Western Canada has extraordinary oil and natural gas resources, but producers there have been suffering from a long list of woes. Oil sands producers need higher oil prices to justify expansion projects, and face shortfalls in pipeline takeaway capacity to refineries in Eastern Canada and export markets on both coasts. Natural gas producers can move gas east, but face stiff competition from the Marcellus and Utica plays; meanwhile, their efforts to expand LNG exports from British Columbia have been stymied by the new glut in worldwide LNG supplies and low LNG prices. Today we discuss the challenges in advancing Canadian oil and gas infrastructure projects.
Daily energy Posts
U.S. crude oil prices languish below $50/bbl, but the oil-directed rig count is up by 90, an increase of almost 30% over the past 12 weeks. Natural gas production is down less than 1% from the all-time high hit back in February even though the price of natural gas remains below $3/MMbtu. The price spread between U.S. propane and international markets is far below a level that should justify exports, but LPG exports to overseas markets continue at astronomical levels –– approaching 700 Mb/d, most of which is propane. What’s wrong with this picture? Why does it seem that relationships between energy production, demand and prices have broken down, or at least have undergone some fundamental shift? That is what our upcoming School of Energy Fall 2016 is all about. Warning: Today’s blog includes a commercial for our upcoming Houston conference, scheduled for November 2 and 3 at The Houstonian Hotel.
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.
In their second quarter 2016 earnings announcements, North American exploration and production companies (E&Ps) announced relatively minor changes to the steep reductions in 2016 capital budgets they unveiled around the first of the year. Total 2016 “finding and development” spending for 46 leading U.S. producers was an estimated $41.0 billion, down 51% and 70% from investment in 2015 and 2014, respectively, and slightly lower than the $41.9 billion forecast for 2016 spending in year-end 2015 announcements. The second-quarter reports over the past few weeks also confirmed the initial guidance of a 4% production decline in 2016 after 7% and 6% increases in 2014 and 2015. However, as we discuss today, a look behind the headline numbers indicates that cuts in capital expenditures (capex) look to have bottomed out, and that the industry may be poised for a turnaround in drilling activity later this year into 2017.
NOVA Chemicals’ 1.8-billion-pound/year ethylene plant in Sarnia, ON already is one of the largest consumers of Marcellus/Utica-sourced ethane, and plans are in the works to significantly increase the steam cracker’s ethane consumption. In 2018, NOVA will complete a project that will enable the cracker to be fed 100% ethane; the petrochemical company also is mulling a cracker expansion –– again with ethane as the feedstock –– and a new polyethylene plant next door. All these plans are driven in large part by the availability of low-cost ethane piped from the U.S. Northeast. Today, we continue our review of southwestern Ontario’s NGL, petchem and refining infrastructure with a look at the big effects of NOVA’s plans.
Higher gasoline imports to the U.S. East Coast and weaker demand in the region have combined to bloat gasoline inventories, raising the question, what would it take to bring the market into balance? East Coast refinery output is down from this time last summer in response to somewhat lower crack spreads, but not enough to make a dent. Part of the problem is that while gasoline demand turned anemic in the Maine-to-Florida region, it is even weaker in many overseas markets. Also, the skill of East Coast blenders in dealing with a wide variety of supplies has always made the region an attractive destination for international product flows. Today, we continue our look at petroleum product cargo flows, and what they are telling us about the health of the market.
Eight years into the Shale Revolution –– and two years into a crude oil price slump that put the brakes on production growth –– midstream companies continue to develop new pipelines to move crude to market. As always, the aims of these investments in new takeaway capacity may include reducing or eliminating delivery constraints, shrinking the price differentials that hurt producers in takeaway-constrained areas, or giving producers access to new markets or refineries access to new sources of supply. Whatever the economic rationale for developing new pipeline capacity, midstreamers and potential crude oil shippers need to examine–– early on –– the likely capital cost of possible projects, if only to help them determine which projects are worth pursuing, and which aren’t. Today, we begin a series on how midstream companies and potential shippers evaluate (and continually reassess) the rationale for new crude pipeline capacity in today’s topsy-turvy markets.
There is a story behind every new crude oil pipeline built to supply a decades-old refinery. After all, the refinery surely had a well-established crude-delivery system in place –– why change horses now, especially with refinery margins under so much pressure? Typically, the answer is that, well, times have changed. Or, more specifically, the Shale Revolution has up-ended traditional crude sourcing, forced refinery owners to rethink their crude slates, and opened up opportunities to access new, lower-cost oil. Today, we continue our look at these new pipeline connections, their rationales, and their effects on other pipelines, barge deliveries and crude-by-rail.
