Concerns about climate change have taken center stage in recent years, with the global economy under mounting pressure from governments, investors, and the wider public to reduce greenhouse gas (GHG) emissions and transition to cleaner energy sources. With the understanding that a transition will take a long time and that the world will still need oil and gas in the interim, traditional energy companies are increasingly seeking ways to clean up their current operations as much as possible. That’s where responsibly sourced gas (RSG) comes into play — natural gas that is produced, gathered, processed, transported, and distributed in a way that meets the highest environmental standards and practices, resulting in reduced GHG emissions. In today’s RBN blog we’ll look at the emergence of RSG as an important opportunity for oil and gas companies looking to be responsible environmental stewards and how Project Canary’s certification standards measure their progress in achieving those goals.
In the past few months, there’s been a flurry of interest in certified responsibly sourced gas (RSG). RSG is natural gas — it still comes out of wells in the Marcellus, Haynesville, Permian, and other U.S. production areas. What distinguishes RSG is that its producers and pipeline companies have made efforts to significantly reduce the greenhouse gases — mostly methane — that are needlessly emitted along the value chain, and that an independent and respected outsider has certified the success of these efforts. RSG is still new to a lot of folks, including those in the natural gas business, so it’s reasonable to ask, who does the certifying, and what are the differences between them? In today’s RBN blog, we continue our series on RSG with a look at the different approaches taken by RSG certifiers: Project Canary and MiQ.
It seems that hardly a week goes by without another announcement on responsibly sourced natural gas (RSG). Either in response to rising interest among electricity generators, gas-distribution utilities, and gas-consuming industrials in procuring RSG or as proactive moves to boost their own ESG cred, a number of players in the gas sector — from producers to pipeline companies to LNG exporters — have been working to qualify their natural gas, their long-haul pipes, or their liquefaction plants for RSG status. A few producers have also been reaching deals to supply independently verified RSG to the market, with the expectation that at least a subset of gas/LNG buyers will be willing to pay the price premium involved. But all this is relatively new, and there’s still a lot that needs to be sorted out on the RSG front. In today’s RBN blog, we continue our series on RSG with a look at recent announcements and the associated challenges when selling RSG.
Given everything that’s happened lately on the ESG front — with a lot more expected — it’s safe to say that while hydrocarbons will continue to play an important role in the global economy for the foreseeable future, the companies that produce, transport and process crude oil, natural gas and NGLs will need to work much harder to minimize and mitigate their impact on the environment. Traditional energy companies have been scrambling to respond to the full-court press by investors, lenders and others to rein in and offset their greenhouse gas (GHG) emissions. In addition to establishing goals for slashing their GHGs, and taking steps to tighten their upstream, midstream, and downstream operations, they’ve offered and delivered “carbon-neutral” shipments of LNG, oil and LPG to overseas buyers, using “nature-based” carbon credits to offset their life-cycle emissions. Now, as we discuss in today’s RBN blog, there’s a big push by U.S. gas distributors and other buyers to shift to gas that’s been produced, gathered, processed and transported as cleanly as humanly possible.
Global gas and LNG prices are currently at record high levels. If we sound like a broken record, it’s because this epic bull run that started in the spring, has been roaring in recent weeks and showing little sign of slowing down. European prices have hit new post-2008 or all-time highs more than 25 times since late June, and prices in Asia, which had been at seasonal all-time highs for most of the spring and summer, finally last week also topped its previous all-time record from last January. A confluence of bullish factors, including high global demand, low storage inventories, weather events, and supply outages, have all contributed to the surge in gas prices. While many of these are near-term drivers and will eventually flip in the other direction, there is one bullish driver of global gas demand — European carbon prices — that will remain a constant in the years to come. That is by design because the carbon market is meant to serve as an incentive for the industry to seek greener solutions over fossil fuels. In today’s RBN blog, we look at the European Union’s Emission Trading System (EU ETS) and how it interacts with the global gas market.
