Six months ago, the natural gas forward price for 2021 averaged $5.15/MMBtu. Back then a producer could hedge forward production at that price. Today 2021 is only $4.63/MMBtu, a decline of $0.52/MMBtu even though we are now in the middle of the winter. Today the forward market doesn’t get above $5.00/MMBtu until 2026, certainly a disappointment for many a producer that didn’t hedge last summer. What does the market know about the future that is different from what was known back in June? How do these forward curves work in the first place? In this new blog series on North American natural gas forward curves we will provide background on the mechanics of forward curves, examine the forward curve in each of the major regions in the North American natural gas market, and do a deep dive into natural gas historical trends, major drivers and market expectations as related to forward markets.
Although as everyone ought to know by now, overall crude prices have dropped more than 35% in the past six months, prospects for the prolific Permian Basin continue to look rosy. Wide price discounts experienced by Permian producers at Midland, TX versus West Texas Intermediate (WTI) crude delivered to Cushing, OK over the past 13 months have narrowed recently in anticipation of the Plains All American Sunrise pipeline coming online. Permian production has been surging all year and midstream companies continue to invest in and expand takeaway capacity. Today we review ongoing infrastructure plans to handle growing output.
The US Environmental Protection Agency (EPA) June 2014 Clean Power Plan (CPP) proposal to reduce greenhouse gas emissions from the power sector 30% from 2005 levels by 2030 would result in a sharp increase in natural gas consumption and potentially major changes in infrastructure to deliver more gas to power plants. The proposal would radically increase the pace at which coal-fired power plants are replaced by gas-fired generation. Today, we consider the proposal and its likely impact on gas demand and the industry.
According to the U.S. Department of Agriculture, this year’s corn crop was 94 percent harvested by November 24, 2014. Unlike the 2013 harvest season, related crop drying activity by farmers to extract moisture from harvested corn has not led to shortages of propane- the main fuel used to power dryers. A wetter than usual crop last year started a Midwest propane shortage that morphed into a crisis by January when Polar Vortex winter weather spiked demand again and pushed prices above $4/Gal. This year the Midwest propane market has to cope with the loss of a major transport artery – the Cochin pipeline that used to bring Canadian propane supplies to the Midwest but has now been reversed to carry U.S. diluent to Canada. Today we examine new Midwest propane delivery infrastructure.
RBN’s School of Energy is headed north – all the way to Calgary. We have reworked, restructured and reorganized the curriculum to make the conference better than ever. And we guarantee it will be way cooler than our Houston Schools. We call it a Remix, because we have added new models, replaced some old models and enhanced them all. But even more important, we have increased the number of model labs from one to FOUR!! Each lab will step you through the model logic, how to input the data and how to interpret the results. You will work through cases that will test your knowledge on how the models work. And of course, all the course content has been updated to reflect the big changes in markets and pricing over the past few months. Warning, today’s blog is a blatant commercial for our Calgary conference.
The ratio of Mont Belvieu ethane prices to the price of natural gas at the Henry Hub on a BTU equivalent basis has been below 100% since March. That means ethane is worth more as gas than as liquid ethane, which was bad enough for ethane producers. But two weeks ago the bottom dropped out from under that ratio, and it now wallows below 80%. At that level, every molecule of ethane being recovered would theoretically be worth far more selling it as gas anywhere in the U.S. So have ethane production numbers been falling? Nope. Ethane production for the past four months reported by EIA has averaged an all-time high. Ethane extraction economics are upside down but ethane production is increasing. Today we examine the reasons why ethane is being extracted even when the economics don’t seem to make sense.
Prices for U.S. domestic benchmark West Texas Intermediate (WTI) crude on the CME NYMEX futures exchange crashed $7.54/Bbl to $66.15/Bbl Friday (November 28, 2014) - down 11 percent since the Wednesday before Thanksgiving and 38 percent since their recent high in late June. International benchmark Brent crude prices on the ICE futures exchange fell 10 percent to $70.02 /Bbl over the holiday and are down 39 percent since June. The underlying cause is oversupply but the short term trigger for last week’s nosedive was OPEC’s failure to respond to falling prices at their Thanksgiving meeting in Vienna by reining in production. Today we discuss the fate of crude prices after the OPEC meeting.
It’s only natural that high-volume markets like Asia and Western Europe are the focus of most discussions about exporting US liquefied natural gas (LNG) and natural gas liquids (NGLs) like ethane and propane. But the Caribbean, a market much closer to home, is attracting more attention lately, as infrastructure is developed to share America’s hydrocarbon bounty with the outside world. For decades, the Caribbean has been heavily dependent on oil-fired power generation and, as a result, its electric rates are among the highest anywhere. Now, the region is looking at alternative fuels for power generation, including LNG, compressed natural gas (CNG) and believe it or not, ethane. Today we consider the potential for fuel switching in the Caribbean, and the challenges involved.
