(San Diego Union Tribune, Rob Nikolewski, 9.Jul.2018) – Continuing its aggressive corporate strategy, IEnova – the Mexican subsidiary of San Diego-based Sempra Energy – added another asset to its energy portfolio Monday by announcing it will spend $150 million to build and operate a liquid fuels marine terminal in the northwest state of Sinaloa.
The federal port authority in the town of Topolobampo, located on the Gulf of California, awarded a 20-year contract to IEnova to construct the terminal that in its first phase will have a storage capacity of 1 million barrels of fuel, mainly gasoline and diesel.
IEnova officials said the company has “achieved significant commercial progress with potential customers” to have the terminal fully contracted and said additional phases of the project could expand to include storage of other products such as petrochemicals.
“IEnova’s success in developing new energy infrastructure is contributing to Mexico’s economic growth, creating jobs and diversifying energy supply while benefiting millions of Mexican energy consumers,” said Joseph Householder, Sempra’s chief operating officer, in a statement.
Monday’s announcement comes just three months after IEnova announced a $130 million investment in a liquid fuels terminal near Ensenada, Mexico, to serve customers in the northern border state of Baja, California. The company signed a long-term contract with the local unit of Chevron as part of the deal.
IEnova has invested about $7.6 billion in energy projects in Mexico, ranging from wind farms to solar power plants to natural gas pipelines and facilities, capitalizing on the country’s energy reform measures that are aimed at attracting private investors to help upgrade Mexico’s energy infrastructure.
On June 28, Sempra CEO Jeff Martin announced the company will sell all of its solar and wind holdings in the U.S., as well as gas storage facilities in the Deep South, but did not mention making any changes in regards to IEnova or other subsidiaries.
(Stabroek News, 3.Jun.2018) – U.S. Virgin Islands Governor Kenneth E. Mapp announced yesterday an agreement which would reopen one of the world’s largest refineries, create hundreds of jobs in the territory and buttress the solvency of the Government Employees Retirement System (GERS).
According to a release from his office, Mapp said the US$1.4 billion pact was between the Government of the Virgin Islands and ArcLight Capital Partners, LLC, the owners of what had been one of the largest oil refineries in the world when it was shut down on the USVI island of St Croix in 2012. The release said that the deal includes reopening the refinery portion of the operation, which when restarted, will funnel hundreds of millions of dollars into the local economy.
The release said that under the agreement with ArcLight Capital, the owners of what is now called Limetree Bay Terminals, the company will invest approximately US$1.4 billion to upgrade the existing refinery located in St. Croix. Over the next 18 months, this will create more than 1,200 local construction jobs.
Once refinery operations begin at the end of 2019, as many as 700 permanent jobs will be created. The new jobs will be in addition to the over 750 jobs now at the terminal storage facility. The initial refining operations provide for the processing of around 200,000 barrels of crude oil feedstock per day.
“This agreement is great news for the people of the Virgin Islands as we continue to grow and expand our economy,” said Mapp, who added it is tremendous news for the ‘big island,’ which felt the full brunt of the shutdown of refining operations in 2012. He added that the capital investment will not only benefit St. Croix since the monies from the agreement will boost the solvency of GERS and will also help fund a new 110-room, “upscale lifestyle” hotel, flagged by a major four-star brand on the sister island of St. Thomas.
Upon the closing of the transaction, ArcLight Capital will make a US$70 million closing payment to the Government of the Virgin Islands. The payment includes US$30 million for the purchase from the government of approximately 225 acres of land and 122 homes. The release said this property was acquired as part of the government’s settlement of certain claims against HOVIC, PDVSA of Venezuela, Hovensa and Hess Oil Corporation.
Once refinery operations begin and after crediting the US$40 million of prepaid taxes, Limetree will make annual payments to the government in lieu of taxes at a base rate of US$22.5 million a year. With market adjustments based on the refinery’s performance, this could increase to as much as US$70 million per year, but will not fall below US$14 million a year, the release said.
