Multiyear RFS proposal ‘a net positive’ for refiners
As the dust cleared following the release of the U.S. Environmental Protection Agency’s (EPA) draft multiyear renewable volume obligation (RVOs) targets under the Renewable Fuel Standard (RFS), market observers have ascertained the real winners—at least when it comes to the conventional implied ethanol proposals—are U.S. refiners.
“U.S. refiners can breathe a bit easier now as the EPA proposal keeps ethanol blending requirements at or slightly below 10% of gasoline demand instead of the original 11% range. While we do not believe the RFS is an issue to build an entire investment thesis around, the revised mandates are, in our opinion, a net positive for the domestic refiners by giving certainty to a significant regulatory risk for the industry,” Chi Chow, analyst for Tudor, Pickering, Holt & Co., said in a note to clients.
“The EPA is sending a clear message that it intends to set future RFS targets based on the realities of logistics and vehicle-compatibility constraints—and that’s a good thing for refiners,” Chow noted.
The EPA used its statutory waiver authority under the Clean Air Act (CAA) and proposed to reduce the total renewable fuel and implied ethanol mandate for 2014, retroactively, based on levels of production that actually occurred.
For 2015 and 2016, the EPA proposed to reduce the overall volumes of renewable fuels from those required in the CAA, taking into account E10 “blend wall” constraints while providing room for advanced and celulosic biofuels to grow and have certainty for investment going forward into 2016. In addition, for 2017, the EPA proposed RVOs for biomass-based diesel.
The EPA aims to issue final rules for the 2014, 2015 and 2016 compliance years by Nov. 30.
Refiners, along with blenders and importers of refined fuel products, are defined as “obligated parties” who must purchase Renewable Identification Number (RIN) credits to demonstrate compliance with the RFS to the EPA, which administers and enforces the program. Not only is the EPA’s latest multiyear RFS proposal seen as a positive for the U.S. refining industry as a whole, it is particularly good news for those with limited in-house ethanol blending capacity, notably Alon USA Energy, HollyFrontier Corp., PBF Energy Inc., CVR Refining LP and Valero Energy Corp., according to Chow.
“The refiners with higher percentages of purchased RINs should incrementally benefit from the potential easing of RIN prices,” Chow said.
—Bryan Sims
BNSF poised to handle impending oil ‘surge’
The crude-by-rail story is one that has certainly seen its ups and downs over the years driven by a host of factors such as weather, congestion, fatal accidents and commodity price volatility, to name a few. But BNSF Railway Co. CEO Matthew Rose knows his company is poised to tackle whatever the oil industry can throw at it.While he didn’t provide a specific time frame, Rose was adamant in disclosing to attendees at the recent U.S. Energy Information Administration’s (EIA) Energy Conference in Washington, D.C., that his company is more than prepared to accommodate a potential rebound in oil production.
“Assuming we see some market indicators—and we clearly will see it now with the price of crude—as it goes up, we’ll see people uncapping wells and start to frack the next well. We think we’re in a much better place to handle that next surge,” Rose said. One-third of all domestic crude oil production increases since 2009, according to Rose, have utilized railroads over pipelines to get product to refineries, which are performing at higher-than-normal utilization rates while seeing favorable margins converting those barrels of oil into refined fuels like gasoline and diesel due to cheap prices relative to the Brent global benchmark.
Crude oil production cuts and strong demand from refineries have led oil prices to rebound to about $60 per barrel (bbl) currently from a six-year low of less than $44 per bbl in March. BNSF handles the largest share of crude-by-rail shipments coming out of the Bakken Shale play.
Rose candidly provided comments on the U.S. Department of Transportation’s latest rule issued in the second quarter requiring a phase-out or retrofit of all legacy DOT-111 tank cars transporting crude oil and ethanol over the next eight years, by May 2023.
The final rule, developed by the Pipeline and Hazardous Materials Safety Administration and the Federal Railroad Administration, was broadened, extended and harmonized with Canada.