New “Tier 3” requirements to limit sulfur content in gasoline are set to take effect in just over two months — on January 2017. In March 2013, the Environmental Protection Agency (EPA) proposed to limit the sulfur content of gasoline produced or imported into the U.S. to no more than 10 parts per million (ppm) from the current “Tier 2” 30 ppm standard by January 1, 2017. With these upcoming “Tier 3” requirements, refiners have been developing their strategies to meet the regulations and in some cases have already invested hundreds of millions of dollars in their facilities. Today, we look at the various approaches refiners can take for compliance and their impacts on the industry.
Arnold Schwarzenegger said “Hasta la vista, baby” to the governor’s office in Sacramento four years ago, but his 2007 executive order establishing a low-carbon standard for transportation fuels is only now starting to have a real effect on California refineries. Some refiners say the rule aimed at reducing “life-cycle” greenhouse gas emissions from the transportation fuel sector 10% by 2020 is unrealistic and could result in refinery closings and gasoline and diesel shortages. Others say California’s goal is achievable. Today, we consider the Golden State’s low-carbon fuel standard (LCFS) and what it may mean for refiners.
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.
A couple of months back in March 2013, the US Environmental Protection Agency (EPA) released proposed Tier 3 gasoline regulations that, if approved, will go into effect on January 1, 2017. The new rules include lower sulfur specifications for gasoline and tighter emissions controls for motor vehicles. Tier 3 also encourages acceptance of higher percentages of ethanol in gasoline. These regulations come at a time when US refinery gasoline blenders are jumping through hoops to handle a flood of new light shale crudes and increased demand for natural gasoline exports to Canada. Today we examines the proposals and their impact on gasoline and natural gas liquids markets.
Emission regulations require that companies planning new olefin crackers in EPA designated nonattainment areas like Houston must buy emission credits prior to construction. The market for credits in Houston for one criteria pollutant – volatile organic compounds (VOCs) skyrocketed from $4.5K/ton in 2011 to $300K/ton this month. The scarcity of emission credits and their rising price threaten to constrain or delay new petrochemical plant builds and will continue to hamper plant development and expansions in the Gulf Coast region. Today we describe the challenge new projects face.
Cheap feedstocks resulting from dramatic increases in US shale production of natural gas and natural gas liquids (NGLs) have led petrochemical companies to plan at least 7 new processing plants - known as olefin crackers - all but one on the Gulf Coast. These plants are expensive (think $billions) and take years to permit and build. They also produce significant quantities of emissions that are restricted by the Clean Air Act (CAA) – some of which trade in a market that has been skyrocketing for the past few months – threatening to delay or constrain the Gulf Coast cracker building spree before it gets started. Today we describe the regulations.
Does lightning strike twice? How about three times? Sure seems like the coal industry has been hit by three lightning bolts in the past several years: a recession that reduced demand for electrical power, low prices for competing fuels (i.e., natural gas), and new federal regulations on smokestack emissions. Today we review regulations that have left coal power generators singing the smokestack blues.
Last week (Feb 19, 2013) we explored California’s cap-and-trade program for Greenhouse Gas emissions (GHG) and saw that it has already increased electricity prices by 20% and pushed up the cost of refining a barrel of oil by $0.78/bbl. These developments are just the tip of the iceberg. California’s program will impact regional natural gas demand and basis. Companies will shift the locations where crude oil is processed. Power imports into the California market from the Pacific Northwest will soar. Today we’ll dive even deeper into the emissions market to better understand the outlook for GHG pricing and how the cap-and-trade rules are likely to influence all sorts of energy and fuel markets.
On January 1st, 2013, California’s cap-and-trade program for Greenhouse Gas emissions (GHG) went live and West Coast energy markets entered a whole new world. Wholesale electricity prices in California increased 20% as a result and other energy markets have felt the impact. For example, the new rules pushed up the average cost of refining oil by $0.78/bbl. For companies subject to the regulations, the bottom line is that if you generate GHG, you pay. But exactly who pays, how much you pay, and when you pay are all subject to a dizzying array of rules and regulations. Today we’ll navigate the turbulent and uncharted seas of California cap-and-trade markets.