A few weeks back Rusty Braziel sat down with Don Stowers, Chief Editor of Pennwell’s Oil & Gas Financial Journal, to talk about the big picture – some of the most important issues facing the oil and gas industry, the lasting impact of the Shale Revolution, and Rusty’s thoughts from 40-plus years in the energy business. It turned into the cover story of their June 2016 issue. Today, we recap a few of the interview questions. You can download the full article (along with Rusty’s smiling face on the cover) at the bottom of the blog.
The international market for liquefied natural gas (LNG) is in the midst of a wrenching transition. The old order, founded largely on long-term, oil-indexed contracts that called for certain volumes of LNG to be delivered by specified Point A to specified Point B, is being replaced by a new order characterized by intense competition among suppliers, new sources of supply (and demand), a glut of liquefaction capacity expected to last at least a few years, more spot purchases, and contracts incorporating destination flexibility—and, for many, tied to natural gas (not oil) prices. Today, we continue our exploration of the industry’s fast-changing dynamics with a look at the fierce battle now under way among LNG suppliers for market share, and at new approaches to pricing LNG.
It’s no secret that a long list of pipeline projects have been proposed to help move natural gas out of the Northeast production areas. But if you were a Marcellus or Utica producer, how would you decide whether you were interested in new capacity that hadn’t been proposed or built yet? Of course, pipeline companies have armies of engineers, cost estimators, and market analysts to bring one of these monster projects to fruition. But for anyone else, particularly in the early stages, how do you even know it’s a reasonable idea? For anyone testing a concept, you need a way to ballpark some scenarios for a new pipe. We’ve been running a blog series on our RBN Pipeline Economics Estimation Model, a quick, rule-of-thumb “sanity test” for new capacity. Today, we wrap up our walk-through of the model, with a real-world example to gauge the accuracy of the model, and then with a discussion on how the model can be used to measure economies of scale in picking the minimum volume you probably need for a new pipeline.
Over the past 20-some days, U.S. natural gas prices have gone from being the lowest in more than a decade to very close to last year’s levels. The July 2016 CME/NYMEX Henry Hub natural gas futures contract on Thursday (June 23) settled at $2.698/MMBtu, up about 70 cents (36%) from where the June contract expired ($1.963/MMBtu on May 26) and also up nearly 50 cents (23%) from where the July contract started as prompt month on May 27 (at $2.169). Market buying to unwind short positions initially kick-started the rally, but since then hot weather and a boost in power demand has kept the rally going. National average temperatures have averaged nearly 8 degrees (Fahrenheit, or F) higher in June to date versus May, and in the past week they’ve climbed above the peak summer levels normally not seen until mid- to late-July. Gas consumption on a temperature-adjusted basis also soared in the first half of June, led by power burn (gas use for power generation). The combination of hot weather and higher gas usage per degree of demand has been practically made-to-order for the oversupplied gas market, and has led to record power burn in June to date. But higher prices have the potential for bearish consequences—the recent gains have catapulted natural gas prices well above prices for coal on a cost-per-MMBtu basis—making the latter fuel more economically competitive in the power generation sector. That’s welcome news for coal producers, but what will it do to natural gas demand and in turn gas prices? Today, we look at the shift in the coal-gas price relationship and the potential impact to power burn and the gas market.
After the $5 billion-plus expansion of the Panama Canal is dedicated this Sunday, June 26, the first “New Panamax” vessel scheduled to pass through the canal’s new, longer, wider locks will be the Lycaste Peace, a Very Large Gas Carrier (VLGC) that is transporting propane from Enterprise Products Partners’ Houston Ship Channel export terminal to Tokyo Bay in Japan. What remains to be seen, though, is how many other supersized vessels carrying propane, liquefied natural gas (LNG) or other hydrocarbons will follow, and how soon. Today, we mark the formal opening of the newly enlarged Atlantic-Pacific short-cut with a look both at the game-changing potential of the expanded canal and the realities of today’s energy and shipping markets.
New and expansion natural gas pipeline projects have been part and parcel of the shale production boom in the U.S. Northeast. In fact, Northeast gas production could not have reached anywhere near its current level and become a major natural gas supplier to the U.S. without the substantial addition of takeaway capacity out of the Marcellus/Utica shale areas. At the same time, the competition among pipeline developers jockeying to be in the right place at the right time has been fierce. And now, low natural gas prices and uncertainty about future production growth have only increased the competition---not all projects will make it to in-service. The risks are higher for big pipeline projects, but so are the stakes. These days, the overall risk tolerance among shippers and investors is low, especially among producers. So if you’re a producer, how can you make sure you don’t end up on the wrong side of a transportation deal? In today’s blog, we continue our walk-through of the RBN Pipeline Economics Estimation Model. We’ll follow up in a later installment with a real-world test and other ways to use the model.
It’s been two years since Hawaii’s electric and natural gas utilities made their first, tentative moves toward ending their dependence on crude oil (for power generation and the production of synthetic natural gas) by shipping in liquefied natural gas (LNG) from western Canada and the U.S. mainland. While Hawaii Gas has secured state regulatory approval to ramp up the number of LNG-filled ISO containers it receives, the gas utility and Hawaiian Electric have so far failed to agree on a comprehensive LNG plan. Also, some state officials remain concerned that simply replacing oil with LNG will undermine Hawaii’s plan to get all its electricity from renewable sources by 2045. Today, we provide an update of the Aloha State’s fits-and-starts transition to LNG.
Crude oil and natural gas prices are back from the abyss, but does that mean the long awaited recovery is underway? Maybe so. But maybe not. Energy markets are fickle, driven by a chain of interactions where one market event triggers another, and then another. Rusty Braziel’s best-selling book, The Domino Effect, explores 30 such market events, which are represented by dominoes – hence the title of the book. More dominoes are falling now and still more will fall in years to come. This book explains the interconnectedness of energy markets through an analysis of energy market fundamentals: prices, flows, infrastructure, value, and economics. And good news for fans of audio books: The Domino Effect is now available on Amazon in Audible format. Today’s blog, an advertorial for the audio book, highlights what The Domino Effect has to say about what’s going on now.
The U.S. Energy Information Administration (EIA) on Thursday (June 9) reported a surprisingly bullish 65-Bcf injection for the week ended June 3—that was 8.0 Bcf below our Natgas Billboard estimate and more than 10 Bcf below the Bloomberg industry average assessment. In response, the CME/NYMEX Henry Hub July natural gas contract screamed about 15 cents higher following the report to a settle of $2.617/MMBtu, the highest daily settle for the prompt month in nearly 9 months. Thursday’s gains extended a rally that began on May 31 (2016) just after the July contract rolled to the front of the futures curve. It’s likely the rally was initially spurred by market participants looking to cover their short positions. But in the past week, an increasingly bullish fundamental picture has emerged prompting us to raise our price outlook (in our June 10 NATGAS Billboard report). In today’s blog, we analyze the fundamentals behind rising natural gas prices.
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.