OPIS Headlines

May 10, 2017
RFA Pushing Back Against 'Misinformation' from Boating Industry

With U.S. boating industry groups lobbying for increased restrictions against ethanol blends in the gasoline pool, the Renewable Fuels Association (RFA) is pushing back against what it calls "misinformation" about the use of ethanol- blended gasoline in marine engines.

RFA launched a campaign this week with a two-page ad in the latest issue of Marina Dock Age it says is designed to educate consumers on the use of a 10% ethanol blend in marine engines. The ad comes less than a week after a group of recreational-boat owners and fishing groups sent a letter to President Donald Trump asking for changes to the Renewable Fuel Standard (RFS), including capping at 9.7% the amount of ethanol that can be blended with conventional gasoline.

Several groups in the boating industry also come out strongly against a year- round Reid Vapor Pressure (RVP) waiver for higher blends of ethanol such as E15.
RFA vice president of Industry Relations Robert White said those efforts actually hurt their calls for more pure gasoline (E0).

"If you want more E10 or more E0 in the marketplace, you should be the biggest fan ever of E15 and E85," White said. "If the obligated parties under the RFS (Renewable Fuel Standard) want to sell more E0, then how do they do that? They sell higher blends of ethanol to offset the E0 sales. Because without it, they're going to have to buy a RIN and jack up the price of E0."

E0 typically costs 20cts to 60cts more than E10, perhaps to offset the roughly 40ct cost of a Renewable Identification Number (RIN) ethanol credit, sources said.

White said the main concern from the boating industry tends to be the possibility of retailers switching from E10 to E15 or misfueling. But he said with July being the five-year anniversary of E15 being in the market, not one retailer has dropped E10 entirely for E15 and not one boat has reported an issue of misfueling. 

"Despite what they may or may not have heard, E10 will always be an option,"
White said. "It has the largest required fueling label on the market. All consumers need to do is spend three seconds to make sure they're buying the right fuel at the pump."

Small engines -- including motorcycles, boats, lawn mowers and other applications -- make up approximately 3% of the gasoline demand market by most estimates, but the boating industry has long been a particularly vocal opponent of ethanol.

"Our latest ad is a good example of helping push back on misinformation, not just inside the Beltway, but for the boating community, in general," White said.
"There just have not been the problems that they have been spooked about."

In its outreach efforts, RFA is also a co-title sponsor of the Crappie Masters fishing tournament.

"There continues to be misinformation on ethanol and boating that our critics spread in the hopes of confusing consumers, but the truth is that for nearly 30 years, 10% ethanol has been used in all types of marine engines," RFA President and CEO Bob Dinneen said.

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May 4, 2017
Market Will Tell Propane that it Needs to Be Stored: Enterprise

Mont Belvieu propane prices may need to strengthen relative to international levels to slow down export rates amid industry concerns over inventory levels by winter.

Enterprise Products, when asked during their latest earnings call on expectations that propane balances could tighten this winter, specifically if there is not enough U.S. supply to meet LPG exports running at 850,000-900,000 b/d without drawing down inventories, replied that there has been less opportunity this year to secure near-term propane to store at Mont Belvieu.

"Frankly, we haven't had the opportunity to do as much [contango], I don think, the first quarter as we did last year. But it is in our playbook," commented Enterprise CEO Jim Teague.

Senior Vice President of Liquid Hydrocarbons Marketing, Brent Secrest, said: "The market has not sold propane that needs to be stored yet. And so we just started to see some stuff happen," noting that they have begun seeing cancellations for the month of May.

"The market will tell propane that it needs to be stored, so that they can get geared up for this winter," he said.   

Market sources told OPIS that at least eight VLGC-size cargoes (about 550,000 bbl) of propane scheduled to load this month have been canceled at the terminal by term contract holders, due to poor international arbitrage margins. A handful of cancellations and/or deferrals were also reported at other U.S. Gulf Coast export terminals.

OPIS Mont Belvieu non-TET propane anys settled at 60.8125cts/gal on May 3, while northwest Europe CIF ARA propane closed at 66.41cts/gal ($346/t) and CFR Japan at 76.20cts/gal ($397/t).

Current U.S. propane/propylene stocks stand at 39.7 million bbl, down 32.2 million bbl from the same time last year. Stock building is taking place later than usual, with the last four weeks of April in 2017 recording a draw of 1.9 million bbl compared to an 8.6-million-bbl build in 2015 and 7.0-million-bbl build in 2016. 

Sources anticipated that double-digit cargo cancellations each month are likely to continue throughout summer.  

"10 per month going forward now, at least," commented one source. "There is no money to be made for traders," the source added. 

One market pundit questioned whether a steady cancellation rate of 10 cargoes per month will be enough for Gulf Coast stocks to get to 75-80 million bbl to start winter.

"There's going to be some decent volatility this summer from exports," a source stated.

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April 26, 2017
Midwest Gasoline Stocks Draw for 8th Week; Jet Inv. Hits Highest Since 2012

Gasoline stocks in the U.S. Midwest posted an eighth consecutive weekly decrease, the latest U.S. data showed, as refiners and blenders continued to draw down winter-grade material to make summer specs in anticipation of increases in traveling demand.

Total gasoline stocks in PADD 2 (Midwest) fell by 555,000 bbl, to 55.33 million bbl in the week ended April 21, down about 1 million bbl compared to 54.4 million bbl in the week a year ago, according to the Energy Information Administration's weekly petroleum status report.

