We’ve spent a lot of time here in the RBN blogosphere discussing the trials and tribulations of natural gas producers in the Marcellus and Utica shales who are “trapped behind the pipe,” unable to get sufficient takeaway capacity to move supply to market (both within and outside the U.S. Northeast region) where they could get a higher price for their gas. Pipeline companies have ponied up billions of dollars to build lots of pipe to alleviate these constraints and much more investment is planned. Of course, those pipelines and their committed shippers hope that the investment will pay off long-term – that the economics for building the pipe will justify the cost. The pipeline will have scores of engineers, lawyers and accountants to figure that out. But what if you just want to make a quick-and-dirty estimate of the economics? Well, there is a way. In today’s blog, we walk through the factors you need to consider when your boss runs in and asks, “Hey—what would it cost to move gas there in a new pipe?”
There’s too much new liquefaction capacity coming online worldwide, too little growth in liquefied natural gas (LNG) demand, and it’s probably too late to prevent a multiyear period of LNG supply glut and low LNG prices. That’s not welcome news to those who have committed to long-term, take-or-pay deals with the new liquefaction “trains” set to come online in the U.S. and Australia in 2016-20, but it’s the reality. What’s making things worse yet is that new entrants in the LNG market are facing push-back from entrenched LNG and natural gas suppliers (Qatar, Russia and Norway) eager to retain market share (much like Saudi Arabia’s been doing in the crude oil market). There’s cause for longer-term optimism, though. Today, we begin an update on the international gas market.
U.S. natural gas production growth has spurred a massive build-out of natural gas pipeline capacity in recent years, and a lot more is on the way, particularly out of the Northeast. To Marcellus and Utica producers eager to improve returns on their investments, this incremental pipeline capacity is a long-overdue relief valve for the pressure that’s been building in the region from growing supply congestion and low prices. But pipeline development is an expensive, long-term endeavor, and few, if any, pipeline projects are slam-dunks. Also, market conditions initially driving the development of new takeaway capacity may change, putting a project’s relevance—and, in turn, its utilization and profitability—at risk. In today’s blog, we begin a look at how midstream companies and their potential shippers evaluate (and continually reassess) the economic rationale for new pipeline capacity in today’s very changeable markets.
With storage inventories soaring to record-high levels and production remaining relatively flat, the U.S. natural gas market is in dire need of record demand this summer to balance storage. All eyes are on power generation to soak up the gas storage surplus. Low gas prices and increased gas-fired generating capacity makes natural gas the go-to generation fuel this year. However, in the largest summer demand market – Texas – natural gas is facing increasing competition from wind. Wind power still provides a much smaller share of Texas’s power than natural gas, but the addition of several big wind farms in 2015 gives wind a stronger footing in the Texas market this year. Today we take a closer look at the potential impact of growing wind generating capacity on natural gas demand, particularly in Texas.
Northeast natural gas production has been averaging nearly 3.0 Bcf/d higher this year than last year, while demand has lagged behind due to mild weather. At the same time, storage inventories are running well above normal and there is little new takeaway capacity due online this summer. This means the Northeast is under pressure to balance excess supply in the region. In today’s blog, we wrap up our analysis of the Northeast supply/demand balance with a closer look at recent demand trends.
As U.S. electric utilities become increasingly dependent on natural gas-fired power, they’re looking for ways to mitigate the risk of future gas-price volatility. One hedging option that’s gained some attention lately is direct utility investment in natural gas production assets, the idea being that by acquiring gas-in-the-ground—especially now, when gas prices seem low and many financially strapped gas producers are eager to make deals—utilities can lock in the price of at least part of the future gas needs. Today, we consider the latest efforts by electric utilities to expand their gas hedging strategies—and hold the line on future gas prices—by including direct investments in gas production assets.
The Northeast has been the biggest driver of U.S. natural gas production growth in recent years, and while rig counts have come down, output from the Marcellus and Utica has remained resilient and helped offset declines in other supply regions. In the process, the Northeast has reinvented itself, shifting from a gas-thirsty consuming region to one of the biggest gas net producing regions in the U.S. But pipeline flow data indicates that Northeast production peaked in February and growth has flattened since then. Is the data signaling a long-term peak or is this a temporary lull? Today, we continue our analysis of the Northeast supply/demand balance with a closer look at recent production trends.