“It’s good to have certainty over the car design and the phase-out schedules,” Rose said. While he supports the overall scope of what the rule tries to accomplish, Rose takes issue with the requirement to have an electronically controlled pneumatic (ECP) braking system outfitted on a crude oil and ethanol rail car by Jan. 1, 2021. “It will be difficult to integrate ECP into our fleet of locomotives for crude and ethanol only without substantial risk of impact of network velocity. It will significantly limit how flexible we use these assets and we certainly realize the importance of the flexibility during our recent service issues. The rule will have to be changed in the future,” Rose said.
In total, Rose said BNSF aims to spend about $6 billion this year alone on rail line expansions, maintenance and renewal of assets, as well as locomotive and equipment upgrades. Maintenance and renewal of assets by far make up the biggest chunk of BNSF’s annual investments because the more capacity it adds to haul freight the more it costs to maintain. In 2015, nearly half of its investments ($2.9 billion) will go toward renewal of its assets and maintaining things like replacing rail ties. In 2014, BNSF spent around $1 billion total on network expansions. Rose said BNSF has already surpassed that amount at the midway point of 2015 ($1.5 billion).
“We can expand the network to take more volume for a long time to come. Our model is to build the railroad for growth, grow the business and reinvest those revenues back in the network where it’s needed, when it’s needed. Sounds straightforward, but it’s not without risk,” Rose said.
South America lacks adequate LNG demand
Grand expectations must reconcile with reality, according to an analyst, especially when new LNG supply from North America interacts with uncertain worldwide demand. South America might provide a home for some of the new capacity, even if nations are more inclined to pipeline natural gas imports and renewables.
A whopping 47 billion cubic feet per day (Bcf/d) of liquefaction capacity has been proposed in the U.S., an amount that dwarfs last year’s total worldwide trade of only 35 Bcf/d.
Javier Diaz, a manager of energy analysis and consulting at Bentek Energy, expects about a quarter of the proposed U.S. capacity to make it to construction and eventually liquefaction. There simply isn’t enough room in the world market to accommodate it all.
By his appraisal, the more realistic estimate includes Cove Point on the U.S. East Coast; the first five trains of Sabine Pass LNG and trains 1 through 3 of Cameron LNG, both in Louisiana; the first three trains of Freeport LNG in Texas; and finally, the first two trains of Corpus Christi LNG. Of the contracts from those projects so far, 4.1 Bcf/d will be dealt to portfolio players, 2.4 Bcf/d will find end users in Japan and 1.6 Bcf/d will be sold to Spanish companies.
The oil price drop has also affected U.S. proposals. Before the commodity price swoon that began last fall, the average savings for a gas price-based, a Henry Hub linked contract vs. a traditional oil-linked contract to Asian LNG buyers was about $2.24 to $2.74 per million Btu.
Now, however, the oil price drop has largely wiped out that price advantage. Moreover, Bentek expects U.S. projects will be competitive with oil-linked projects at a $78 per bbl oil price, but when it incorporates the sunk costs on terminals that are currently under construction, oil needs to only be at $54 per bbl to be competitive in 2020.
Canada, like the U.S., is also finding itself adjusting expectations. Close to 20 projects have been proposed for some time, but it is only recently that one has decided to make the plunge—sort of. Canada was originally well positioned to take advantage of Asian LNG price arbitrage, banking on its available cheaper gas and lower transportation costs. Yet, the opportunity window for British Columbia projects is closing, according to Diaz.
The projects there didn’t react quickly enough to what Asian buyers were looking for: destination flexibility and diversified price structures with a break from oil links. Moreover, the high infrastructure costs, including monstrous pipelines, added to an already swelling potential bill. In the medium term, this lack of alacrity let Australian projects come in and swoop up the market.