Mogas inventories across the nation typically fall around this time of the year. In 2016, Midwest stocks were drawn for 13 straight weeks between mid- February and mid-May.

This year's rate of decrease was slower than that of 2016. In the last eight weeks, Midwest gasoline stocks fell by 4.89 million bbl, compared to a drop of 5.48 million bbl during the same eight-week period in 2016, EIA data show.

Meanwhile, gasoline production rose for a second week, up 75,000 bbl, to 2.593 million b/d, up from 2.364 million b/d in early March when mogas stocks began to draw.

PADD2 refinery utilization rose by 1.9pts, to 95.7%, up more than 12pts compared with 83.4% a year ago, EIA data show. The weekly increase was most likely related to completion of maintenance at BP's bellwether Whiting refinery in Indiana and Phillips 66's Wood River refinery in southwest Illinois.

Turning to jet fuel, Midwest inventories posted a build of 505,000 bbl, to 8.092 million bbl, the highest since November 2012.

OPIS noted the gradual increase in jet fuel could indicate the ongoing jet fuel stability (JFTOT) issues that have plagued supplies to Chicago-area airports for nearly a year might have been resolved, as the fuel is now flowing into storage again.

JFTOT issues refer to delayed jet fuel deliveries into Chicago while the batches are required to go through extra testing.

In July 2016, sources said that tanks in Chicago are filled with jet with no place for to go, forcing Explorer Pipeline to cancel a shipping cycle. The backlog was related to testing of fuel staying in storage longer than usual.

Other than JFTOT, there are no specific fundamental reasons behind jet fuel's gradual increase this year, said Midwest participants.

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April 20, 2017
U.S. Summer Gasoline Off to Slow Start; Course for Season May Change

The U.S. summer gasoline market is off to a slow start, based on the current prices, demand and supply fundamentals so far.

It is noted that while current gasoline market appears bearish, it is relatively more favorable compared with the same time period a year ago when the market was suppressed by an oversupply.

The current U.S. gasoline market reflects the prevailing supply overwhelming demand. The bearish market sentiment, at least for now, is backed up by a surprising increase in the weekly gasoline stocks in mid-April when stocks should start falling based on the historical trend. However, the slow start may not dictate the tone for the rest of the summer season as peak demand later in July-August could clean up the "oversupply."

The NYMEX front-month RBOB price spread was at a slight contango of about 10pts/gal, narrowing from about minus 50pts seen earlier this week. For the last three years, the NYMEX RBOB front-month gap was at a contango in mid-April, reflecting a supply overwhelming demand scenario. In mid-April 2015, the front- month spread was at a 4ct backwardation.

The Northeast gasoline market switched to lower-RVP summer grade from higher-RVP winter gasoline in mid-April.

"The market normally sees a stockbuilding trend in winter and spring in preparation for the peak summer demand season, but the problem is a stockbuild in early summer from already high inventory," a trader said, pointing to the blip in higher U.S. gasoline stocks last week.

U.S. gasoline inventory for the week ended April 14 rose by 1.5 million bbl from the previous week, according to the Energy Information Administration. For the past few years, April gasoline stock data had typically shown a falling trend. It remains to be seen if U.S. gasoline stocks will continue to build for the rest of April.

Traders noted that the rising stocks were attributed to higher domestic gasoline output and strong import flow.

Gasoline imports for the week ended April 14 jumped to 843,000 b/d, the highest so far this year, according to EIA.

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March 29, 2017
April Gasoline Could be Compelling, or Cruel

Anyone with more than a cursory interest in the gasoline business recognizes that 2016 set a standard for average daily demand of just over 9.327 million b/d or nearly 392 million gallons daily. But very few marketers and analysts remember a particularly notable spring disappointment. Gasoline demand in April 2016, without clear reason, dropped from March, representing the first significant third-to-fourth month slide in 10 years.

The drop was a significant 186,000 b/d and resulted in April domestic demand of 9.213 million b/d, compared to the 9.399 million b/d reading for March 2016. Every other April since 2007 produced a surge in motor fuel demand with the odd exception of 2011 where April lost about 3,000 barrels per day of consumption versus its predecessor.

So, the last 10 years have delivered an average April gasoline "lift" of about 100,000 b/d, and if you take away the outlier 2016 year, the lift moves up to 114,000 b/d. Nearly all of the weekly data sets from 2016 have implied erosion from year-ago demand levels, ranging from a percentage point to as much as 5%-6% in the dead of the winter. Under the best of circumstances, gasoline demand can soar by over 300,000 b/d in April, as it did in 2010.

Hence, there is a sense that gasoline prices may be teed up for take-off, particularly since year-on-year retail price premiums have narrowed to about 25cts or less nationally. High employment, the stubborn refusal of the public to migrate to smaller more fuel-efficient vehicles and the highest consumer confidence in 16 years all could coalesce and lead to an April demand record. Ironically, that would break the record that was established last year, even after the drop from March.