The release said that according to industry experts and consultants Gaffney, Cline & Associates, the government expects to receive more than US$600 million over the first 10 years of the restart of the refining operations. This income is in addition to the US$11.5 million currently flowing to the government from the oil storage terminal each year.
“For comparison sake, in the over 30 years that Hess Oil operated the refinery on the island of St. Croix, the company paid approximately US$330 million in corporate taxes to the government. As you may recall, in 2015 Hess Oil filed suit for the return of (those tax payments),” Mapp pointed out in the release. Hess Oil is one of the partners of ExxonMobil’s subsidiary, Esso in the Stabroek Block in Guyana’s waters.
Mapp said: “This landmark agreement did not happen overnight. It is the result of much hard work by the owners of ArcLight Capital and my Administration over the past two years. It is the product of complex negotiations with major players in the global oil industry. It required tremendous work with the Trump Administration and the President’s Council of Environmental Quality, the EPA (United States Environmental Protection Agency) and the U.S. Department of Justice. More work remains to be done, but this agreement allows the Virgin Islands to accelerate its recovery, grow its economy, create jobs for its people, propel new startup businesses, as well as support existing businesses and ultimately provide revenues for our government and our retirement system,” he said.
The release added that qualified Virgin Islands residents will be given preference in all hiring. ArcLight Capital will be obligated, and the local government will assist, to advertise and publicize all job opportunities for local residents. Residents of St. Thomas and St. John, who may be interested in working during the reconstruction of the refinery, will be offered a place to live while working on St. Croix without charge, the release added.
(Natural Gas Intelligence, 28.Jun.2018) – Citing a “profound opportunity in Latin America,” Department of Energy (DOE) Secretary Rick Perry said the U.S. government would partner with the Overseas Private Investment Corporation (OPIC) and invest $1 billion in Mexico’s energy sector over the next three years.
The joint initiative, officially the “Partnership to Power the Americas,” was announced Thursday on the sidelines of the World Gas Conference in Washington, DC. Both Perry and OPIC CEO Ray Washburne said the initiative would help American energy companies working throughout the Western Hemisphere.
Specifically, OPIC, a self-sustaining agency of the federal government, would provide financing and insurance when it is unavailable in the private sector. Perry said the initiative would “fund some projects that maybe wouldn’t otherwise get done.
“Our goal here is to create solutions that utilize the expertise, goods and services of our businesses in order to increase energy access, strengthen energy security and ultimately affect prosperity and opportunity in this Western Hemispheric region. We’re in a great position right now to do that, thanks to our U.S. energy abundance and the technical ingenuity that resides in the U.S. There is an enormous potential in Latin America.”
Washburne added that the partnership “will help establish a seamless process for bringing the best of U.S. energy technology and expertise to places in Latin America where it is needed most.”
Perry said recoverable shale and tight gas in the entire Western Hemisphere, which includes the United States and Canada, could potentially make up approximately 40% of the world’s reserves. “Yet the private sector incentives are needed to foster the development of infrastructure that we’re going to be needing for those greater business opportunities,” he said.
“OPIC is going to be prioritizing assistance to those companies seeking to expand in Latin America when private resources are unavailable or insufficient. In turn, we at DOE will be providing the connections, the expertise. We’ll help identify technology areas and sectors where U.S.-based companies have the potential to excel in these markets but lack the capital to do so.”
‘Complete Confidence’ In Mexico’s Next President
Perry said that whomever wins Sunday’s presidential election in Mexico, he had “complete confidence” that the winner would ultimately work closely with the United States to develop that nation’s energy infrastructure. Andres Manuel Lopez Obrador, a frequent critic of energy reforms enacted under President Enrique Pena Nieto, is expected to prevail.
“Regardless of your political leanings, you’re going to need resources to address the needs of your country and your citizens,” Perry said. “The most powerful and expeditious way to address resources coming into the country is through the energy sector. I think Mexico is going to be very willing to work with private sector partners, with the United States.”
The DOE-OPIC joint initiative will “most likely” assist American companies working to develop oil and natural gas pipelines and associated infrastructure throughout Mexico.