Ethane’s obstacle course continues
Ethane continues to hover around the price floor, but relief is in sight in the form of seven steam crackers currently under construction, Kendall Puig, senior energy analyst with Bentek Energy, said at Platts’ Benposium conference in Houston. Once the new crackers come online, current ethane rejection rates will need to decrease to meet a new incremental demand of about 590,000 bbl/d.
However, investors in infrastructure to get ethane from the wellhead to Gulf Coast processing plants, as well as the new crackers themselves, will need to recoup construction costs by charging fees that current ethane prices simply will not support.
“You have to flow ethane on a pipeline and these pipelines have costs associated with them, they have tariffs,” Puig said. “Ethane prices will need to cover both fractionation fees and the cost of flowing on these pipelines.”
That cost varies significantly depending on where the ethane originates. The transportation cost from the Rocky Mountains to the Gulf Coast region is about 14 cents per gallon, Puig said. Moving ethane from the Marcellus and Utica shales in the Northeast on Enterprise Products Partners LP’s ATEX Pipeline is pricier, at about 22 cents per gallon. Transporting ethane from the Williston Basin is the most expensive option at about 26 cents per gallon.
“When ethane rejection starts to decrease and more ethane is necessary to fill domestic demand, ethane prices will need to rise to cover these transportation and fractionation costs,” she said. According to Puig, PADD 3 and PADD 2, or the Gulf Coast and Midwest, respectively, will likely see the first decreases in ethane rejection due to the relatively lower transportation costs from the regions. The next areas to follow will likely be the East Coast and Rocky Mountain regions, or PADD 1 and PADD 4, respectively. The Williston Basin’s high transportation costs make it the last likely candidate for decreased ethane rejection.
Marcellus, Utica step onto world’s gas stage
With Marcellus and Utica dry gas production at a combined 17.5 Bcf/d, the Appalachian Basin’s plays are stepping into the global spotlight.
The attention comes as the world’s energy players gear up for an anticipated surge in gas demand, which could rise by 1.9% annually reaching 497 Bcf/d by 2035, according to BP’s “Energy Outlook 2035.” While forecasters believe most of the demand growth will come from outside of the continent, the supply of shale gas will be dominated by North America—led by the Marcellus.
“The speed and the magnitude of the growth of the Marcellus gas production have caught everyone’s attention. The size of the resource is clearly large and that attracts market,” said John Staub, E&P team leader for the EIA’s Office of Natural Gas and Biofuels.
But the cost of producing these resources is already impacting how the energy industry and energy marketplace work, he said during Hart Energy’s DUG East conference. Shale gas production has grown from being 5% of total U.S. dry gas production to 56% in 2015. The Marcellus gas portion is the largest, he said, adding it drives home the importance of the Marcellus and Utica. Data from the EIA’s latest drilling production report projected about 16 Bcf/d will be produced in the Marcellus alone in July, up from about 15 Bcf/d in July 2014. The amount is more than twice that produced in the Eagle Ford or the Haynesville shale plays. In addition, the estimated ultimate recoveries (EUR) of wells in recent years have been improving. About 1,200 Marcellus wells had a mean EUR of 0.39 Bcf per well in 2008. Five years later, the EIA found that the mean EUR jumped to 6.37 Bcf per well
while the number of wells fell to 302. Shale resources are expected to continue dominating U.S. gas production growth, based on the EIA’s Annual Energy Outlook (AEO) 2015. Through 2014, about 64 trillion cubic feet (Tcf) of gas was produced from U.S. shale plays and in the AEO reference case growth continues through 2040, reaching a total production of about 459 Tcf, Staub said.
“In the high resource case, where we assume you can drill twice as many wells and the wells are 50% better than the average today, we end up producing 200 Tcf of additional gas from shale and tight oil plays,” he said. “Low oil prices don’t dent the gas production very significantly.”
