Offer any energy commodity at a low-enough price and buyers will surface, as long as there’s a way to get that liquid or gas from where it’s being sold to where it’s being used or put on a boat for export. That’s been the recent experience of the butane market in Western Canada, where a perfect storm of events last fall caused butane prices in Edmonton, AB, to freefall to near zero. But things have turned around, at least for now. Today, we take a look at the dramatic recovery of the Edmonton butane market and what might lie ahead.
What a deal! Take as much butane as you want — all for the low, low price of less than 10 cents/gallon (c/gal). That was the situation in Edmonton, AB, last November and the price stayed dirt cheap until a few days ago. Given a decline in demand for butane in crude blending, along with growing NGL production, the NGL processing and storage hub in Western Canada was awash in butane as winter approached. It remains flush with product today — and the price for Alberta butane is still low. How did this happen, and how will it play out over the next few months? Today, we examine the factors that led the Edmonton NGL market to see a price fall to near zero c/gal for the second time this decade.
The Mexican market is critically important to Permian producers. Rising gas demand south of the border — along with expected gains in LNG exports from new liquefaction/export facilities along the Gulf Coast — are key to their plans to significantly increase production of crude oil, which brings with it large volumes of associated gas. All that gas needs a market, and nearby Mexico is a natural. For a number of years now, Mexico’s Comisión Federal de Electricidad has been working to implement a plan to add dozens of new gas-fired power plants and to support the development of new gas pipelines to transport gas to them from the U.S. The new pipelines have been coming online at a slower-than-planned pace. But what pipeline capacity has been added across the border from West Texas is already changing Mexico’s gas market. The El Encino Hub in Northwest Mexico is one such area where there are signs of a shifting supply-demand balance. Today, we continue a blog series on key gas pipeline developments down Mexico way and the implications for gas flows, this time delving into the dynamics at the El Encino Hub.
Mexico’s energy sector has been dealing with a fair amount of uncertainty of late. Newly installed Mexican President Andrés Manuel López Obrador has promised to undo elements of the country’s historic energy reform program, limit imports of hydrocarbons, and focus on domestic production and refining. How much will all this affect the export of natural gas from the U.S. to Mexico? It’s too soon to know what the long-term impact might be, but for now, gas exports remain near record highs and the pipeline buildout within Mexico is proceeding. That’s not to say, however, that the infrastructure work has gone without its own set of challenges — many of those were apparent well before the recent political changes. Today, we begin a series examining the opportunities and potential pitfalls ahead this year for Mexico’s natural gas pipeline infrastructure additions.
U.S. Northeast natural gas producers will soon get another boost of pipeline capacity with direct access to Gulf Coast demand. TransCanada’s Columbia Gas and Columbia Gulf transmission systems are gearing up to place into service their tandem Mountaineer Xpress and Gulf Xpress expansions, which will allow another 1 Bcf/d of Marcellus/Utica gas to flow south as far as Louisiana. The new capacity should further ease takeaway constraints for moving gas out of the Northeast, potentially redistributing outflows across the various takeaway routes, while also allowing Appalachian gas supply to grow. The duo of expansions is also the last of the southbound expansions from the Northeast, at least until late 2019, when the embattled Atlantic Coast and Mountain Valley projects are due online. Today, we detail the upcoming expansions.
This spring, TransCanada launched service for its 230-MMcf/d Sundre Crossover expansion, increasing transportation capacity for moving Alberta natural gas production to the U.S. Pacific Northwest. That may seem like a trifling volume in the big scheme of the North American gas market. But considering that Canadian and U.S. producers already are locked in a heated battle for market share of U.S. demand and pipeline capacity, it’s enough for Canadian supply to gain ground. Since the Sundre in-service date, deliveries to the Kingsgate point at the British Columbia-Idaho border have ratcheted up to the highest levels in at least a decade. As a result, Canadian exports have managed to elbow out Rockies gas from the California market, and set off a ripple effect that’s pushing more gas east to the Midcontinent. Today, we examine the shifting gas flows in the West.
Natural gas producers in Western Canada, with their share of U.S. and Eastern Canadian markets threatened by competition from producers in the Marcellus/Utica and other shale plays south of the international border, for years have seen prospective LNG exports to Asian markets as a panacea. But efforts to develop liquefaction “trains” and export terminals in British Columbia failed to advance earlier this decade — for starters, their economics weren’t nearly as favorable as those for U.S. projects like Sabine Pass LNG. Then, by 2016-17, global markets were awash in LNG as new Australian and U.S. liquefaction trains came online, and the BC LNG projects still alive were either delayed further or scrapped. Now, with LNG demand on the upswing and the need for additional LNG capacity in the early-to-mid 2020s apparent, the co-developers of LNG Canada — Shell, PetroChina, Korea Gas and Mitsubishi — have attracted a new and significant investor: Petronas, Malaysia’s state-owned oil and gas company and owner of Progress Energy Canada, which has vast gas reserves in Western Canada. Today, we continue our review of efforts to send natural gas and crude oil to Asian markets with a fresh look at the LNG project and TransCanada’s planned Coastal GasLink pipeline, which will deliver gas to it.