“We see Mexico continuing as a good neighbor,” Perry said. “We see Mexico as an economic partner. To help build their foundational economy, energy will play a very important role. We look forward to meeting with the new administration, whoever that individual may be, and finding ways that we can help the citizens of both the United States and Mexico together.”
(Reuters, 28.Jun.2018) – Citgo Petroleum, the U.S. refining arm of Venezuela’s state-run oil company PDVSA, said it appointed two senior executives to new positions as it works to refurbish an idled Aruba refinery.
Luis Marquez was named vice president and general manager at the refinery, a 235,000-barrel-per-day plant in San Nicholas that has been awaiting an overhaul. Edward Oduber also was appointed interim on-site project manager for the refurbishment of the refinery, during Phase II of the project, the company said.
Citgo in 2016 signed an up to 25-year lease with the government of Aruba to refurbish and operate the plant as part of a $685 million project. Earlier this year, it had slowed work on the overhaul due to a lack of credit.
Marquez, who replaced interim general manager Raymond Buckley, began his career in 1981 at the Amuay Refinery in Venezuela and has held positions at PDVSA International Refining, PDVSA Argentina, PDVSA Ecuador, and Petrocedeño, the company said.
Edward began at the San Nicolas refinery in Aruba in 1990, and held positions with Citgo Aruba, Valero Aruba, and Coastal Aruba.
Citgo said that Joe Crawford Jr will continue as general manager maintenance and operations overseeing the operating portions of the facility along with the loading facilities, terminal and distribution network. (Reporting by Gary McWilliams; Editing by Amrutha Gayathri)
(Natural Gas Intelligence, Carolyn Davis, 27.Jun.2018) – The mantra for a San Antonio, TX-based midstream operator, whose portfolio is increasingly weighted to southern destinations, could well be what’s good for Texas is good for Mexico.
Howard Midstream Energy Partners LLC, aka Howard Energy Partners (HEP), is making inroads in the Lone Star State and across the border as it builds out its multiple systems to carry natural gas and liquids to serve a growing customer base in northern Mexico, i.e. the Monterrey Energy Corridor.
Monterrey, the largest city and capital of the state of Nuevo León, has become an industrialized mecca for projects, something not lost on HEP executives, said President Brandon Seale. He discussed the myriad opportunities with an industry audience at the 4th Mexico Gas Summit held earlier this month in San Antonio.
HEP’s processing and pipeline assets extend from the Permian Basin to South Texas, and east of Houston in Port Arthur, all strategically sited to serve the “end goal,” said Seale, northern Mexico’s “growing appetite for hydrocarbons.”
Because of where HEP’s assets are in South Texas, the operator was “always going to be at the tail-end of the value chain,” he said. “We were trying to push product back to Houston or to other markets, but we wanted to be at the front-end of the value chain. So we stepped into Mexico with a very simple strategy,” to diversify and bring aboard strategic partners.
HEP about seven years ago bought the Maverick Dimmit and Zavala Gathering System, about 344 miles of pipeline in the South Texas counties of Maverick, Dimmit, Zavala and Frio.
Designed for rich and lean gas service, the system gathers for production from the Eagle Ford and Pearsall formations, and interconnects with several big pipelines that move gas in all directions, including south.
“From Day 1, we were selling gas to Mexico,” Seale said. “Mexico was always on our radar. And the funny thing is, if you don’t live and work close to the border, sometimes you look at infrastructure maps and you forget Mexico is there…It just looks like a big white space on the map. But of course, the resources don’t stop at the border and infrastructure doesn’t really stop either…The magnitude of the opportunity was always present in our minds.”
For example, Texas has an estimated 300,000 wellheads. In Mexico, there’s about 8,000. Texas has nearly 250,000 miles of gathering transportation pipelines. In Mexico, there’s around 75,000 miles.
“There’s a huge, huge opportunity there,” Seale said. “The resource is there…with some of the biggest wells ever drilled in the history of the world…Staggering, staggering numbers.”