March to April Demand Changes: 2007-2016 (EIA Monthly Data)
2007 + 37,000 b/d
2008      + 46,000 b/d
2009      +126,000 b/d
2010      +315,000 b/d
2011      -  3,000 b/d
2012      +159,000 b/d
2013      +214,000 b/d
2014      +258,000 b/d
2015      +132,000 b/d
2016      -186,000 b/d

EIA's just-released estimate of gasoline demand for the seven days ending March 24 gives bullish traders some hope. EIA today measured gasoline deliveries at a very robust 9.524 million b/d, by far the highest number this year. Last year saw that demand level exceeded 22 times, but we topped 9.524 million b/d only nine times in 2015 and just once in 2014.

There are two wildcards that are probably keeping nervous speculative gasoline buyers at bay. One comes when analysts look at the stealth amount of refinery capacity "creep" that has increased U.S. refining capability by more than 1 million b/d since April 2007. Back then, the limits of U.S. processing were listed at under 17.5 million b/d, whereas current capacity is 18.508 million b/d.

And thanks to a crude slate that depends a lot on light tight (gasoline-packed) shale blends, it will not be unusual to see total gasoline output (refined and blended) numbers exceed 10 million b/d in the driving season.

The other wildcard is much less predictable and a relative newcomer to the bouillabaisse of ingredients that determine gasoline prices.

It's the two-sided card of imports and exports. Exports of finished gasoline and blending components were negligible until the last few years, with routine departures of less than 200,000 b/d of motor fuel in the 2001-2010 decade. We'll get new January 2017 export data on Friday, but December saw 927,000 b/d of finished gasoline exports, supplemented by another 98,000 b/d of gasoline components. Gasoline traders don't believe that December is a proxy for spring, but they would not be surprised to see exports of 500,000-750,000 b/d of gasoline in the second quarter.

Imports are a bit more mysterious, but there is a clear ongoing decline in arrivals from Europe and Canada. Generally, most gasoline traders are anticipating that gasoline import levels will remain under 500,000 b/d in most weeks, with the exceptions coming in reaction to strong rallies in U.S. coastal markets.

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April 13, 2017
LCFS Weekly Trade Activity Slows, Prices Move Lower: CARB

Low Carbon Fuel Standard (LCFS) credit prices in the week ended Sunday fell from the previous week as trading activity also thinned, according to data released late Tuesday by the California Air Resources Board (CARB).

The volume weighted average price fell $8.28 to $86.84/credit in the week, the agency said, adding that the total value of the transfers in the week was $7.53 million, down from $21.91 million in the previous week.

The agency said 86,749 credits were transferred in the most recent reporting week, down from 230,331 credits transferred a week earlier. The 14 reported transfers in the week also were slightly less than half than the 29 reported in the prior week.

OPIS Wednesday assessed the LCFS credit at $79/credit, down from $86/credit one month earlier. Credit prices tumbled in late March and early April after a California appeals court issued a tentative ruling in a lawsuit brought by ethanol producer Poet that some believe could create uncertainties over elements of the LCFS program.

But a final ruling released earlier provided a more LCFS-friendly decision than had been expected by most in the market, and the credits saw stronger buying interest in the past two trading sessions as offers have crept higher, sources said.

According to CARB, LCFS credit prices steadily moved lower throughout last week, with the first posted trade coming in at $94/credit (for 980 credits) and the last posted trade at $79/credit (5,000 credits).

CARB's weekly report excluded eight transfers for a total of 19,932 credits that were reported at zero or near-zero prices.

For the weekly report, CARB considers the date the transfers were fully completed rather than the date they were posted, which can vary.

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April 5, 2017
Planned Maintenance Underway at ExxonMobil Joliet Refinery in Illinois

ExxonMobil Corp.'s 260,000-b/d Joliet refinery in Illinois, one of the largest refineries in the Midwest, is currently undergoing planned maintenance works, a company spokeswoman told OPIS on Wednesday.

"We are undergoing short-term scheduled maintenance. All customer commitments are being met," Tricia Simpson said in an email statement.

In response to an OPIS inquiry, Simpson added that the company does not comment on the details of ongoing operations.

Earlier, one trading source suggested the loss of a production unit at an Exxonmobil refinery was a reason for stronger Chicago RBOB and premium gasoline grades.

Looking at Chicago premium grades, April cycle-two 9-lb. premium unleaded gasoline was last talked at 14.50cts/gal above May RBOB futures, strengthening by nearly 5cts/gal from Tuesday's mean, based on sharply higher offers.

Prices of premium unleaded gasoline, also known to spot participants as "P91" based on its octane rating, were at $1.86/gal at presstime.

Premium RBOB VOC-controlled gasoline, whose prices tend to move in tandem with P91, also saw similar gains in basis levels.

Turning to CBOB regular gasoline, cycle-two barrels were last assessed at 6cts/gal under the May Merc, based on the level of a confirmed Buckeye Complex deal.

Current CBOB cash differentials were about 1.75cts/gal weaker than where the market left off as April's first-cycle timing expired at the end of Tuesday.

On Tuesday, OPIS reported that BP Plc's 430,000-b/d refinery in Whiting, Ind., is experiencing a minor issue on crude distillation units that is affecting its normal production.

Located in Channahon, Ill., Joliet is the second-largest refinery in close proximity to Chicago after BP Plc's 430,000-b/d Whiting refinery. Joliet refinery has a crude distillation unit, fluid catalytic cracker, coker and a reformer, which is used to produce high-octane gasoline, according to ExxonMobil's website.

