For some time now, discussions about the possible development of Canadian liquefaction/LNG export terminals have focused on the Western Canadian coast in British Columbia––partly because most of Canada’s natural gas reserves are nearby in northeastern BC and in Alberta, and partly due to Asia being a primary LNG target market. . But it could be that liquefaction/LNG export projects in Eastern Canada may make more sense. In today’s blog, “So Far Away –Sending Western Canadian Natural Gas East for Export as LNG,” LNG Ltd.’s Greg M. Vesey considers the rationale for piping Western Canadian natural gas long distances to Quebec and the Canadian Maritimes for export as LNG.
Daily energy Posts
At long last, the Energy Information Administration (EIA) has reported an “official” estimate of the U.S. drilled-and-uncompleted well (DUC) inventory as part of its monthly Drilling Productivity Report. DUCs are a critical factor in forecasting production trends, as many of these wells are likely to be some of the first to come online as soon as prices move higher and thus have the potential to boost production quicker and easier than would otherwise be the case. However, the number of DUCs has been a difficult thing to measure, though not for lack of trying. There are, in fact, widely varying counts from many different sources circulating in the industry. Today, we begin a short series on these latest DUC counts and their potential implications.
Many factors are weighed before a midstream company commits to building, or a shipper commits to shipping on, a major crude oil pipeline. Where is incremental pipeline capacity needed? What would be the logical origin and terminus for the pipeline? What should the project’s capacity be, and what would be the capital cost of building the project? Where the economic rubber really meets the road is the question of what unit cost––or rate per barrel––would the pipeline developer need to charge to recover its costs and earn a reasonable rate of return on its investment. Today we continue our review of crude oil pipeline economics with a look at the rules-of-thumb for determining what pipeline transportation rates would be.
The prospects for sellers of Williston Basin/Bakken crude oil in what once was a prime growth market—the U.S. East Coast—have been dwindling fast, as have the volumes of Bakken crude being railed and barged to refineries along the Mid-Atlantic coast and the Canadian Maritimes. Today we look at how a combination of weak crude oil prices, declining production, high relative freight costs, and the lifting of the U.S. crude oil export ban have opened the door to more imports from West Africa, and left Bakken producers out in the cold.
Natural gas production volumes in the Permian Basin are very near the all-time record of 6.9 Bcf/d set last September, and crude oil and gas producers alike see nothing but blue skies for the highly prolific West Texas/Southeast New Mexico play. The Permian already has a lot of gas processing capacity, but a good bit of it is older, and parts of the region—especially the super-hot Delaware Basin—need more of the big, efficient cryogenic plants that can process 100 to 200 MMcf/d. Today, we continue our review of gas production and processing in the biggest U.S. gas-producing region that is not named Marcellus.
For the first time since the start of the crude-by-rail (CBR) boom a few years ago, just as much crude oil is being transported by rail to PADD 5—that is, to states in the western U.S.—as to the Eastern Seaboard states in PADD 1. This primarily reflects the facts that 1) CBR deliveries from the Williston Basin/Bakken to PADD 1 continue to plummet and 2) refineries in the West remain reliable buyers of railed-in crude from the Bakken and Western Canada. Will CBR shipments to the East Coast continue to fall, or have we seen the worst of the decline? Today we take a look at recent trends in crude movements by tank car, and a look ahead.
More midstream projects than you might expect are “goin’ on” in the Western Canadian province of Alberta, considering the challenges that bitumen/crude oil and natural gas producers there continue to face. There are several drivers behind the relatively long list of oil and diluent pipelines; gas processing plants and fractionators; and oil/NGL storage facilities being built in Canada’s Energy Province, but much of the work is being done to meet the expected needs of oil-sands expansion projects approved during better times and set to come online soon. Today we begin a blog series on Alberta midstream projects with an overview of where the province’s energy sector stands today.
Planned liquefaction/LNG export facilities along the South Texas coast and growing demand from Mexico’s electric power sector together will require several billion cubic feet/day of additional U.S. natural gas over the next three to five years. Gas producers from the Marcellus/Utica to the Permian are targeting these markets, but there are questions regarding whether the Lone Star State’s existing pipeline infrastructure is sufficient to deliver all that gas to these critically important export markets. Part of the solution will be optimizing the use of Texas’s impressive—but sometimes misunderstood intrastate pipeline networks, particularly the far-reaching systems operated by Enterprise, Energy Transfer and Kinder Morgan. Today, we discuss one part of the solution, an inexpensive but impactful Kinder Morgan project that will enable about 1 Bcf of natural gas from various sources to reach South Texas LNG exporters and Mexico on KM’s intrastate system.
