look at pipeline flow data indicates these developments stem from shifting gas flows that coincide with the ramp-up of Energy Transfer Partners’ Rover Pipeline. In today’s blog, we continue our update of the Northeast gas market with the latest on Rover’s gas receipts, along with its effects on other regional takeaway capacity and price relationships.
The late-August decision by Canada’s Federal Court of Appeal to overturn the Canadian government’s approval of the Trans Mountain Expansion Project will delay the project’s completion to at least 2021 or 2022. And — who knows? — the unanimous ruling may ultimately lead to TMX’s undoing, despite the Canadian government’s acquisition of the existing Trans Mountain Pipeline and the expansion project and its commitment to get TMX built. As producers in the Western Canadian Sedimentary Basin (WCSB) know all too well, TMX’s 590 Mb/d of incremental pipeline capacity would help to resolve ever-worsening pipeline takeaway constraints out of the Alberta oil sands and other production areas in the WCSB. These constraints are having a major economic impact every day — as evidenced by price differentials wide enough to run a locomotive through. Speaking of trains, crude-by-rail exports out of Western Canada reached a record 205 Mb/d in June, an 86% increase from the same month last year, and with WCSB production rising as new oil sands capacity comes online and with only limited relief likely on the pipeline capacity front from the Enbridge Line 3 Replacement Project in late 2019, many producers will need to depend on rail shipments of crude well into the 2020s. Today, we discuss the recent court ruling and what it means for Western Canadian producers, price spreads and the future of crude-by-rail.
Each of the “second wave” liquefaction/LNG export projects along the U.S. Gulf Coast now closing in on a Final Investment Decision (FID) believes it has an edge — that special something that will enable it to cross the finish line ahead of its competitors. Things like a prime location, access to an existing network of natural gas pipelines, lower capital costs, or going with smaller “midscale” liquefaction trains instead of traditional big ones. Some tout the experience and depth of their executive teams, while others claim that thinking outside the box is key. Time will soon tell which two or three (or four) projects advance to FID. Today, we continue our series on the next round of liquefaction/LNG export terminals “coming up” with a look at NextDecade’s plan for the Rio Grande LNG project in Brownsville, TX, which would export large volumes of Permian and Eagle Ford gas.
The push to develop local sources of frac sand — and significantly reduce well-completion costs in the process — started in the Permian Basin, but it didn’t end there. A number of new sand mines are being opened and developed in the Eagle Ford in South Texas, and there are early signs the same is happening in the SCOOP/STACK in Oklahoma. With local sand eliminating the need for rail deliveries and rail-to-truck transloading terminals, sand and logistics companies are streamlining the delivery and management of frac sand by providing integrated mine-to-well-site proppant services. Today, we discuss recent developments on the frac sand front and what they mean for exploration and production companies in key plays.