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March 29, 2017
Pembina Plans $242 Million Western Canadian Oil Pipeline Expansion

Pembina Pipeline Corporation said that it is planning a C$325 million (US$241.745 million) expansion of its pipeline infrastructure between Lator, Alberta and Namao, Alberta, related to its Phase III Expansion project in Western Canada.

It also provided an updated outlook for 2018 adjusted EBITDA and cost savings on capital projects. Its board of directors approved a 6.25% increase in its monthly common share dividend rate (from C$0.16 per common share to C$0.17 per common share), the company's sixth consecutive annual increase.

Mick Dilger, Pembina's CEO, said, "These developments build on our already strong start to 2017. We are encouraged by the level of volumes and business development activity we've seen in the early months of the year and our confidence in the outlook for Pembina continues to grow with the near-term completion of large-scale capital projects."

Pembina's 420,000-b/d Phase III Expansion is nearing completion and continues to trend slightly under budget, with an expected on-time in-service date of July 2017, the company said. Given ongoing customer demand for capacity, Pembina is proceeding with two projects for a total estimated capital cost of C$325 million: the Fox Creek and Namao Pump Stations (Phase IV Expansion), which comprises two pump stations on the newly installed 24-inch-diameter pipeline from Fox Creek to Namao, Alberta, and the Lator to Fox Creek Expansion (Phase V Expansion), which is a new, approximately 95-kilometer (59 mile), 20-inch- diameter pipeline from Lator to Fox Creek, Alberta. Both of these projects are underpinned by long-term, take-or-pay contracts.

The Phase IV Expansion is expected to increase capacity between Fox Creek and Namao by approximately 180,000 b/d, Pembina said. The estimated capital costs for the two pump stations is approximately $75 million. Subject to regulatory and environmental approvals, Pembina expects to place this expansion into service in late 2018. Pembina has the ability to further expand capacity between Fox Creek and Namao by adding additional pump stations.

The Phase V Expansion is aimed at addressing the current capacity constraints between Lator and Fox Creek and supporting future growth in the Montney and Deep Basin resource plays, Pembina said. This C$250 million project is expected to provide approximately 260,000 b/d of additional capacity in this corridor and access to Pembina's downstream capacity at Fox Creek. Pembina has received regulatory and environmental approvals for the Phase V Expansion and clearing of the right-of-way is approximately 50% complete. The company expects to bring this pipeline into service in late 2018.

In late 2015, Pembina's secured capital program comprised C$5.3 billion of new assets which were scheduled to come into service through 2016 and 2017. Based on this capital program, the company provided EBITDA guidance indicating that, once in-service, these projects could generate an incremental run-rate annual EBITDA ranging from C$600 million to C$950 million in 2018, with the upper end of the range depending on utilization above take-or-pay levels and commodity prices.

At the time of these disclosures, the outlook for commodity prices remained uncertain, as did levels of activity in the Western Canadian Sedimentary Basin, Pembina said. Despite this uncertainty, Pembina also discussed its goal of achieving capital cost savings, which it estimated at the end of 2015 to be approximately C$225 million on the overall capital program.

With the majority of the remaining projects substantially complete and nearing on-time in-service by mid-year, Pembina is revising its estimated capital cost savings and scope optimizations to approximately C$275 million.

Based on the current commodity price environment and volume estimates, Pembina expects 2018 adjusted EBITDA to range from C$1.8 billion to C$1.9 billion. This range is consistent with Pembina's prior commitment of delivering C$600 million to C$950 million of incremental fee-for-service EBITDA from the secured capital projects which enter service in 2016 and 2017, in addition to the Kakwa River acquisition in 2016 and higher volumes/pricing across the base business.

Pembina expects to deliver on its projection of nearly doubling 2015 adjusted EBITDA by 2018.

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March 29, 2017
Dow Completes Freeport, Texas, Ethane Cracker Construction

Dow Chemical Company has wrapped up construction at its Freeport, Texas, ethylene facility, paving the way toward commissioning and startup by mid-year.

The world-scale cracker has a nameplate capacity of 1.5 million metric tons per year and will bolster olefins output at Freeport, which already produces over 4 million metric tons per year, Dow said in a release yesterday.

Dow said construction was completed within a week of its originally planned date. It is now moving toward the commissioning phase over the next several months.

"Our growth investments leverage the advantaged shale gas supply available in the U.S., and represent thousands of new jobs and significant economic value, including exports of approximately 20% of our U.S. production," said Chairman and CEO Andrew Liveris in a statement.

The addition of the Dow ethane cracker is among a wave of new facilities slated to come online this year and next. The U.S. Energy Information Administration earlier this year estimated that the addition of six new ethylene plants and one restarted plant by mid-2018 could boost ethane demand by 310,000 b/d (more than 25%) between 2013 and 2018.

Ethane is also in high demand as a feedstock globally. Last year, the United States launched its first waterborne exports of ethane from the East Coast Marcus Hook terminal and from Enterprise Products Partners' Morgan's Point in the Gulf Coast. By EIA's estimates, ethane exports could grow by 180,000 b/d between 2016 and 2018.

This demand is coming at a time that ethane production is rocketing, estimated to grow to 1.7 million b/d in 2018 from 1.25 million b/d at the end of 2016, according to EIA.