By 2040, the EIA outlook shows Marcellus dry gas production at 147 Tcf, followed by Haynesville/Bossier with 70 Tcf and the Eagle Ford at 52 Tcf. The Utica is forecasted to have a cumulative production of about 27 Tcf.
Gas prices are not expected to deter growth. The EIA forecasts the Henry Hub gas price could double to about $8 per thousand cf, which allows for further long-term development by 2040.
“All of that matters for exports,” Staub added. “Natural gas exports are one opportunity for finding value for the resource that we have. We have exports growing to a little under 8 Tcf per year.”
What is also uncertain is where hydrocarbon supplies will end up. Currently, supply is outpacing demand.
“This is an oversupplied oil market which in turn reduces the interest and opportunities to build export facilities or start planning to develop export facilities for natural gas,” Staub said.

Crude by rail helps West Coast oil shortfall
Crude oil production in PADD 5—the western U.S.—continues a slow decline and crude- by-rail shipments are helping to make up the difference, according to the EIA. West Coast oil imports also are increasing, the agency said.
The PADD 5 oil production drop differs markedly from the rest of the nation, where rising production from unconventional plays has turned around a decades-long fall in crude output that began in the early 1970s. U.S. crude production increased by 3.2 million barrels per day (MMbbl/d) from 2012 to 2014, EIA statistics show. In comparison, PADD 5 output dropped by 100,000 bbl/d in the same four-year period, primarily due to a decline in Alaska North Slope (ANS) crude production. North Slope output peaked at 2 MMbbl/d in 1988 and has declined steadily since, averaging 479,000 bbl/d last year. The drop has created operating problems for the giant Trans-Alaska Pipeline that moves North Slope crude 800 miles south to the ice-free port of Valdez, Alaska. The crude is then shipped primarily to West Coast refineries. The 48-inch pipeline has an operating capacity of slightly more than 2 MMbbl/d.
North Slope production for March, the most current monthly number available, ticked up slightly to 491,580 bbl/d, the EIA reported. No major pipelines link West Coast refiners with oil-producing regions east of California. That regional production drop off has left the three major West Coast refining centers—Puget Sound, San Francisco and Los Angeles—in a feedstock bind. Crude imports to the West Coast were fairly rare 20 years ago but now average 1.1 MMbbl/d, primarily from Saudi Arabia, Canada, Ecuador, Iraq and Colombia, according to the EIA.

Wolfcamp leads pack of Permian trends
Permian Basin players are high on the potential of the Wolfcamp Formation, believe rapid-fire advances in technology will ultimately defy economic modeling that results in pessimistic forecasts, and note that oil-field service companies seem intent on positioning themselves to be the new best friends of upstream and midstream operators.
These are some of the trends identified in a panel discussion during the midstream program of Hart Energy’s recent DUG Permian Basin Conference in Fort Worth, Texas. “We’re primarily focused on the North West Shelf, just north of the Delaware Basin,” said E. Will Gray, CEO of Midland, Texas-based Dala Petroleum Corp., an E&P focused on the Midcontinent and the Permian Basin. “There is still is an oversupply in that area. Right now, a lot of the tier 1 that’s being developed is in the Delaware [Basin] where Concho and other E&Ps are doing a great job of unlocking value.”
The high-gravity characteristics of Permian crude bring challenges and opportunities, said Ken Snyder, vice president of business development for Tulsa, Okla.- based Frontier Energy Services LLC, a full-service midstream company. “In the Delaware Basin, we’re finding a lot of high-gravity crude, 50-plus, mainly in the Wolfcamp down along the Texas-New Mexico state line and just south of that around Orla and West Orla, [Texas],” he said. “There is tremendous well potential there. The wells are coming in really large—1,000 [bbl/d] to 1,500 [bbl/d] initial production rates—so those are worth going after. Even with the lower crude prices, you can still afford to produce some of that crude.”

