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.
Daily Energy Blog
We enter the natural gas winter this November after a record-breaking storage season that saw 2.75 Tcf of summer surplus squirreled away into underground storage. That surplus resulted from record breaking U.S. production exceeding lower summer demand. This year a repeat of last year’s freezing winter should run down storage enough to leave room for another summer of surplus. But with U.S. production at 70 Bcf/d and northeast output up 22 percent this year to nearly 18 Bcf/d gas supplies have reached a level where anything but a cold winter will leave too much gas in the ground next March. That theoretically would leave no room to inject surplus supplies into storage next summer – threatening the balancing role that storage plays in the natural gas market. Today we explain how the gas supply demand balance is threatened by changes to the storage market.
There’s good reason to be bullish about a skyrocketing trajectory for US methanol production. Natural gas prices are relatively low and likely to stay so; domestic demand for methanol continues to increase; and overseas demand—especially in China—is rising even faster. More than a dozen methanol mega-projects are in various stages of planning, design and construction, most of them along the Gulf Coast. If they were all built (they probably won’t be), US methanol production capacity would increase more than 10-fold to nearly 30 million metric tons per year, and turn the US from a methanol importer to an exporter within two or three years. Today, we look into why methanol demand is rising, what new capacity is under development in the US, and what it all means for natural gas producers.
There is an onslaught of surplus natural gas supply bearing down on the Henry Hub in South Louisiana. More than 60 natural gas pipeline projects are in the process of reversing the continent's gas flows to move gas out of the Northeast, and much of that production will be moved to the Gulf Coast. That gas will slam into supplies moving in to Louisiana from the west, sourced from “wet” gas and associated gas from crude oil plays in TX, NM, OK and ND. Demand from gas fired power generation, industrial gas use and LNG exports will eventually absorb the incremental supply, but not for a few years. We’ve seen this movie before, in the 2008-10 timeframe when Rockies gas battled it out with new shale supplies from the Haynesville and Fayetteville. But this time there is a big difference in the economics of production. Today we summarize the conclusions from a new deep-dive report from RBN Energy and BTU Analytics.
Japan is the world’s leading importer of liquefied natural gas, and its dependence on LNG has only increased since the March 2011 Fukushima nuclear disaster, which led to the shutdown of Japan’s 48 nuclear units. Some of those nukes are expected to return to service starting in 2015, but it’s possible—some would say likely—that a quarter or maybe even half of Japan’s nuclear fleet will never be restarted. While coal is cheap and oil is cheaper than it was a few months ago, natural gas-fired generation is seen as the best short-, mid- and long-term substitute for nuclear power. As a result, Japan utilities are working to increase and geographically diversify their LNG purchases, and to break what for decades has been a link between the pricing of LNG and oil. Today, we continue our look at how Japan’s response to the Fukushima disaster affects U.S. and Canadian natural gas producers and LNG exporters.
It seems increasingly likely that Hawaii’s electric utility and gas utility will be leading the Aloha State through a multi-year transition from an oil-based economy to one founded largely on liquefied natural gas—most of it sourced from Western Canada. Hawaii Gas, which currently makes syngas from naphtha, has proposed a two-step transition to LNG that begins with ISO container shipments and follows up with bulk shipments. That meshes well with Hawaiian Electric’s plan—also a two-stepper. Today, we up update our recent series on Hawaii’s big-wave move to LNG-based natural gas.
The total shutdown of Japan’s nuclear power industry in the wake of the March 2011 Fukushima disaster caused a more than 20% increase in liquefied natural gas imports. In 2015, the first two of the 48 Japanese nuclear units that were taken offline post-Fukushima are expected to be restarted, but it will take several years for most of the rest to come back online—and it’s likely that many nuclear units will never return to service. How much did Fukushima change Japan’s electricity sector, and how will that nation’s fledgling nuclear reboot affect LNG imports, not just from current suppliers like Australia, Qatar and Malaysia but new and prospective suppliers in the US and Canada? Today we begin a look at the electric industry in Japan, the future of nuclear power and LNG use there, and the Japanese-led effort to change how LNG is priced.
At first glance, the recent purchase of a natural gas pipeline network in southern Louisiana by EnLink Midstream from Chevron does not look very exciting. One of the assets - the Sabine pipeline – backbone of the Henry Hub CME NYMEX natural gas futures contract - reported losses of $7.5 Million and total flows averaging only 200 MMcf/d on Federal Energy Regulatory Commission (FERC) Form 2 in 2013. So what is the value of the pipelines tied to the world’s third largest futures contract? Turns out the Henry Hub futures contract generates some pretty good revenue for the pipeline operator without moving a molecule of gas. And there’s a bright future ahead for gas pipeline networks in Louisiana these days. We explain why in today’s blog.