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March 8, 2017
MMEX Resources to Build Oil Refinery in West Texas; Targets Mexican Market

MMEX Resources Corp. said that it plans to build a $450 million, 50,000-b/d capacity crude oil refinery in the West Texas Permian Basin, subject to the receipt of required governmental permits and completion of required debt and equity financing.

Construction is slated to begin in early 2018, following the permitting process, and the facility is projected to begin operations in 2019.

MMEX is a development stage company formed to engage in the exploration, extraction, refining and distribution of oil, gas, petroleum products and electric power. MMEX focuses on the acquisition, development and financing of oil, gas, refining and electric power projects in Texas, Peru and other countries in Latin America.

Located 20 miles northeast of Fort Stockton, Texas, near the Sulfur Junction spur of the Texas Pacifico Railroad, the 250-acre facility intends to utilize its connection to existing railways to export diesel, gasoline, jet fuel, liquefied petroleum gas and crude oil to western Mexico and South America.

OPIS notes that MMEX refinery in the Permian Basin is the second refinery project targeting the Mexican liberalized fuel market. On Nov. 18, 2016, OPIS reported that Raven Petroleum was building a 50,000-b/d export-only oil refinery near Laredo in South Texas, targeting the Mexican and Caribbean oil products markets. Raven Petroleum is a wholly owned subsidiary of Raven Resources Group LLC. The Raven refinery and terminal project is scheduled to break ground in the third quarter of 2017, and the refinery could be in service by the end of 2018.

MMEX said that once completed, the Pecos County refinery will be one of the first oil refineries built in the United States in more than 40 years. The last refinery built in the U.S. was Marathon's 539,000-b/d Garyville, La., refinery in 1976.

Jack Hanks, CEO of MMEX, said, "The Permian Basin is the largest continuous oil discovery and has experienced exponential gains in daily production volume recently. The existing facilities and pipeline networks are largely unequipped to handle this growth and are limiting where products can be transported."

"By building a state-of-the-art refinery along the region's existing railway infrastructure, we hope to bring a local and export market for crude oil and refined products which will add substantial job and economic growth to West Texas," he said.

MMEX plans to surround the Pecos County refinery with an additional 250 acres of buffer property and leverage emissions technologies to yield minimal environmental impact. It also expects to feature closed-in water and air-cooling systems, which will require very little local water resources, the company said.

The company anticipates the 18-month construction process will create approximately 400 jobs in the area during peak construction, as well as foster a significant number of indirect jobs and revenue for companies in catering, workforce housing, construction, equipment and other industries.

Once operational, the facility is expected to provide an estimated 100 permanent jobs and generate substantial tax revenue for Pecos County, MMEX said.

"The MMEX management team has more than 30 years of experience building and managing multi-million dollar gas processing, pipelines, power plants, refinery and oil and gas operations in Peru and the United States," the company said.

MMEX purchased the rights to the project from Maple Resources Corporation. As with each of its previous projects, the management team will establish local offices and representatives to keep the surrounding communities informed throughout the construction phase and once the refinery is fully operational, MMEX said.

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March 6, 2017
Oregon Carbon Pricing Gains Momentum

The Oregon Senate Committee on Environment and Natural Resources and the Oregon House Committee on Energy and Environment held a joint public hearing last week concerning proposed legislation that would introduce a greenhouse gas emissions pricing mechanism to the state's economic activities.

Oregon lawmakers are in the midst of weighing five bills that would address greenhouse gas emissions from within the state by imposing various forms of caps, permits or taxes: Senate Bill 557 and Senate Bill 748, House Bills HB 2135 and HB 2468, and Legislative Committee proposal LC 1242.

SB 557, also known as the Healthy Climate Act of 2017, was introduced by Oregon Senator Lee Beyer (D) at the request of former Senator and emissions cap advocate Chris Edwards (D). The bill would require the state's Environmental Quality Commission (EQC) to set carbon reduction targets of 20% below 1990 levels by 2025, 45% by 2035, and 75% by 2050. Further, to meet these updated emissions targets, the bill would introduce a carbon trading market beginning in 2021, as per the recommendation from the Department of Environmental Quality study released in February. House Bill HB 2135 is a corollary to SB 557 and contains largely the same text. 

SB 748, also introduced by Beyer at the request of former Senator Edwards, would direct the EQC to establish a carbon pollution permitting program for emitters exceeding 25,000 "units." Covered sources would be given an emissions cap beginning in 2021 that would decrease annually through 2050. Fees and penalties collected as part of the program would be directed to transportation infrastructure, low-income utility assistance, and two grant programs aimed at climate change adaptation and clean energy transition.

HB 2468 would require the EQC to adopt new greenhouse gas emissions limits by the end of 2017, and directs the Oregon Global Warming Commission to "examine greenhouse gas cap-and-trade systems, including a statewide and multistate carbon cap-and-trade system and market-based mechanisms, as a means of achieving the limits on greenhouse gas emissions."

The Legislative Committee bill, LC 1242, would introduce a carbon tax on fuel suppliers and utilities.

Submitted testimony for the committee meeting was overwhelmingly supportive of the cap-and-trade initiatives, although it should be noted that comments from potentially affected industry players was limited.

"The room was packed. I don't believe there was anyone in attendance who was not in full support of putting a price on carbon in Oregon," said one carbon market advocate who requested anonymity. The source noted that a majority of hearing participants testified in support of SB 557, the cap-and-trade mechanism, although some of the environmental advocates testifying may not understand the nuances between the proposed cap-and-trade bill, the cap-and-permit bills, and the tax proposals.