Around the time the Maverick purchase was made, Mexico was becoming a net hydrocarbon importing country.
“The situation was quite acute on the natural gas side,” Seales noted. The country was suffering from critical power alerts and brownouts, and state-owned Petroleos Mexicanos at times would cut off service to customers with no notice. It was “exceedingly distractive,” he said.
Mexico had to turn to the Pacific markets to buy liquefied natural gas at “exorbitant” prices, when West Texas operators “would have given their left arm to sell gas at $2.50/Mcf. It didn’t make sense…”
HEP got acquisitive again, and a year after the Maverick purchase, it acquired the Eagle Ford Escondido and Cuervo Creek gathering systems to the south in Webb County, primarily 12- 16-inch diameter high-pressure gas pipelines that gave it another 83 miles of pipeline, a 102-mile lean gas gathering system, two leased amine treating plants and multiple intrastate pipeline outlets.
A 30-inch diameter pipeline was installed in 2013 to provide a direct connect to a Kinder Morgan Inc. system, which moves gas from Katy, near Houston, southwest to Laredo.
Three years ago HEP installed a direct connection with the NET Midstream system, whose affiliate NET Mexico Pipeline Partners LLC‘s 120-mile, 42- and 48-inch diameter Texas pipeline moves gas from the Agua Dulce hub in South Texas to Mexico.
“Our markets were all getting to Mexico,” but they were getting there indirectly, Seales said. “At this point too, our system was basically full…packed to the gills. So we had to find new markets.” Those opportunities led to the the genesis of Nueva Era Pipeline LLC, a cross-border system that ramped up in May.
Nueva Era, a 30-inch diameter system that is designed to carry at least 600 MMcf/d and up to 1 Bcf/d, is a joint venture between HEP and Mexico’s Grupo Clisa to supply Monterrey.
“There was a huge market” for natural gas in the Monterrey area that “was basically tapped out” around 2013, with no new sources of supply on the horizon. HEP executives also had a theory about suppressed demand for natural gas in the region.
“Basically, if you just looked at the charts, it looked like Mexico’s gas demand was flat,” Seale said. “But if you considered the external factors…the fact that historically, there were all these subsidies” for fuel oil and liquefied petroleum gas and other alternative fuels. “And if you consider that pricing on natural gas had never really been that transparent in Mexico, there were a lot of disincentives for people to use natural gas as a feedstock.
“As the experience in the U.S. in the last 30 years has taught us, if you deregulate the product, if you make it plentiful and if you make it transparent in price and you make it liquid, people will find a lot of ways to use it.”
The United States uses 80-90 Bcf/d of gas, while Mexico uses 8-9 Bcf/d, he said. “Somewhere in there is opportunity.”
Mexico’s state power company, Comision Federal de Electricidad, is the anchor shipper on Nueva Era with 504 MMcf/d of capacity. Another 496 Bcf/d is still available.
“The pipeline is mechanically complete,” Seales said. In mid-June the partnership was “awaiting final regulatory approvals,” to go into full service by the end of the month.
While trucks and rail are adequate to transport oil and liquids, a “pipeline is really the end goal” to transport all energy products, Seale said. With its cross-border system, North America’s energy markets are becoming “truly integrated…
By connecting Monterrey via a pipeline in South Texas, there’s energy integration across “the entire North American network,” allowing a trader to “swap a barrel from New Jersey to Monterrey…That’s pretty remarkable…And we feel like we’re in a unique position because of our experience with cross-border transactions” from working with U.S., Texas and Mexico’s diverse regulatory regimes.”
For HEP, the Texas coastal community of Corpus Christi, which is near Agua Dulce, is an important piece of the puzzle. The port city, already a manufacturing hub for the Gulf of Mexico energy industry, is quickly becoming the go-to destination for oil and petrochemical exports.
In addition, Cheniere Energy Inc. is building a liquefied natural gas export project in Corpus, and newbuild petrochemical facilities, including one led by ExxonMobil Corp., are on the drawing board.
