By Friday (January 9, 2015) crude prices had fallen 55% since June 2014, natural gas prices are at the lowest since 2012 and natural gas liquids are suffering as well. The potential revenues from U.S. shale oil production in 2015 would be a whopping $66 billion lower at $50/Bbl than when oil was $100/Bbl last year. In this new world where prices may not return close to pre-crash levels for a number of years, producers are scrambling to reconfigure drilling budgets and locations. The exercise is all about rates of return and figuring out breakeven prices. Today we start a new series looking under the hood at production drilling economics including results from our own models.
Welcome to 2015! No, the last few months of 2014 were not a dream – or nightmare, depending on your perspective. Crude oil prices really did come crashing to earth, sucking down NGL prices in the process. And natural gas prices followed, falling to $3/MMbtu last week. Price relationships are out the window, as are drilling budgets. Over the next few months, these markets will be going through some of the most dynamic changes in years, with unpredictable consequences. Unpredictable? Nah. No mere market turmoil will dissuade RBN from sticking our collective necks out a third year in a row to peer once more into the crystal ball. Today we wrap up RBNs Top Ten Energy Prognostications for 2015 – Year of the Goat – #5 to #1.
Time to sober up. Not from excessive New Year’s Eve reveling, but instead from the past five years of euphoria in the shale oil and gas markets. In the past two months crude oil prices have come crashing to earth, sucking down NGL prices in the process. And lately even natural gas has succumbed to the malaise, falling below $3/MMbtu this week. Price relationships are out the window, as are drilling budgets. Over the next few months, these markets will be going through some of the most dynamic changes in years, with unpredictable consequences. Unpredictable? Nah. No mere market turmoil can dissuade RBN from sticking out our collective necks to peer into the crystal ball for a third year in a row for 2015 – Year of the Goat. Really. We did not make that up.
In time honored RBN blogging tradition – we’ve been at this blogging business three years –we look back today at the 250 blogs posted this year to see which ones had the highest hit rates. The number of hits any blog gets tells you a lot about what is going on in the energy markets – which topics resonate with our members, and which don’t attract much attention. Last year the big hitter blogs came in about 17,000 hits. This year the big numbers are closer to 50,000. With that many folks paying attention these days it is even more important that we take a page out of the late Casey Kasem’s playbook to look at the top blogs of 2014 based on numbers of website hits.
It would be an understatement to say that the worldwide market for liquefied natural gas (LNG) is in flux. LNG production is up and heading higher, oil—and LNG--prices are down sharply from a few months ago, and Japan and other big consumers of LNG are more interested than ever in mitigating price and supply risk. All this comes as Japan, a primary target of prospective U.S. and Canadian LNG export projects, is grappling with the need to restart dozens of idled nuclear units so it can reduce the oil and LNG imports that have hurt its trade balance since the Fukushima disaster nearly four years ago. Today we consider recent developments and how they may affect Japan and its potential LNG suppliers on the North America side of the Pacific.
We saw a slight recovery in crude prices Friday (December 19, 2014) with CME NYMEX West Texas Intermediate (WTI) futures up $2.41/Bbl from Thursday’s close. At the same time CME NYMEX Henry Hub natural gas futures were down $0.18 to $3.464/MMbtu. That meant the crude-to-gas price ratio between these two commodities was up 1.5X to 16.3X from it’s recent low under 15X on Thursday. However futures markets indicate that market expectations for the crude-to-gas ratio are for it to remain at a low level between 15X (i.e. WTI in $/Bbl is 15X Henry gas in $/MMbtu) and 17X for most of the next decade. If that turns out to be true there are serious implications for shale drilling, gas processing and LNG export prospects in the U.S. Today we look at what may happen and why.
In the dead of the natural gas winter season when US producers count on strong margins from higher gas prices, the Transco Z6 New York hub is trading on average nearly flat with U.S. benchmark Henry Hub, LA – the delivery point for the CME NYMEX natural gas futures contract. This is a dramatic departure from historical winter norms in the Northeast market, where prices relative to Henry and just about every other gas hub in the Northeast have traditionally carried hefty premiums in the winter. Moreover, the forward curves indicate these basis levels are the new norm for Northeast pricing. The forward curve for Transco Z6 New York shows basis for 2015 barely above Henry Hub for the year, with several months at more than $1.00/MMBtu discount. Today we look at what’s behind major changes in northeast forward curves.
West Texas Intermediate (WTI) CME NYMEX crude futures settled yesterday at $55.93/Bbl, down 52% since June 2014 and NYMEX Henry Hub natural gas futures settled at $3.619/MMBtu. The crude-to-gas ratio of these two energy commodities - meaning the crude price in $/Bbl divided by the gas price in $/MMBtu - was just over 15X. We have not seen a crude-to-gas ratio at this level since June 2010. Over the past 4 years the ratio has been far higher - averaging 27X and reaching a high of 54X In April 2012. That lofty four year run for the crude-to-gas ratio has arguably been responsible for much of the crude and natural gas liquids production boom since 2011 and a “Golden Age” of natural gas processing. Today we begin a two part series on the implications of a lower crude-to-gas ratio.
Developing new natural gas pipeline capacity in the Northeast isn’t easy. Environmental rules are tough, local citizens are well-organized, and—in New England in particular—the electricity market structure is not, shall we say, pipeline development-friendly. Still, with gas needs in the region rising, and all that Marcellus gas close at hand, midstream companies are doggedly and creatively pursuing pipeline projects, and making some headway. Today, we update efforts to advance the Constitution Pipeline, the Northeast Energy Direct project, and Access Northeast, all of which are planned to help move Marcellus gas into the heart of New England.
The development of US liquefied natural gas (LNG) export facilities is picking up steam. Four projects—Sabine Pass LNG, Cameron LNG, Cove Point LNG, and Freeport LNG—are now under construction (up from only one this past summer), and Sabine Pass is only a year or so away from liquefying and exporting its first LNG. But what about Western Canada? It’s got tremendous LNG export potential, but project proposals continue to face headwinds from cost concerns, regulatory uncertainty and the most recent hurdle – lower oil prices. Today, we consider the latest news on efforts to move Western Canadian gas to Japan and other overseas markets.
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.
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.
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.
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.
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.