A highly anticipated event in the U.S. natural gas market is when the Northeast region crosses the line from being a net gas taker from, to becoming a net gas supplier to, the rest of the country. Ever since the Marcellus and Utica shale began ramping up, Northeast production has been on a course to eclipse regional demand. RBN predicted 2015 would be the tipping point when the supply-demand balance would finally reverse on an annual average basis, marking a new phase for Northeast prices and for the U.S. gas market as a whole. We’ve seen that despite capitulating oil prices, capital budget cuts and lower rig counts, Northeast production has continued to reach new highs in 2015 – beating the record again this past Sunday (November 22,2015) at 20.3 Bcf/d according to Genscape. But regional demand also has been at record high levels. Today with less than two months left in the year, we determine whether the Northeast region will – or already has - crossed the threshold to net supplier in 2015.
Yesterday (November 19, 2015) the Energy Information Administration (EIA) published its first official weekly natural gas storage report in its new five-region format indicating an injection of 15 Bcf over the past week for a total U.S. inventory of exactly 4 Tcf. The new methodology and reporting format is a vast improvement in the granularity and clarity of government natural gas storage inventory data. But it also potentially moves the target for the slew of industry analysts who lose sleep trying to predict it each week. How the changes impact EIA inventory data and the ability of analysts to predict that data will become clearer in the coming weeks and months. But we got more clues this week as the EIA released dual versions of last week’s report on Monday showing significant differences leading up to launch of the new report on Thursday. Today we compare the results of the old versus new methodology.
Within and near the Marcellus and Utica shale plays, power plant developers are building more than a dozen new natural gas-fired generating units, mostly combined-cycle plants that can operate essentially around-the-clock. This construction boom, spurred by a combination of abundant, low-cost gas and the regulation-driven retirement of scores of older coal plants, is boosting gas consumption close to gas production areas and reducing—at least a bit—the surplus gas volumes that Marcellus and Utica producers and marketers need to move to markets outside the region. Today, we examine the race to build new power plants near production areas in the Northeast, and consider what the resulting local gas consumption might mean for the region’s gas prices and pipeline needs.
It used to be the case that if natural gas even came up in power-industry discussions of generation, it happened at the end of a meeting—“Well, we’re done with our nuclear and coal plans, anyone have anything else to discuss before we go to dinner? Oh, that’s right—anything happening with gas?” Now it’s the other way around. It seems like every discussion starts with gas, whether it’s about the plants being low-cost and easy to site, about concerns around reliability and price volatility, or around the impact of the gas market on coal investments. And power is clearly the fastest growing segment of the U.S. natural gas market. But does all this attention from the power market mean that the natural gas industry really understands the power side? Perhaps not. In fact, we’ve found that frequently, as soon as we get beyond the marketers and analysts who deal specifically with supplying gas-fired power generation, there’s a lot the natural gas industry (and the energy markets in general) can learn about power plants, electricity markets, and how natural gas fits in. So for that reason, we’ve concluded that now is a good time for a primer on how gas-fired generation works, how it fits together with energy markets and how it might be affected by national policy changes. Today we take on this challenge with the first installment of a three-part series.
As we stated in Part 1 of this series, New York City will need increasing amounts of natural gas as it continues its shift from oil-fired power plants and oil-based space heating. New gas pipeline capacity to and through the Big Apple has been added as recently as May 2015, but the nation’s largest city still faces wintertime gas-delivery constraints that cause costly spikes in gas and power prices. Given the challenges of adding new pipeline capacity in one of the most densely populated parts of the U.S., developer Liberty Natural Gas is planning an offshore liquefied natural gas terminal that by late 2018 would inject gas into the city’s existing pipeline network on an as-needed basis. Today, we continue our look at the economics of using imported LNG to supplement gas supplies in the Northeast.
The U.S. natural gas market is starting its 2015-16 winter season with a whopping 3,929 Bcf in storage, equal to the record maximum level set Nov. 2, 2012. Meanwhile gas production is also well above last year. Given these conditions, the market will need record demand to absorb incremental production and work off the surplus in storage. But weather forecasts so far are pointing toward a delayed start to winter heating demand. The price of natural gas has sagged under the pressure with the prompt CME/NYMEX Henry Hub futures contract treading at a price less than half this time last year. And, now, a number of operational factors and constraints are set to kick in for the winter that could further disrupt an oversupplied market. In today’s blog, we look at the storage and transportation dynamics that could factor into how the market balances this winter.
There’s been at least some progress the last two years on Alaska’s ambitious plan to pipe huge volumes of North Slope-sourced natural gas to the state’s southern coast, supercool it into liquid form, and ship the resulting LNG to Asia. Over that same period, however, the international LNG market has been rattled by weak demand, rock-bottom prices and an impending supply glut. Alaska is itching to become a major LNG supplier by the mid-2020s, but is anyone willing to buy what it’s selling? Today, we provide an update on Alaska’s LNG plan, including a newly approved state buy-out of TransCanada’s interest in key elements of it.