The source, who provided testimony in favor of cap-and-trade as a least cost mechanism to reduce carbon emissions, also noted that a number of parties testified as to the importance of offsets for any carbon pricing mechanism to be successful.

The source also pointed out that the state's environmental community seems to be rallying around SB 557. This is backed up by the submitted testimony from the Oregon chapter of the Sierra Club, the Oregon Environmental Council, Oregon Climate Trust, Southern Oregon Climate Action Now, Environment Oregon and Climate Solutions.

OPIS notes that Oregon does not have the same environmental justice issues that bedevil cap-and-trade efforts in California, primarily due to the distribution of its populace, very few of which live in the vicinity of large greenhouse gas emitters. SB 557 has also been able to gain the support of Oregon's environmental justice groups by directing more of the cap-and-trade revenue to low-income, disadvantaged communities.

Oregon accounted for an estimated 63 million mt of CO2 emissions in 2015, according to the Oregon DEQ emission inventory. Comparatively, California emissions covered under the cap-and-trade program exceeded 340 million mt of CO2e in 2015, according to the California Air Resources Board.

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February 28, 2017
Drop in Fuel Profit Lowers CST's 4Q Net Income

CST Brands Inc. reported lower net income in the fourth quarter of last year but a big jump in net income for 2016 overall.

The primary driver for the drop in fourth-quarter net income was a 25% decrease in U.S. motor fuel gross profit, as the CST experienced "very strong" fuel margins in the fourth quarter of 2015.

The large, convenience and fuel retailer posted fourth-quarter net income of $18 million, or $0.23 per diluted share, compared to net income of $25 million, or $0.34 per diluted share, for the same period in 2015. The decline in net income would have been more pronounced without about $16 million in asset impairment charges, acquisition expenses, legal expenses, professional fees and net tax effects on repatriation in the fourth quarter of 2015.

For full-year 2016, CST reported net income of $324 million, diluted earnings per common share of $4.24 and EBITDA of $717 million, compared to net income of $149 million, diluted earnings per common share of $1.95 and EBITDA of $422 million the year earlier.

4Q Fuel Profits Down

Motor fuel gross profit in the U.S. for the fourth quarter of 2016 was $66 million versus $88 million in the same quarter of 2015.

The fuel margin fell to 13.4cts/gal in the fourth quarter from 19.4cts/gal during the year-ago period. The decline was partially offset by a 10% increase in total motor fuel gallons sold, resulting from CST's expanded core network.

New-to-industry stores, acquisitions and organic growth boosted U.S. merchandise and services gross profit 19% from the year-ago quarter. Core same- store merchandise and services sales per store per day declined 3% during the fourth quarter of 2016, primarily due to continued softness in parts of south Texas associated with the oil slump. Core same-store merchandise and services gross profit dollars were relatively flat when compared to the same period in 2015, as a result of a 60 basis point improvement in gross margin capture during the quarter.

In Canada, motor fuel gross profit increased 4% and merchandise and services gross profit increased 5% when compared to the fourth quarter of 2015, primarily driven by an increase in the average number of retail sites. On a same-store basis, merchandise and services sales per site per day increased 2% in Canada when compared to the fourth quarter of 2015, primarily due to growth in the grocery and packaged beverage business, the company said.

Divestitures Increase EBITDA

Behind the year's 70% jump in EBITDA was the sale of CST's California and Wyoming convenience stores during the third quarter, as well as continued improvement in the merchandise and services gross profits, the company said.

For the full year, motor fuel gross profit in the U.S. was $309 million versus $360 million in the same period of 2015. CST linked the decline in motor fuel gross profit to lower fuel margins.

U.S. merchandise and services gross profit increased 22% year over year, thanks to higher merchandise and services sales and gross profits in the company's U.S. core and NTI store sales, acquisitions and organic growth. Core same-store merchandise and services sales per store per day declined 1% during 2016.

However, core same-store merchandise and services gross profits grew by 2% in 2016, resulting from a 100 basis point improvement in margin capture.

In Canada, motor fuel gross profit increased slightly and merchandise and services gross profit increased 4% when compared to 2015, primarily due to an increase in the average number of retail sites. On a same-store basis, merchandise and services sales per site per day and merchandise and services gross profits increased 4% in Canada year-over-year thanks to growth in the grocery and packaged beverage business, CST said.

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February 22, 2017
PBF Will See Crude Storage Swell at Chalmette

A new 625,000-bbl tank will be constructed to handle sour crude at PBF's refinery in Chalmette, La., after a deal was reached between the refiner and its master limited partnership affiliate. The additional tank is a reminder that refiners with publicly traded MLPs are motivated to add storage that can yield a nice earnings stream for logistics and afford the refining company more agility with crude supply or refined products marketing.

A 10-year storage services agreement was signed last week between PBF Holding and PBFX (the master limited partnership) for tankage that should be ready by Nov. 1, 2017 or earlier. PBF affiliate Chalmette Refining along with PBFX Operating (a PBFX affiliate) have entered into a 20-year lease on the premises where the tank will be located and Chalmette Refining will manage the construction of the tank.

