You may not know it by the look of the S&P E&P stock index, which has been flirting with record lows in recent weeks, but exploration and production companies are continuing to defy the industry’s legendary boom-and-bust cycles by pumping out increasing volumes of crude oil and natural gas while slashing spending. Some types of E&P companies have fared better than others in this lower-price environment. How are they continuing to generate substantial production growth under sharply lower capital investment programs? Today, we update our analysis of capital expenditures and production growth based on the second-quarter results of the 43 U.S. oil-focused, gas-focused, and diversified producers we track.
Daily energy Posts
U.S. Northeast natural gas producers in recent months got a substantial boost in pipeline capacity to receive and move incremental gas production volumes to attractive Gulf Coast markets. TC Energy’s Columbia Gas and Columbia Gulf transmission systems in March completed the Mountaineer Xpress and Gulf Xpress pipeline expansions, respectively, increasing the combined system’s Marcellus/Utica receipt capacity by 2.7 Bcf/d in the producing region, while also bumping up the Marcellus/Utica’s takeaway capacity to the Gulf Coast by nearly 900 MMcf/d. The duo of expansions is among the biggest takeaway capacity additions to be completed out of the Northeast, volume-wise, and among the handful that inextricably connect Marcellus/Utica supply markets to well-sought-after LNG exports markets along the Texas and Louisiana coasts. One of the export terminals these projects are designed to serve is Sempra’s Cameron LNG, where Train 1 began commercial operations in recent weeks. Today, we provide an update on the upstream and downstream implications of the recently installed Northeast-to-Gulf Coast pipeline capacity.
Rising U.S. production of NGLs and so-called “purity products” like ethane and propane, as well as growth in steam cracker capacity and NGL and ethylene exports, are giving added importance to NGL and ethylene storage capacity in underground salt caverns along the Gulf Coast. Mont Belvieu, TX, has long been the epicenter of both fractionation and salt-cavern NGL storage — and it will remain so — but there are other areas along the Texas coast with frac capacity and NGL storage, as well as steam crackers and export docks. The questions now are, is there enough in the right locations, and can what’s stored there be received and quickly sent out? Today, we begin a look at existing and planned NGL storage facilities along the Texas coast that are not in Mont Belvieu.
The news has been out for a few days now: Enterprise Products Partners announced last Tuesday, July 30, that, thanks to new agreements with Chevron, the midstream company has made a final investment decision to proceed with its Sea Port Oil Terminal (SPOT) about 30 miles off the coast of Freeport, TX, pending regulatory approvals. Being out front on this is critically important; even with significant growth in crude oil export volumes through the early 2020s, only one or two new export terminals capable of fully loading Very Large Crude Carriers (VLCCs) are likely to be needed. What was it that enabled Enterprise to move first among a wave of proposed projects? And what does that tell us about the VLCC-ready export terminal projects being advanced by others? Today, we look at the SPOT project and the important roles that existing pipeline and storage infrastructure play in export terminal development.
Growing natural gas supplies in Western Canada have been pressuring gas prices and export pipelines in the region, but there are signs that at least some of that supply-growth pressure is being offset by rising gas demand. Though the region is pegged as primarily a winter gas market — where local demand only rises when the temperature falls into the winter extremes — non-weather-related demand for natural gas has been growing in Western Canada and looks to have further upside in the years ahead. Today, we delve into Alberta and British Columbia’s gas demand trends and their potential to help balance the region’s oversupply conditions.
The battle between Bakken and Western Canadian natural gas supplies for the Chicago market seems to be advancing toward a final showdown of sorts. Associated gas production from the crude-focused Bakken has been rising sharply, but capacity on the Bakken’s two gas takeaway pipelines — Northern Border and Alliance, also utilized by Western Canadian Sedimentary Basin (WCSB) supplies — has been maxed out for a few years now. The result is that Bakken gas is increasingly encroaching on — and pushing back — imports from the WCSB. Bakken gas flows already overtook Canadian gas receipts on Northern Border a year ago. Since then, the gas-on-gas competition and the resulting pipeline constraints have escalated, and things are likely to get worse. Today, we break down the forces at play in the competition for market access.
It’s been an exciting and productive few years for Permian producers, but it’s also been a period fraught with challenges. Dealing with a mid-decade crash in crude oil prices. Struggling to improve yields from the Wolfcamp, Bone Spring and other hydrocarbon-rich formations to lower breakeven costs. Coping with major pipeline takeaway constraints — for crude and natural gas — and the resulting price discounts. Now, the challenge of produced water has come to the fore. Horizontal wells in some parts of the Permian generate six, eight, even 10 barrels of produced water per barrel of crude, and all of it needs to be either disposed of or treated. The volumes are enormous, the permitting and logistics mind-boggling, and the costs — well, you can imagine. Today, we consider the Permian’s produced-water conundrum as crude and gas production volumes ramp up. Warning!: Today’s blog is a blatant advertorial for new reports by B3 Insight on Permian produced water.
Crude oil gathering systems in the Permian and elsewhere are, by their very nature, evolving things. They increase in mileage and crude-carrying capacity as new wells are drilled and completed, and it’s not uncommon for smaller systems to be consolidated into larger ones. It’s also become typical for the ownership of these systems to change — sometimes year to year — as early investors cash in on what they’ve developed, and buyers see opportunities to rake in increasing revenue and take their newly acquired systems to the next level. Also, owners of neighboring systems sometimes form joint ventures that combine their assets, all to make their operations work better for their producer customers. Today, we continue our series on Permian gathering with a look at Brazos Midstream’s crude gathering system in the Delaware Basin, which has experienced considerable evolution.