Between them the TransCanada Grand Rapids, Enbridge Norlite and Devon/MEG Access pipelines currently being planned and built out will be able to deliver an extra 1 MMb/d of diluent to oil sands producers by 2017. That’s more than producers currently expect to need until 2030. The diluent will be shipped north from Edmonton terminals to production plants and blended with bitumen before making the return trip as dilbit or railbit destined for long-haul transport by pipe or rail to U.S. and Canadian markets. Today we describe the pipeline build out plans.
Last winter a Midwest propane shortage of epic proportions caused prices at the Conway, KS trading hub to spike over $4/Gal in January 2014 (nearly twice the price of crude oil at the time). The shortage was caused by a perfect storm of events starting with high propane demand from farmers for crop drying in the late fall and ending with record retail and commercial heating demand during the Polar Vortex cold weather in January. The high demand was compounded by the partial closure of the Kinder Morgan Cochin pipeline supplying propane to the Midwest from Western Canada and a temporary shutdown of the Hess Tioga fractionation plant in North Dakota, not to mention booming Gulf Coast propane exports reducing domestic availability. This year the Midwest propane market appears to be much better supplied in spite of the loss of the Cochin pipeline that has now been reversed to carry diluent to Canada. Prices should therefore be less volatile than last year – unless Mother Nature throws another icy winter curve ball. Today we look Midwest propane prices and supply this year.
We estimate October 2014 Eagle Ford condensate production at 690 Mb/d and have identified 450 Mb/d of stabilization capacity that meets Bureau of Industry and Security (BIS) standards to classify the processed output as OK for export. That should make it possible for an estimated 230 Mb/d of processed condensate to be exported from the Gulf Coast in 2015. All that is needed to open the floodgates are more transport routes to export docks. Today we describe current and future routes planned by Enterprise to get segregated processed condensate to market.
On Thursday, November 20, the ratio of ethane to natural gas hit its lowest point since 2005 – ethane only 64% of natural gas on a BTU basis. According to OPIS, the price of ethane in Mont Belvieu was 19.25 cents/gallon while natural gas at Henry Hub was $4.49/MMbtu. At this level it makes economic sense to reject as much ethane as possible. All the rest of the ethane that gets produced needs to find a use, a purpose, a home. Demand for ethane as a feedstock for the petrochemical industry will rise considerably as new ethane cracking capacity comes online, mostly in the 2017-19 period. Even so, ethane rejection is likely to remain commonplace for the foreseeable future. But what about ethane exports, not just to Canada but to Western Europe, Asia and other overseas markets? Today we update developments on the ethane export front.
RBN has been in the blogging business for almost three years, and ever since we started these postings one of the most frequent complaints we’ve heard is that “It doesn’t work on my iPhone”. Finally we are fixing that, and many more things too. But as with anything new delivered by internet, there are some things you need to know. So today is a blog about blogs, to make sure all of our members know what we are changing and how to take maximum advantage of our new website’s capabilities.
The economics of natural gas production in the dry Marcellus, the wet Marcellus and the Utica are so favorable—and the shale gas resource so bountiful—that the only real limit on how much the Marcellus/Utica plays can produce is the capacity of the pipeline network in the Northeast and neighboring regions to take gas to market. And there’s the rub, because the region’s gas transmission infrastructure was designed decades ago to deliver large volumes of gas to the Northeast, not away from it. That’s why the midstream sector has made “a new plan, Stan,” and is now in the midst of a major reworking of the pipeline system—not just within and near the Marcellus/Utica but just about everywhere east of the Mississippi. The $30 billion re-plumbing effort and its effects on the gas market as a whole are the subject of RBN’s latest Drill-Down Report, “50 Ways to Leave The Marcellus” which is available today to Backstage Pass members. In today’s blog, we provide an overview.
With Western Canadian oil sands bitumen output increasing rapidly, producers need more diluent to blend with their production so that it can flow to market in pipelines. That means delivering diluent to remote locations as far as 250 miles northwest of Edmonton. Smaller oil sands projects typically get their diluent delivered by rail or truck but pipeline infrastructure is being built out for larger projects as their production comes online. Inter Pipeline (IPL) diluent delivery volumes on their Polaris pipeline at the end of 2013 were just 20 Mb/d. By 2017 that volume could be to 1.2 MMb/d. Today we detail IPL and Plains build out plans.