The U.S. Northeast natural gas supply/demand balance has been getting less and less short in recent years due to the onslaught of Marcellus/Utica production, and in 2015 flipped to net long supply for the first time on an annualized basis. That means the 15-state Northeast region as a whole produced more gas in 2015 than it used. Then, in the winter of 2015-16, the region reached another milestone when it ended the season net long supply for the first time. Now regional production may be flattening out and future growth is at risk as takeaway capacity projects face economic and regulatory headwinds. What does that mean for the Northeast balance going forward? Today, we begin a series analyzing the latest fundamental trends in the Northeast gas market.
Even in tough times like these, companies need to look ahead, to consider what steps they would take--or investments they would make--if, for example, oil prices were to rise to X dollars per barrel, or the cost of drilling and completing a well were to fall by Y%. For methanol producers, these “what-ifs” might include what if methanol prices (holding steady the past few months at $249/metric ton, or MT) were to rebound to where they stood a year ago ($442/MW in May 2015)? Or what if we could add new capacity at a fraction of the cost of new-build? Today, we consider how building more methanol capacity might make sense in the right circumstances.
The U.S. natural gas market is carrying about an 850-Bcf surplus in storage versus last year and the 5-year average. But it looks like the surplus will finally start to contract in earnest over the next few weeks. So the big question is -- will it be fast enough to prevent crippling supply congestion by this fall? With Canadian storage inventories also high and U.S. gas production still averaging slightly higher than last year, it seems record demand will be needed to bring storage into balance. Today we look at the prospects for demand this summer to trump last year’s record demand.
With the first month of storage injection season now behind us, the weekly storage report from Energy Information Administration (EIA) shows U.S. natural gas stocks at about 850 Bcf higher than last year. While the surplus vs. 2015 has contracted from over 1,000 Bcf at the start of injection season April 1, it has a long way to go before the gas market is out of the woods, and prices are reflecting that. The CME/NYMEX Henry Hub contract for June delivery settled Wednesday at $2.141/MMBtu, down 68 (24%) from last year, and the balance-of-summer strip is priced at an average $2.408/MMBtu as of yesterday’s settles, 48 cents (17%) lower than a year ago. Given the sheer size of the overhang at this point, the pace of the surplus contraction will be at least as important to price direction as the fact that it is contracting. Today we look at the various supply and demand factors that could either help or hinder the market to whittle down the storage surplus this summer.
Shell Chemicals is taking steps that suggest it finally may be ready to pull the trigger on a long-debated petrochemical complex which would include an ethylene plant (steam cracker) and three polyethylene units in the heart of the “wet” Marcellus/Utica natural gas liquids production region. If the $3+ billion project advances to construction soon, it would significantly impact ethane market dynamics, not just in Ohio/Pennsylvania/West Virginia but along the Gulf Coast too. And if it turns out we’re in for extended stagnation in drilling and production, the Shell cracker also may undermine plans to build additional NGL pipeline capacity out of the Marcellus/Utica—or any other cracker there. Today we discuss the likelihood of Shell proceeding with its Beaver County, PA cracker and the effects the project’s development might have.
More than 3,000 MW of new, natural gas-fired generating capacity is either under construction in New England or will be soon, but some of the gas pipeline projects that would ease long-standing constraints into and through the six-state region have hit rough patches. Kinder Morgan in mid-April suspended plans for its Northeast Energy Direct project, a “greenfield” pipeline across Massachusetts and southern New Hampshire, and a few days later the state of New York denied the co-developers of the already-delayed Constitution Pipeline—a key link between the Marcellus and New England--a needed water quality permit. The fates of some other major projects in the Northeast are uncertain too. Today, we provide an update on pipelines in the land of Yankees and Red Sox.
In connection with year-end 2015 earnings announcements, North American exploration and production companies (E&Ps) continued to announce large reductions in 2016 capital budgets. But the most dramatic news is that RBN’s analysis of a study group of 30 E&Ps indicates that these companies are finally expecting oil and gas production to fall in 2016 after a 7% gain in 2015. In today’s blog we update our continuing analysis of E&P capital spending and oil and gas production guidance.
The U.S. natural gas market ended the winter withdrawal season with inventories carrying a record high overhang and an enormous surplus versus previous years. Since then, the historic surplus has begun to contract, and the CME/NYMEX Henry Hub futures contract has responded, rallying 11.2 cents since April 1st to settle at $2.068/MMBtu Thursday. Now, well into the third week of injection season, the big questions are whether the recent bullishness can be sustained and what it will take to relieve the surplus in storage. In today’s blog, we assess how the existing surplus will impact summer storage activity and prices.