Institutions drive midstream M&A shift
At the recent Mergermarket Energy Forum in Houston, panelists told attendees how they expect the recent large structural changes from some of the biggest midstream players to impact the M&A space. With the recent announcement from The Williams Cos. Inc. that it would roll up Williams Partners LP into a C corp in a transaction similar to last year’s announcement from Kinder Morgan Inc. that it would absorb its MLPs, the future landscape of midstream transactions as they relate to MLPs seemed in doubt.
Close behind, Williams rejected a $53.1 billion buyout from Energy Transfer Equity. It’s unlikely that these transactions signal the end of MLPs in midstream, however. The creation of new MLPs is still “outstripping MLP collapse,” Will Bousquette, managing director, Goldman Sachs, told the audience. The Williams and Kinder Morgan transactions were unique in that they were “mature MLPs that had reached a point where the burden from the general partner was making it difficult for the MLP to grow because the IDR [incentive distribution right] burden with the general partner had gotten to a very high percentage of total cash flows,” he said. The larger midstream M&A market will instead be defined by the current “massive shift in the ownership of midstream from something that was primarily controlled by retail equity investors to something that is primarily owned by institutional equity investors,” he said. The change in investor type is leading to a shift away from traditional expectations of “yield-based valuations and relatively slower growth” to the expectation of much more significant growth, Bousquette added.
The growth expectations from institutional investors can be difficult to meet, as the cascade of recent MLP IPOs has increased competition for available acquisition targets.
“Basically, having more MLPs with robust valuations, the IPO window’s been opened,” said Jeremy Goebel, managing director, business development and strategic planning, Plains All American Pipeline LP. “These are small companies looking to gain critical mass, so they’ve been very aggressive with new entrance into new basins or business lines.

Report outlines Canada’s energy challenges
Canada’s oil and gas operators—like those worldwide—must adapt to sagging commodity prices that alter assumptions about the future. A new report by the Canadian unit of PricewaterhouseCoopers (PwC), e titled “Compete, Survive or Prosper?” offers some projections for what may lie ahead for the Canadian industry.
The report summarizes interviews with 15 Canadian energy thought leaders from the upstream, midstream and field service sectors on what they see ahead. The accounting and consulting firm released the study recently at its 6th annual Energy Visions Business Forum in Calgary.
Midstream participants included Al Monaco, president and CEO of Enbridge Inc., and Stewart Hanlon, president and CEO of Gibson Energy Inc. “What we found was that the industry is learning how to navigate through a new reality,” said Reynold Tetzlaff, national energy leader for PwC Canada. “Given the duration of this downturn, the Canadian industry as a whole needs to manage costs, address global access and find ways to attract global investment.”
The recent flood of light oil from U.S. shale plays, coupled with growing production of heavy oil from Canada’s oil sands, “caught the world by surprise,” Hanlon observed in the report.
Several of the executives questioned whether U.S. shale oil production will flatten out or even decline in the near future. In contrast, most saw the large-scale, long- lead time Canadian oil sands projects continuing to increase production in the foreseeable future. Darren Andruko, deputy CFO and treasurer at Husky Energy Inc., quoted estimates of an incremental increase of 400,000 bbl/d of oil sands and bitumen from northern Alberta.
Long-term projects can ride out price downturns, but they have special problems of their own, Monaco said in the report.
“The longer a project takes, the more uncertain it is,” he said. “That’s going to drive up your cost of capital and it’s going to increase volatility, which has more of an effect on cost of capital and things are just not going to get done.”
However, a number of issues continue to constrain the industry, including restricted market access, higher production costs, availability of labor and global competition, according to PwC.
Some of the reflections that emerged include:
• Cost structure is a primary area for ensuring continued survival;
• Government plays a role by providing a cohesive energy strategy, building public awareness about the importance of resource development, providing the right fiscal, tax and regulatory regimes;
• One of Canada’s main advantages is its excellence in technology use; and
• The nation’s energy industry has the fundamentals to emerge strongly from the current downturn, but changes are needed.

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