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.
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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 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 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.
Over the next two years, increasing natural gas demand for Gulf Coast LNG exports will reverse flow patterns across the Southeast/Gulf region, resulting in supply/demand imbalances, pipeline capacity constraints and regional price aberrations. The most significant of these developments will occur in the backyard of Henry Hub, Louisiana, where growing supplies in the north of the state will compete for pipeline capacity to get down to coastal export facilities. More Louisiana north-to-south pipeline capacity is needed. The only questions are where the capacity is needed most, and who will build it? Today, we continue our review of Louisiana gas supply, demand and transportation capacity.
The Louisiana natural gas market has undergone major changes in recent years, from the decline of its offshore and onshore production volumes to the emergence of new export demand from LNG terminals. But there are many more changes on the way. The industry has plans to add another 5.0 Bcf/d of liquefaction and export capacity in the Bayou State between now and 2023. At the same time, there are a slew of pipeline projects designed to carry Marcellus/Utica gas supply to the Perryville Hub in northeastern Louisiana. And, Louisiana’s own gas supply is soaring from the Haynesville Shale. The timing of these emerging factors will drive supply-demand economics and volatility in the region — including at the national pricing benchmark Henry Hub — over the next five years. Today, we take a closer look at the timing and extent of the supply and demand factors affecting the Louisiana gas market.
Everyone in the North American gas industry knows that a big wave of U.S. LNG exports is coming. Although Cheniere Energy’s Sabine Pass terminal in southwestern Louisiana started shipping out LNG in 2016, exports really started having a major impact in 2017 — increasing demand for U.S.-produced gas, providing an outlet for Marcellus and Utica supplies, and affecting physical flows at the Henry Hub and in south Louisiana more generally. But with the first four liquefaction trains at Sabine Pass all but fully ramped up, attention in recent months has been turning to the next facility being commissioned: Dominion’s Cove Point terminal on Chesapeake Bay in Maryland, which exported its first cargo in early March. But tracking gas pipeline flows into the Cove Point plant has not been easy, and in today’s blog, we consider the various possibilities and discuss our view of how best to monitor the amount of LNG feedgas going into Cove Point.
The Louisiana natural gas market is in a state of major flux. The state’s supply mix has changed drastically, with Offshore Gulf of Mexico production declining over the past few years and the long-dormant Haynesville Shale making somewhat of a comeback in the past year. At the same time, four new liquefaction trains at Cheniere Energy’s Sabine Pass LNG terminal have added more than 3.0 Bcf/d of export demand that didn’t exist before 2016. These trends signal a shift in Louisiana’s supply-demand balance and are a prelude to big changes yet to come as producers and midstreamers look to provide solutions for balancing the market. Today, we continue our deep-dive into recent and upcoming changes in the Louisiana market, this time focusing on flow trends across the state’s North, Offshore Gulf and Central pipeline corridors.
The U.S. natural gas storage inventory lagged behind year-ago and five-year average levels throughout this past winter. The market started the withdrawal season in November 2017 with about 200 Bcf less in storage than the prior year. That year-on-year deficit subsequently ballooned to more than 600 Bcf. Compared to the five-year average, the inventory went from about 100 Bcf lower in November to a more than 300-Bcf deficit now, at the beginning of spring. An expanding deficit in storage is typically a bullish indicator for price. Yet, the CME/NYMEX Henry Hub natural gas futures contract struggled to hold onto the $3.00/MMBtu level it started the season with in mid-November, and, in fact, has retreated back to an average near $2.70 in the past couple of months — about 25 cents under where it traded a year ago. Today, we look at the supply-demand factors keeping a lid on the futures price.
With LNG export demand rising along the Gulf Coast, there are big changes coming to the Louisiana natural gas supply-demand balance, with significant implications for the national benchmark pricing location Henry Hub. The state’s growing demand center is attracting midstream investment and supply from two of the fastest growing producing regions — Appalachia’s Marcellus/Utica and West Texas’s Permian. An analysis of pipeline flow data is already providing clues as to how markets will evolve in the Bayou State. Today, we continue our flow analysis of the Louisiana pipeline corridors, this time with a focus on interstate flows across the state’s western border.
The supply-demand dynamic in Louisiana — and around the national benchmark pricing location Henry Hub — is rapidly changing, with LNG exports providing a new demand source in the state and both producers and midstreamers in high gear to push more supply there. These factors will disrupt existing flow patterns and pricing relationships in the region over the next two or three years, eventually turning the market entirely on its head. Today, we continue our series on the Louisiana market transformation with a detailed look at the infrastructure and gas flow trends already underway, starting with what’s going on in the eastern half of the state.
Natural gas flows and market dynamics are shifting at national benchmark Henry Hub. Supply receipts at Henry this year to date have doubled since the comparable period last year to nearly 450 MMcf/d, on average. That’s also a five-fold increase from the same period in 2016. In fact, current gas flows through the hub are the highest we’ve seen since 2009. The last time we saw this level of flows through the hub was when Gulf of Mexico offshore gas production volumes — much of which hit the U.S. pipeline system in southern Louisiana — were still topping 6.0 Bcf/d. That was also before the Marcellus/Utica Shale gas supply ballooned, effectively emptying out the pipeline capacity that used to flow gas north from the Gulf Coast. Now, many of those pipelines have reversed flows and the hub is showing signs of becoming a destination market for that Northeast gas and other supply targeting LNG export demand on the Gulf Coast. Today, we continue our short series looking at the changing physical flows at Henry Hub.
For decades, liquidity at the U.S. natural gas benchmark pricing location Henry Hub in Louisiana has been dominated by financial trades, with minimal physical exchange of gas, despite the hub boasting robust physical infrastructure, including ample pipeline connectivity. But that’s changing. Between the start of LNG exports from Cheniere Energy’s Sabine Pass LNG facility in February 2016, and the slew of pipeline reversals that are allowing Marcellus/Utica producers to target the new Gulf Coast demand, gas flows through Henry have been rising. In fact, more physical gas is moving through the hub than in nearly 10 years, to the point where a key pipeline interconnect is at capacity on many days, which historically was unheard of. Today, we begin a short series looking at the changing physical market at Henry.
As Canada’s natural gas exports to the Eastern U.S. have been pushed out by growing Marcellus/Utica gas supply, they’ve been flooding the U.S. West Coast. TransCanada is planning expansions of its Alberta system to send more gas across the western border, setting the stage for a showdown with Rockies gas supply. At the same time, the rise of renewable energy in California and the Pacific Northwest poses a constraint for gas demand growth in the region. Today, we look at recent shifts in border flows to the West Coast and prospects for future growth.
Canada’s natural gas exports — which have been pushed out of the supply-rich U.S. Northeast in recent years — are also facing challenges in Western U.S. markets. Growing supply from North Dakota’s Bakken Shale is increasingly competing for capacity on the same transportation routes as imports and is targeting the same downstream markets. Meanwhile, the rise of renewable energy in the West region from wind and solar farms is limiting gas demand in those target markets. What does that mean for imports from Canada? Today, we look at how these factors are affecting Canada’s exports to the Western U.S.