The ratio of NGL-to-crude oil prices looks like it will be rebounding, and over the next two or three years could rise to levels not seen since the Shale Revolution brought down NGL prices at the end of 2012, a signal that all of the new NGL-consuming petrochemical cracker projects now under construction may not be as lucrative as their developers had once hoped. Several factors are driving the ratio’s rise: increasing U.S. demand for NGLs; more exports; stubbornly low crude oil prices and a lower trajectory of NGL production growth. Today, we examine the historical relationship between NGL and crude oil prices and the reasons why that ratio may be headed back above 50%.
More than four years after the Utica and the “wet” part of the Marcellus became a hot spot for drillers, the field condensate and natural gasoline produced there are still moved to market by barge, rail and truck. A three-part, $500 million plan by MPLX LP and the midstream master limited partnership’s (MLP’s) subsidiaries, now well under way, will enable more efficient pipeline transport of these important hydrocarbons to Midwest refineries, Western Canadian diluent pipelines and other end-users. To hold down costs, the effort involves a creative mix of new and existing pipelines. Today we continue our review of MPLX’s plan with a look at its “Utica Build-Out Projects.”
Despite the doom and gloom that many see in the global LNG market –– too much supply, weak demand growth, and low LNG prices –– the possibility remains that the sector may offer the opportunity for low-cost, highly responsive market participants to do quite well, and even thrive. How can that be? After all, we’ve just seen another year of low crude oil prices resulting in very low oil/natural gas margins, and the expectation of high oil/gas margins were critical in supporting the development of many U.S. liquefaction/LNG export projects. But a combination of responsive demand, low cost infrastructure development and the possibility that number of exporting countries could run out of gas at or near the end of their existing contracts could change the outlook for ongoing LNG export development. Today, we look at the LNG market in the context of themes discussed at the North American Gas Forum (NAGF). Warning: this blog includes a plug for this year’s NAGF conference.
Net crude oil imports to the U.S. Gulf Coast in 2016 have been running well above the pace set last year, the increase driven by a combination of lower U.S. crude oil production, rising import levels and relatively flat export volumes. The trend toward higher net imports –– an outgrowth of the end of the ban on U.S. crude exports –– is significant in that it affects oil inventories and oil prices. What’s driving this trend, and how soon might net imports peak? Today, we survey recent developments on the crude oil import/export front, with a focus on the Gulf Coast.
Let’s face it — for producers, the last couple of years have stung, with low-slung energy prices allowing little-to-no returns on drilling investments in most parts of the major shale basins. A side effect of the low price environment in the past two years has been the shrinking geographic footprint of the Shale Revolution. About 50% of all onshore rigs in the Lower 48 currently are clustered in the top 20 counties for drilling activity. In effect, this also means a lot of the new production growth will come primarily from these same 20 counties, with the potential for all sorts of implications for infrastructure and regional price relationships. In today’s blog, we take a closer look at rig counts by county to see how much the geographic focus of the Shale Revolution has narrowed.
California and New England are two of the nation’s quirkier regions when it comes to energy –– and we mean that in the nicest way possible. So maybe it’s not too surprising that, at a time when the U.S. is just beginning a big push to export natural gas as LNG, the Golden State and “Yankeeland” (as some still refer to New England) are turning to imported LNG to help them deal with possible gas shortages during peak demand periods this coming winter. In neither case is liquefied natural gas considered to be a long-term fix, but –– for now at least –– LNG may be playing a role in keeping the pilot lights lit and the electric lights on. Today, we look at how the stockpiling and use of LNG can still make sense in a nation with an abundant supply of gas.
Two new 50-Mb/d, Kinder Morgan-owned and -operated condensate splitters came online during the first seven months of 2015, backed by a 10-year BP commitment to process a total of 84 Mb/d through the units. Located in the Houston Ship Channel’s refinery row, the splitters were expected to provide a profitable outlet to process growing volumes of the ultra-light crude oil known as condensate. Instead, average plant throughput through July 2016 has been only 71% of capacity, well below the 90% average operating level of neighboring refineries. The relatively low level at which these units have been operating reflects sagging condensate processing margins. Today, we detail how Kinder Morgan’s new splitters have been run during their first year or so of operation.
The group of 21 liquids-focused exploration and production companies we have been tracking plans to cut capital expenditures by half in 2016, after a 42% decline in 2015. However, capex for this “oil-weighted” E&P peer group is apparently bottoming out—their mid-year guidance was only 2% lower than their original 2016 estimates. Even with deep cuts in capital spending, the group expects production to fall only 7% in 2016, and those estimates have been revised higher from the initial 2016 guidance. Also worth noting: Pure Permian Basin players, the most optimistic companies in the peer group, are cutting capital spending by only 19% and are expecting a 12% gain in production. And with Apache Corp.’s announcement earlier this week of a huge discovery in the Permian’s Southern Delaware Basin, the market is definitely making a turn. Today we discuss 2016 capex and production for a representative group of E&P companies whose proved reserves are more than 60% liquids.