The long-awaited Panama Canal expansion is expected to be complete and operational in January 2016, more than a year late and just in time to allow much larger liquefied natural gas (LNG) tankers to move product from Sabine Pass through the canal to Asian and Latin American customers. The canal’s ability to handle larger ships with “New Panamax” dimensions also will make transporting growing U.S. liquid petroleum gas (LPG) exports more efficient and less costly. And the canal expansion may make shipments of crude from Gulf Coast ports to West Coast refineries cost-competitive (but that’s not a sure thing). In today’s blog, we discuss the latest on the canal expansion and what it means to U.S. and global energy markets.
Hawaiian Electric’s plan to shift quickly from oil to liquefied natural gas (LNG) based natural gas as its primary power plant fuel is ambitious, but is it broad enough to benefit from the economies of scale that a more comprehensive, state-wide LNG program might provide? Hawaii Gas, which distributes synthetic natural gas it produces from naphtha, wants to shift to LNG as its gas source too, and state policymakers and environmentalists are interested in transitioning a significant part of the transportation sector from gasoline and diesel to natural gas. Will Hawaii become an island paradise for LNG suppliers? In this final episode of our Blue Hawaii series, we consider Hawaii Gas’s LNG plans, and assess the potential for an economy-wide shift to natural gas in the Aloha State.
From a high of $6.14/MMBtu in February 2014 natural gas prices have fallen to $4.013/MMBtu yesterday (September 17, 2014). In large part the price decline reflects the recovery of gas storage levels from record lows in March at the end of a freezing winter. Booming production and a milder summer have provided the surplus supplies needed for injections to replenish inventories reasonably close to normal levels (the latest storage numbers are released by the Energy Information Administration (EIA) this morning (September 18, 2014). Today we describe the impact of supply and weather driven demand on storage levels.
Hawaii is unique among the states. Not only is it a group of islands hours by plane from the US mainland, it alone—unlike the Lower 48 and Alaska—has neither indigenous oil or natural gas of its own nor any pipeline connections. That leaves Hawaii with no choice but to bring in via ship whatever energy it cannot wring from the sun, the wind or the earth (as in geothermal). After decades of burning oil to generate most of its electricity and making synthetic natural gas from naphtha, the state’s electric and gas utilities are moving toward liquefied natural gas (LNG). Today, we continue our examination of the Aloha State’s energy future with a detailed look at Hawaiian Electric’s plan to quickly shift from oil to LNG.
Many exploration and production (E&P) companies have indicated their sincere interest in at least partly weaning themselves away from diesel—and onto natural gas, much of it from LNG—as their fuel of choice for the engines that power their drilling rigs and hydrofracturing pumps. But there has been some hesitance in making the switch, in part due to concern about whether the LNG-supply infrastructure is sufficiently reliable. The same is true for railroads, trucking companies and ship owners—they too see potential savings in moving to engines fired partially or entirely by LNG, but they need assurance that their new fuel source will be plentiful and at hand. Today we detail all the new liquefaction capacity being developed specifically to serve these new markets.
Hawaii’s electric and gas utilities plan to end their long-time reliance on oil and its by-products—gas on the islands is actually synthesized from naphtha—and to shift to LNG as their primary fossil fuel (in the case of Hawaiian Electric) or at least as a back-up fuel (in the case of Hawaii Gas). The key drivers are economy and environment, but there also has been a worry that one or both of Hawaii’s two oil refineries may shut down, leaving islanders “at sea” from a fuel-supply perspective. Today, we begin a look at the potentially rapid transition to LNG being planned in the Aloha state, and the significant challenges and costs involved in making the switch.
The shift from diesel to LNG (and sometimes CNG or field gas) as a fuel for drilling rigs and hydrofracturing pump engines is underway, and there is interest in having ships, locomotives and long-haul trucks run on natural gas from LNG too. But before investing in new or converted engines that can run on natural gas or on a diesel-natural gas blend, diesel and shipping fuel users need answers to three questions: What will it cost? How much will we save? And—this is important, too--is the LNG infrastructure sufficiently robust to support the switch?Today we explore the economic ins and outs of converting from diesel to gas, and describe the current state of domestic LNG supply infrastructure.