It is certainly no secret that hydraulic fracturing, the process used to crack shale to yield natural gas and oil, is highly controversial. Numerous reports, claims, protests, etc. have asserted that hydraulic fracturing poses a danger to drinking water, which has led to a storm of argument and opposition in many areas of the country. Anyone wondering how oil and gas markets will work in the future must have in the back of their mind the possibility that opposition could lead to rules that would stifle supply development. So many were anxiously awaiting an Environmental Protection Agency (EPA) study of hydraulic fracturing and drinking water that had been going on for five years. The draft of that study was released in June. What does it do, and what does it mean for oil and gas future development? Today, we explore some of the findings of the draft report and focus on its implications for the natural gas industry.
The incremental pipeline capacity built to move more natural gas from the Marcellus to the New York City region over the past two or three years has reduced—but not eliminated--delivery constraints and wintertime gas-price premiums at the New York City pricing hub on Zone 6 of the Transco pipeline and other pipes feeding the area. Given the Big Apple’s significant and growing gas demand, midstream companies are exploring whether to add still more pipeline capacity, and developer Liberty Natural Gas is lining up approvals for its proposed fix: an offshore LNG terminal that would inject gas when demand spikes. Today, we begin an examination of the economics of using LNG to supplement wintertime gas supplies, and how Greater New York might benefit from an LNG shot-in-the-arm.
The Energy Information Administration (EIA) yesterday (Thursday) reported the U.S. natural gas storage inventory is 3,877 Bcf as of Oct. 23, which is above the 5-year maximum for this week and within striking distance of breaching the all-time record high of 3,929 Bcf (Nov. 2, 2012) by the end of the traditional storage injection season on Oct. 31. And, while the production growth rate has slowed compared to recent years, and even dipped a bit over the past couple of weeks, total gas production is still near record levels and about 2.0 Bcf/d higher than last year. Now the gas market is about to flip to withdrawal season, when winter heating demand typically exceeds available local production, leading to storage drawdowns. The combination of high storage and production levels sets up a bearish dynamic for the winter market. Today, we take a look at the supply and demand balance going into the winter gas market.
The availability of pipeline flow data makes the U.S. natural gas market uniquely positioned to grasp with reasonable accuracy where it stands with regional or national supply and demand on a daily basis. If you understand how to wrangle and finesse this robust data source, you can make a pretty good estimate of where the supply is, where it is headed, how it’s being consumed, and ultimately, what that all means for prices. Today we wrap up our series on natural gas production estimates and how the industry uses pipeline flow data to track gas production trends in real time.
In all sorts of commodity markets, buyers and sellers would give their eye-teeth to have access to accurate daily supply and demand data. Access to such data would provide insight into the utilization of transportation assets, transportation patterns and ultimately --- the holy grail of commodity markets – price. What if there was a commodity market where you could know supply and demand on a daily basis? Well there is. And it is the natural gas market. Gas market analysts have access to the luxury of pipeline flow data that (in the right hands) provides reasonably accurate estimates of daily supply (including production) and demand. In today’s blog, we explain how the natural gas industry uses flow data to track gas production trends in real time.
The acquisition of Williams Companies by Energy Transfer will create a midstream behemoth. The deal is expected to close during the first half of 2016 subject to regulatory approval. Once complete the main holding company Energy Transfer Corp (ETC) will be a C-Corp entity sitting atop Master Limited Partnerships (MLPs – see Masters of the Midstream for a more complete explanation of these structures) containing the assets of Energy Transfer Partners (ETP), Williams Energy Partners (WPZ), Sunoco LP (SUN) and Sunoco Logistics (SXL). The combined natural gas pipeline network will carry as much as 45% of U.S. Lower 48 dry gas production. Today we take a look at the natural gas infrastructure assets in the deal.
On Tuesday of this week the Energy Information Administration released its latest Drilling Productivity Report, projecting declines in US natural gas production volumes. Meanwhile, daily pipeline flow data shows gas production hitting record highs and gas storage fill could also be heading toward maximum levels. The CME/NYMEX Henry Hub natural gas price for the November 2015 is responding to these burgeoning supplies, settling yesterday at $2.518/MMBtu, near all-time lows for this time of year. Today we continue our look at the various sources of natural gas production data and what they tell us.
Depending on whom you believe, the international liquefied natural gas (LNG) market is either struggling through a period of oversupply and rock-bottom prices or poised for a new round of demand growth based on that low-cost supply abundance. (Hint: The answer may well be both of the above.) For electric and natural gas utilities that want to become LNG importers as quickly—and as cheaply--as possible, an increasingly popular option is buying or (more likely) chartering a floating storage and regasification unit, or FSRU. Today, we look at the growing use of FSRUs and how they may boost the LNG market.