And that’s not including the pipelines destined for the region from the Permian Basin and Eagle Ford Shale.
“The importance of Corpus is obvious in the market,” Seale said. “The number of pipeline projects to link West Texas to Corpus Christi are almost too big to count…” and “almost every midstream in the space is looking at their own project” to potentially add on capacity.
“What that signals is that the same thing that’s happening in natural gas that makes Agua Dulce…the natural gas hub, the natural liquid point, is happening now with crude and other refined products,” Seale said.
“If we do our job right, Corpus Christi should become the northernmost delivery point into northern Mexico,” he said. A plethora of investments are earmarked to support energy product transport south of the border.
Mexico is no longer the “blank spot on the map…the infrastructure map is now fully connected and day by day becomes only more integrated across the border.
Consider the Nueva Era system, he said. “With our Nueva Era pipeline, we can connect to Waha with these other pipelines coming down…In a few months in theory, a Waha-Monterrey route, which HEP is calling the “WahaRey” route “is going to be a viable option for any gas shipper in West Texas.
By the same token, the Agua Dulce-to-Monterrey route, aka “AguaRey” is already available. Already there’s 500 MMcf/d going into Monterrey,” with pipeline capacity “almost tapped out,” Seale said, as the region grows and commerce builds.
“Imagine what a 20-inch diameter presidential permit pipeline across the border could do for liquids products?” he asked the audience. “It would be something very, very similar.”
HEP is creating a path, he said, “connecting the most efficient and largest points of product in South Texas with Monterrey, the most industrialized market in Latin America, the gateway to all of Latin America…
“What’s good for Texas is good for Mexico, and what’s good for Mexico is good for Texas,” Seale said, borrowing a line from an HEP executive. “I really think that the integration of these energy markets is one of the finest results of that.”
(OilPrice.com, Tsvetana Paraskova, 24.Jun.2018) – While the U.S. shale production in the Permian has been grabbing most of the market and media attention over the past two years, the Gulf of Mexico has been quietly staging a comeback.
Big Oil firms, the main operators in the Gulf of Mexico, have been cutting costs and simplifying designs to make offshore projects viable in the lower-for-longer oil price world.
Chevron, Shell, and BP continue with their deepwater developments offshore Louisiana and Texas and have brought down breakeven costs to $40 a barrel or less—comparable with the breakevens at some shale formations onshore. Now operators are vying for new exploration acreage close to existing production platforms that would bring development and production costs down even further.
While the market and media have focused on the record Permian production, the Gulf of Mexico’s production is also expected to hit a record high this year.
But there’s one huge difference between onshore and offshore in terms of resource development—for shale wells, production peaks in several months, while vast deepwater resources can pump oil for decades.
Big Oil continues to bet on resources and projects that will last for decades, but companies have drastically changed their approach to development. Gone are the days in which the race was to have ‘the biggest, the most complex and most expensive’ bespoke project the industry has seen. It may have worked at oil prices at $100, but at half that price of oil, the focus is on leaner projects and more collaborative work to bring costs down.
Top executives at the largest operators in the Gulf of Mexico admit that project costs before 2014 were unsustainable.
“We knew there was incredible waste, but 2014 was the trigger,” Harry Brekelmans, Shell Projects and Technology Director, tells Bloomberg.
“We knew there was no way we could put forward a project in the same way again.”
In April this year, Shell announced the final investment decision for Vito, a deepwater development in the Gulf of Mexico with a forward-looking, breakeven price estimated at less than $35 a barrel. After the oil prices started crashing, Shell began in 2015 to redesign the Vito project, reducing cost estimates by more than 70 percent from the original concept, the oil major said in late April.
Shell “collaborated internally and externally to optimize the supply chain, to drill standardized wells and to build tried-and-tested designs more efficiently,” Brekelmans said at the Offshore Technology Conference in Houston a week later.
Last month, Shell started early production at the Kaikias deepwater subsea development in the Gulf of Mexico a year ahead of schedule and at a forward-looking, break-even price of less than $30 per barrel of oil. Shell’s Brekelmans said earlier this year that the supermajor was targeting its deepwater projects to break even at $40 or preferably below that threshold.