Bakken crude oil production surpassed 1.4 MMb/d this spring and has maintained a level near that since, even posting a new high just shy of 1.5 MMb/d in April 2019. The rising production volumes have filled any remaining space on the Dakota Access Pipeline (DAPL) and prompted midstream companies to step up expansion efforts to alleviate the pressure, even as questions linger about the possibility of a pipeline overbuild if all of the announced capacity gets built. Specifically, the market is weighing the need for the recently announced Liberty Pipeline and a DAPL expansion. Today, we look at these two new projects and what their development means for the supply/demand balance in one of the U.S.’s biggest shale basins.
By the third quarter of next year, the Enterprise Hydrocarbons Terminal (EHT) on the Houston Ship Channel will have the capacity to export nearly 1.1 MMb/d of LPG — 435 Mb/d more than it can today. Also, Targa Resources and Energy Transfer are each planning 200-Mb/d expansions at their LPG export docks along the Texas Coast, and Phillips 66 and MPLX may very well be announcing projects of their own soon. All this suggests that there will be ample dock space available to propane and butane shippers if, as we expect, LPG volumes continue to ramp up in the 2020s. And, with Enterprise Products Partners’ promise to offer super-competitive rates at EHT, shippers are likely to enjoy low send-out costs. Today, we discuss recent developments on the propane/butane marine-terminal front and what they mean for LPG shippers and exports.
After sustaining a record pace since March, natural gas storage injections have been slowing dramatically and are projected to fall below the 5-year-average rate over the next few weeks. While weather has factored heavily into the swing in storage activity, increased baseload demand for gas in the power sector has amplified the effects of weather anomalies and electricity demand seasonality on overall gas demand. As a result, gas demand volumes have diverged from historical levels on a temperature-adjusted basis. Today, we examine the changing historical relationships of power burn and storage injections to weather and electricity demand.
Crude oil production in Western Canada and the Bakken is ratcheting up — in the Niobrara too — but pipeline takeaway capacity to key markets south of there is an issue. For a couple of years now, egress out of Alberta has been problematic, due in large part to delays in the development of the Enbridge Line 3 replacement, the Trans Mountain Expansion (TMX) and Keystone XL. Things got so bad last winter that Alberta’s provincial government ordered production cutbacks, though they are now easing. Rising Bakken production is quickly filling any remaining space on the Dakota Access Pipeline, and pipes out of the Niobrara’s Powder River and Denver-Julesburg (D-J) basins are approaching their capacities as well. In response, midstream companies have proposed a number of fixes, some very incremental in nature and others big and impactful. As typically happens, though, too much capacity may be on the drawing board. Today, we consider the ongoing competition to build new capacity down the eastern side of the Rockies.
Once consigned to a flat or declining profile, natural gas production in Western Canada has been increasing steadily since 2012, to the extent that it has now begun to stretch the ability of the existing pipeline network to the breaking point. Most striking is that this expansion in production has been taking place in an era of declining natural gas prices and weakening basis for Western Canada’s primary natural price marker, AECO, and rising and relentless competition from U.S. gas supplies in several of Canada’s key domestic and export markets. If the pricing, pipe egress and export situation has become so dire, why are producers still drilling for and pumping out even more natural gas? Today, we address this question in the second part of our series investigating Western Canada’s natural gas supply and demand balance.
Acquire, expand, and acquire again. That’s proven to be a successful strategy for a number of midstream companies providing crude oil and natural gas gathering services in the Permian Basin. In the past couple of years, the hydrocarbons-packed shale play in West Texas and southeastern New Mexico has been experiencing major gathering-system buildouts and Pac-Man-like acquisitions that aggregate small and midsize systems into regional behemoths. A case in point is EagleClaw Midstream, which has used the acquire-and-expand approach to great effect, most recently with the concurrent acquisition of Caprock Midstream Holdings and Pinnacle Midstream — two deals that, by the way, gave previously gas-focused EagleClaw a strong foothold in Permian crude gathering. Today, we discuss EagleClaw and its holdings in the Permian’s Delaware Basin.
The battle over the future of Enbridge’s Line 5 light crude oil pipeline through Michigan is heating up. In recent weeks, Michigan’s new attorney general filed suit to throw out the 1953 easement the state granted to allow the pipeline to be laid under the Straits of Mackinac — the narrow waterway between Michigan’s upper and lower peninsulas — and to block implementation of an agreement Enbridge and the state’s then-governor reached last fall to replace the section of Line 5 under the straits by the mid-2020s. Enbridge is pressing ahead, maintaining that the existing pipeline is safe and the 2018 agreement is legal and fully enforceable. All that raises two questions: just how important is Line 5 to the Michigan and Eastern Canadian refineries, and what would those refineries do if the pipeline were to cease operations? Today, we discuss recent developments and examine the issues at hand.
Natural gas storage activity this spring suggested extremely bearish fundamentals. The market injected gas into storage at a record pace, well above year-ago and 5-year-average levels. The high injection rate was in part a result of demand loss as weather abruptly moderated in April and May. However, a look at injections on a weather-adjusted basis suggests there’s another dynamic at play — namely, that increased baseload demand for gas in the power sector amplified the effects of the mild weather this spring, lowering demand even more than temperatures alone would indicate. Moreover, that same dynamic could have an opposite, equally extreme effect during the hotter months when power generation is the primary driver of gas demand. Today, we look at the latest gas storage and demand trends, and what they can tell us about the balance of injection season.