Under the storage agreement, which is typical between refiners and their logistics affiliates, PBFX will provide the parent company (PBF Holding) with storage services in return for storage fees. The agreement requires the parent company to pay a monthly fee of 60cts per barrel of shell capacity and the lease can be extended for various terms.

The project underscores how independent refiners and their MLPs can be much more nimble than major oil companies such as ExxonMobil. Among major oil companies in the U.S., only Shell has a master limited partnership affiliate, whereas nearly every publicly traded independent refiner has a publicly traded MLP.

Beyond leverage for refining operations, the additional crude oil storage could pay off when there is deep contango in crude oil prices. Much of the crude that is in U.S. tanks was put there as part of "carry plays" by public and private trading companies.

New for 2017! The 19th Annual OPIS Supply & Transportation Summit is now part of CERAWeek, the industry's premier gathering of global energy industry leaders, experts and government officials. Get all the details here.

February 22, 2017
NATSO, Large Retailers Drum Up Support to Keep RFS Point of Obligation

On the last day of the public comment period on the Renewable Fuel Standard (RFS) at the Environmental Protection Agency (EPA), comments from opposing sides on the petitions to move the point of obligation are flying in fast and furious before the deadline.

NATSO, representing America's travel centers and truckstops, said on Wednesday that it is encouraged by the vast support to keep the current compliance structure under the RFS. NATSO is opposed to moving the point of obligation.

NATSO's opposition to keep the current compliance requirements is backed by major retailers, including Boyett Petroleum, Circle K, Cumberland Farms, Guttman Energy, Kwik Trip, Murphy USA, Pilot Travel Centers, QuikTrip, RaceTrac, 7- Eleven, Sheetz and Wawa.

NATSO, in collaboration with other industry stakeholders, has engaged a diverse group of more than 35 organizations and companies representing downstream blenders, fuel retailers, marketers and end users at the federal and state levels. These groups speak on behalf of a majority of the fuel sector, which opposes the shift, NATSO said.

"NATSO is heartened by the overwhelming number of stakeholders who are urging the EPA to keep the RFS compliance with refiners, importers and manufacturers," said Lisa Mullings, CEO of NATSO. "We urge the EPA not to shift compliance onto thousands of small business fuel retailers, which would inject massive disruption into fuels markets and raise fuel prices, ultimately harming the economy and hard-working Americans."

The RFS has been an ongoing point of contention between major players in the fuel industry, NATSO said. A handful of refiners and investors have petitioned the EPA to shift compliance requirements down the supply chain, it said.

"Doing so would undercut the program's efforts to sustain the use of renewable fuels in gasoline and diesel fuel. The current structure creates a strong incentive for blenders, retailers and marketers to integrate renewable fuels into the supply chain," NATSO said.

"The RFS is working as intended by creating stable gas prices and encouraging renewable fuels in our gas supply," said Tim Columbus, general counsel of the National Association of Convenience Stores and SIGMA. "But if the EPA shifts compliance, it would unnecessarily complicate the program, needlessly disrupt the markets for motor fuels, and hurt consumers most."

In addition to undermining the purpose of the program, this change would increase gas prices for consumers as downstream players' ability to satisfy their obligations would be dictated by upstream counterparts, who have the leverage and incentive to raise prices, NATSO said.

A recent Penn Schoen Berland (PSB) survey released earlier this year revealed that 86% of voters agree that a compliance shift would increase gas and diesel prices at the pump, according to NATSO.

The change would also add significant compliance costs and burdens to freight shippers, which would ultimately raise the cost of consumer goods through higher shipping costs, the study said.

For example, if the compliance changes, Class I railroads would need to expend between $112.5 million and $214 million just to acquire Renewable Identification Numbers (RINs) to comply with 2016 Renewable Volume Obligations (RVOs) -- based on 2016 numbers. California's enactment of the Low Carbon Fuel Standard is a cautionary tale. In light of the market's experience in California, it would not be implausible for the railroads to have to pay between $260 and $447 million more for fuel.

OPIS notes that the point of obligation for the RFS has been a contentious issue at different market levels in the past year, with some refiners and retailers requesting a move of the point of obligation from the refineries to the racks.

It is a case of the haves versus have-nots. Some refiners with a small or no retail footprint are incurring heavy RINs costs due to an inability to blend ethanol and generate RINs. Some other refiners and large retailers are able to generate more RINs from their large retail networks, which they have invested in over the years. These refiners could use the RINs from their large retail operations to cover their RINs obligations, while larger retailers like Sheetz and Wawa are able to benefit from selling RINs or use the RINs benefits to be more competitive in retail pricing.

Become a better fuel buyer without ever leaving your desk – sign up now for the OPIS Basics of Fuel Buying eLearning course. Taught by 30+ year industry veteran Scott Berhang, this 11-module online training program will guide you through everything you need to know about purchasing physical fuel. Visit www.opisnet.com/events/fuel-buying-online.aspx or call our eLearning team toll-free at 888-301-2645 for more details and to get started. Also available en español.

February 13, 2017
Western Refining Yet to Finalize Voting Date for Tesoro Merger

Western Refining said that it set a record date of Feb. 10 for company stockholders who will vote on a proposal to adopt a previously announced merger plan with Tesoro during a special meeting.

A Western spokesman told OPIS on Monday that the company has yet to finalize a date for that special meeting.

Western said that Western stockholders of record at the close of business last Friday will be entitled to receive notice of the special meeting and to vote at the special meeting.