The availability of vast amounts of ethane from the nearby “wet” Marcellus and Utica plays is spurring a petrochemical rejuvenation in Sarnia, ON. Two years ago NOVA Chemicals stopped using naphtha as a feedstock at its 1.8 billion pound/year ethylene plant in Sarnia’s Chemical Valley and now relies on a combination of ethane, propane and butane. Next year the company is planning to complete the plant’s conversion to 100% ethane and is considering the possibility of building a big polyethylene plant nearby. Today, we continue our comprehensive review of southwestern Ontario’s NGL, petchem and refining infrastructure, including Sarnia’s NGL fractionation, storage and end-use markets.
New pipelines to increase crude oil takeaway capacity from major producing areas like the Permian and the Bakken to oil storage and distribution hubs like Houston, TX and Cushing, OK seem to garner most of the media’s attention. Just outside the spotlight’s glare, though –– and even during the ongoing slump in oil prices –– midstream companies are building several “demand-pull” pipelines to move crude to refineries more efficiently, and to give refineries easier, cheaper access to new, desirable supplies. Today, we begin a look at these new pipeline connections, their rationales, and their effects on other pipelines, barge deliveries and crude-by-rail.
It’s been a volatile summer for U.S. natural gas. The CME NYMEX front month contract spiked from $1.96/MMBtu in late May to $2.99 on July 1, up more than 50% in just over a month. Since then the price has headed mostly south, closing at $2.62/MMBtu on Tuesday, down $.37/MMBtu from its summer high a few weeks ago. As often is the case, the primary culprit has been weather. But for the first time, a new factor is starting to have an impact: LNG exports. During August, approximately 30 Bcf of gas will likely flow into Cheniere Energy’s Sabine Pass for now-routine LNG exports from Train 1 and the initial volumes needed for the start-up of Train 2. The more recent decline in gas prices just happened to follow the announcement that the entire Sabine Pass LNG facility will be shut down for several weeks starting next month for maintenance and to address a design issue. Was LNG a factor in the price decline? Hard to say. We may get a better sense of the market impact of LNG exports when the plant starts back up. At that point even more gas –– up to 1.25-1.5 Bcf/d in total –– could be sucked out of the market, possibly taking a 125-Bcf bite out of supply by the end of this year. The gas market has changed. From here on out, you won’t be able to understand the U.S. natural gas market without a solid grasp of LNG export dynamics. Today, we begin a two-part series on how international demand for U.S.-sourced LNG will have an increasing effect on gas supply, demand and price.
Of the 18 Bcf/d of incremental pipeline takeaway capacity out of the Marcellus/Utica that is due to come online over the next few years, nearly one-third is heading to demand markets in the Southeast via the Atlantic Coast states. The southeastern U.S is a fast-growing region, and its residents and businesses are becoming increasingly dependent on gas-fired power generation –– a real boon to Northeast gas producers. Today, we continue our look at how pipeline takeaway capacity will stack up against Northeast production over the next several years, this time with a focus on projects that will move gas to the Southeast.
The 450-Mb/d Dakota Access Pipeline (DAPL) has broken away from the pack of out-of-the-Bakken crude takeaway projects. On August 2, Enbridge Inc., through its master limited partnership Enbridge Energy Partners, agreed to take a large stake in DAPL from Energy Transfer Partners (ETP) and Sunoco Logistics Partners (SXL), a move that suggests Enbridge’s own 225-Mb/d Sandpiper Pipeline may drop out of the race soon. Joining Enbridge in the $2 billion deal is Marathon Petroleum, its former joint venture partner and anchor shipper on Sandpiper. Today, we consider these recent developments in the long-running effort to transport North Dakota crude oil to market more efficiently.
West Texas Intermediate (WTI) crude oil at Cushing is languishing back in the low $40s/bbl after a brief period of exuberance in the late spring. The blame for this latest oil-price retreat has shifted from high inventories of crude oil –– both on land and on tankers floating offshore –– to bloated petroleum-product inventories. There is some debate about how concerned the market should be about the increase in product stocks. In the opening episode of this blog series, we take a look at petroleum product cargo flows, and what they are telling us about the health of the market. We start today with middle distillates –– diesel and jet fuel.
Given their proximity to the Marcellus and Utica shale regions, the Midwestern states and Ontario would appear to be logical consumers of the increasing volumes of natural gas being produced in Pennsylvania, West Virginia, and eastern Ohio. The catch has been that the pipelines built years ago to serve the Midwest and Canada’s most populous province were designed to move gas into those regions from western Canada, the U.S. Gulf Coast, the Midcontinent and the Rockies, not the nearby Marcellus/Utica. That’s being corrected. Today we continue our look at how pipeline takeaway capacity will stack up against Northeast production over the next few years, with a focus on the Midwest and Ontario.
U.S. propane production from natural gas processing has doubled over the past five years, but domestic demand has hardly moved the needle. So the only way the propane market has balanced is through exports, and it is no overstatement to say that the ship has really come in for U.S. propane exporters. All those exports have also helped support the U.S.