Mexico has been slowly increasing import volumes of natural gas from the U.S., utilizing spare capacity in the newest pipelines south of the border that access supply from the Permian Basin’s Waha Hub. The recent increases have been muted somewhat by delays in completing other infrastructure inside of Mexico, but one of those big delays is about to be resolved. TransCanada’s long-awaited El Encino-Topolobampo Pipeline is finally nearing completion, and once it’s online there may be a surprisingly big gain in gas export volumes to Mexico. As most of this gas will be supplied directly from Waha, Mexico’s impact on Permian gas balances is likely to jump materially in the weeks ahead. Today, we examine the latest development in Mexico’s natural gas pipeline buildout and its effects north of the border.
The Alberta natural gas market in Western Canada is in the midst of a seismic shift. Regional gas supply growth is accelerating. At the same time, export demand is eroding, but domestic demand — particularly from gas-fired power generation and oil-sands development — is on the rise. The incremental production along with the move toward intra-provincial demand has reconfigured flows and strained TransCanada’s infrastructure in the region. These factors resulted in extreme price volatility this past fall, a dynamic that’s likely to resurface in the New Year during low-demand times. Today, we continue our analysis of the Western Canadian gas market with a look at the changing transportation and flow dynamics in Alberta.
Western Canadian natural gas producers are increasingly facing oversupply conditions and price volatility. While competition and pushback from growing U.S. shale gas supply continues to be a factor, producers are now also contending with fresh problems closer to home — namely transportation constraints right where production is growing the most, in central Alberta. This fall, the Alberta market experienced extreme bottlenecks that left production stranded and sent area gas prices reeling. The ramp-up of winter heating demand has since helped ease the constraints, but the problems are likely to return in the spring when demand is lower, leaving producers exposed to the risk of severe price weakness again in 2018 and limited in their ability to grow supply. Today, we continue our look at what’s behind the local constraints and the implications for production growth and prices in Western Canada.
Demand for U.S. natural gas exports via Texas is set to increase by close to 6 Bcf/d over the next few years. At the same time, Texas production has declined more than 3.0 Bcf/d (16%) to less than 17 Bcf/d in the first half of November from a peak of over 20 Bcf/d in December 2014, and any upside from current levels is likely to be far outpaced by that export demand growth. Much of the supply for export demand from Texas will need to come from outside the state, the most likely source being the only still-growing supply regions—the Marcellus/Utica shales in the U.S. Northeast. Perryville Hub in northeastern Louisiana will be a key waystation for southbound flows from the Marcellus/Utica to target these export markets along the Louisiana and Texas Gulf Coast, particularly given the hub’s connectivity and prime location. Today, we look at the pipeline expansion projects into Perryville that will make this flow reversal possible.
Of all the demand markets in the U.S., the biggest prize eyed by Marcellus/Utica natural gas producers is the Gulf Coast region, where a combination of industrial demand, LNG exports and power generation projects is driving a need for more and more gas. And beyond the U.S. Gulf Coast states, there lies still another market capable of gobbling up even more of the excess Northeast gas supply: Mexico’s rapidly growing gas-fired generation sector ––that is, assuming pipelines in Texas can get it all the way there. There is over 4.0 Bcf/d of Marcellus/Utica-to-Gulf-Coast takeaway capacity planned to be completed over the next few years. Today, we look at the status and timing of Northeast pipeline takeaway projects targeting the Gulf Coast.
Natural gas producers in Western Canada are still struggling to find new markets to replace those they’ve lost to Marcellus/Utica producers in recent years. It hasn’t been easy, and they certainly haven’t been helped by the high cost of transporting gas to Ontario and the Upper Midwest, by the failure of LNG export projects in British Columbia to advance, or by the collapse of oil prices that has slowed growth in the oil sands sector (a huge consumer of gas). Despite the gloom, though, there are at least some rays of hope. TransCanada is considering big cuts in pipeline tolls in exchange for commitments to long-term deals. It’s also possible that at least one BC LNG export project may become a reality by the early 2020s. And some gas producers in the Montney shale region in the Canadian Rockies are focusing on areas where they also can produce vast amounts of condensate for use as diluent in the nearby oil sands region. Today, we provide an update on the ongoing (and often frustrating) efforts to expand gas production in BC and Alberta.
There’s been at least some progress the last two years on Alaska’s ambitious plan to pipe huge volumes of North Slope-sourced natural gas to the state’s southern coast, supercool it into liquid form, and ship the resulting LNG to Asia. Over that same period, however, the international LNG market has been rattled by weak demand, rock-bottom prices and an impending supply glut. Alaska is itching to become a major LNG supplier by the mid-2020s, but is anyone willing to buy what it’s selling? Today, we provide an update on Alaska’s LNG plan, including a newly approved state buy-out of TransCanada’s interest in key elements of it.
Yesterday (August 3, 2015) Brent crude closed under $50/Bbl for the first time since January 2015. At that price expensive crude-by-rail (CBR) freight costs to the East Coast leave Bakken producers with netbacks not much over $30/Bbl. Yet CBR shipments to the East Coast were still over 400 Mb/d in May 2015 according to the Energy Information Administration (EIA). By 2017 there should be adequate capacity to get all Bakken crude to market by pipeline. But direct pipeline competition against rail to the East Coast is not expected until at least 2020. Today we look at the future of East Coast CBR.