OPIS notes that the pending merger deal is subject to customary closing conditions, including approval by the shareholders of both companies and the receipt of regulatory approval.

Tesoro and Western said on Monday that the U.S. Federal Trading Commission has requested more information on the merger agreement, but both companies still expect the deal to close in the first half of 2017, subject to approvals.

On Jan. 25, Western Refining said that the integration process between Tesoro and Western is ongoing ahead of the potential closing of the deal.

Following the announcement of the acquisition, many at Tesoro and Western have been preparing for the potential closing, Western said.

Tesoro's Enterprise Integration Office comprises a team of business and functional work teams led by Keith Casey, executive vice president, Marketing and Commercial, while Mark Wilson, vice president, Enterprise Integration, manages the effort on a day-to-day basis, Western said.

In January, the joint Western and Tesoro Integration Planning team met for two days in San Antonio to kick off their work, Western said.

On Nov. 17, OPIS reported that Tesoro would acquire Western at an implied current price of $37.30 per Western share in a stock transaction, representing an equity value of $4.1 billion based on Tesoro's closing stock price of $85.74 on Nov. 16, 2016.

This represents an enterprise value of $6.4 billion, including the assumption of approximately $1.7 billion of Western's net debt and the $605 million market value of non-controlling interest in Western Refining Logistics.

Tesoro will add Western's refineries in Texas, New Mexico and Minnesota to Tesoro's existing refineries in California, Washington, Alaska, Utah and North Dakota, which will expand the combined company's operational capabilities and improve access to advantaged crude oil and extended product regions.

Combined, the company will have 10 refineries, with a refining capacity of over 1.1 million b/d.

The merger deal brings together 12 retail and convenience store brands to better serve a customer base and regional preferences and provides improved ratable supply from the entire refining system, Tesoro said. The combined retail operations will comprise over 3,000 branded retail stations operating under a variety of brands including ARCO, Shell, Exxon, Mobil, SuperAmerica, Giant and Tesoro.

New for 2017! The 19th Annual OPIS Supply & Transportation Summit is now part of CERAWeek, the industry's premier gathering of global energy industry leaders, experts and government officials. Get all the details here.

February 1, 2017
Demand for Global Fuel Additives to Grow; Mixed Impact From Regs: Kline

Consumption of global fuel additives is expected to grow at a compound annual growth rate of 1.9% from 2015 to 2020 despite mixed impact from biofuels mandates and fuel regulations, according to market research and management consulting firm Kline.

Consumption is about 820 kilotons (537,496 bbl) in 2016, according to the recently published Global Fuel Additives: Market Analysis and Opportunities report issued by Kline.

North America is the largest fuel-additive-consuming region in the world due to its high fuel consumption for transportation, as well as supported by the mandated additive usage for gasoline in the United States, Kline said.

Fuel additives are categorized into three key segments: blending, shipping and storage; performance additives; and the aftermarket.

The blending, shipping, and storage segment represents additives that are added at the refinery and is the largest segment, accounting for more than two-thirds of the total fuel additives market.

Performance additives applied by fuel marketers to differentiate themselves in the market is the second-largest segment of the market. This segment can be further divided among gasoline performance additives, diesel performance additives and other fuels.

Aftermarket additives are those bought and applied by vehicle owners. The distribution channels are also different for this segment. Gas stations, workshops and auto-parts stores are some of the channels used to sell additives in this segment.

Diesel is the most consumed fuel globally, Kline said. Therefore, additives such as cetane improvers and cold flow improvers, used for diesel, are among the most consumed fuel additives in the market.

Additive consumption depends on several factors, such as fuel consumption, treat rates, fuel grade and regulations.

The larger the share is for premium fuels sold in the market, the higher the consumption of additives is expected for that market. With the anticipated rise in sales of premium fuel in Asia as a portion of customers switch to premium fuels, consumption of additives will also increase in the region.

"Tightening fuel economy norms globally are expected to slow down the growth in the fuel consumption, adversely affecting fuel additive demand growth. Furthermore, regulations can also have both a positive and negative impact on the consumption of fuel additives. Regulations such as the 'Total Additivation Program' in Brazil mandating minimum treat rates are expected to boost the demand for fuel additives if implemented," according to Kunal Mahajan, a project manager in Kline's energy practice.

"Regulations mandating minimum ethanol blending with gasoline and biodiesel blending with diesel could have a positive impact on additives such as corrosion inhibitors and anti-oxidants but a negative impact on additives such as lubricity improvers," he said.

Biodiesel improves lubricity, but has poor oxidative stability, Mahajan said. This will adversely impact the demand growth of lubricity improvers if the governments around the world, especially in Asia, are successful in implementing the biofuels mandate, he said.

On the other hand, such mandates will favor the growth of anti-oxidants and corrosion inhibitors, Mahajan said. Ethanol absorbs moisture, which could cause corrosion, due to which the demand for corrosion inhibitors will increase, he added.

Become a better fuel buyer without ever leaving your desk – sign up now for the OPIS Basics of Fuel Buying eLearning course. Taught by 30+ year industry veteran Scott Berhang, this 11-module online training program will guide you through everything you need to know about purchasing physical fuel. Visit www.opisnet.com/events/fuel-buying-online.aspx or call our eLearning team toll-free at 888-301-2645 for more details and to get started. Also available en español.


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