Another oil major, BP, has cut project costs for its Mad Dog 2 project in the Gulf by 60 percent to US$9 billion, working with co-owners and contractors to simplify and standardize the platform’s design.
Chevron says that offshore crude oil extraction, including deepwater, is closing in on shale in terms of cost thanks to new production technologies.
“In the past, a lot of the cost of development has been new technology,” Jeff Shellebarger, president of Chevron’s North American division, told Bloomberg. “With the types of reservoirs we’re drilling today, most of that learning curve is behind us. Now we can keep those costs pretty competitive.”
According to Wood Mackenzie, oil and gas production in deepwater Gulf of Mexico is expected to reach an all-time record high this year at 1.935 million boepd, of which 80 percent is oil—beating the previous record from 2009 by nearly 10 percent and representing 13-percent growth year over year.
U.S. crude oil production in the Federal Gulf of Mexico increased slightly in 2017 to reach 1.65 million bpd, the highest annual level on record, the EIA said in April, adding that production is expected to continue growing this year and next, accounting for 16 percent of total U.S. crude oil production. According to the EIA, a total of 10 deepwater Gulf of Mexico field starts are expected in 2018 and 2019.
Exploration investment, however, is still flat, and operators are in a ‘wait and see’ mode, Wood Mackenzie said in March in a comment on the latest ‘lackluster’ U.S. lease sale in the Gulf. Bidding was focused on the Mississippi Canyon—an area with established infrastructure and lowest cost developments.
“Operators are keen to keep the utilization up on the infrastructure and every new barrel produced through these facilities, further realizes value from the original investment,” William Turner, senior research analyst at Wood Mackenzie, said.
“Meanwhile some patient but dedicated operators are on the brink of cracking the code on ultra-high-pressure developments. Once the industry sees some proven developments in fields like Anchor, others will follow suit and we will begin to see the return of significant volumes being discovered and developed in the region.”
(Natural Gas Intelligence, Carolyn Davis, 22.Jun.2018) – The Permian Basin’s growing natural gas volumes may provide the perfect aperitif to quench Mexico’s thirst, according to Kinder Morgan Inc.
The Houston-based pipeline and midstream giant’s natural gas segment makes up about 90% of $900 million worth of projects that were added to backlog in the first quarter. Mexico is a likely another avenue for future expansion, said Vice President Gregory Ruben, who oversees business development.
Speaking at the 4th Mexico Gas Summit in San Antonio, TX, Ruben said some of Kinder’s future growth is based on Permian projections, where oil is surging, which in turn produces more associated gas. And the basin’s proximity to Mexico provides “connectivity opportunities,” he told the audience.
“We’re continuing to look for opportunities to expand our footprint into the marketplace.” Mexico’s energy reform has opened the door to opportunities, and the company now is looking for the “best connection at this point in time.”
From a footprint perspective, Kinder has holdings in many of the key U.S. gas basins, including in Appalachia, which “gives us quite a bit of opportunity to take advantage of the markets and the supply basins as they do develop over time.”
The interconnectivity with Mexico is a natural, Ruben said, as “we have been in partnership as far as delivering volumes into Mexico for quite some time” through legacy El Paso Natural Gas Pipeline Co., i.e. EPNG.
The company’s Mier-Monterrey gas pipeline during March was the second largest importer into Mexico at 490 MMcf/d. Kinder is considering an expansion of the pipeline, which now in “proposed status.”
The company today has “roughly 5.4 Bcf/d of interconnect capability and growing, across the border into Mexico,” Ruben said. And a “near-term” expansion is underway to add up to 200 MMcf/d to the 300 MMcf/d Border Pipeline.
Other projects also are in the works to move more gas south. During 1Q2018, contracts were secured to carry from the Permian about 1.2 Bcf of capacity via EPNG, with some supply destined for south of the border, Ruben said.
In addition, remaining capacity was taken for the proposed 2 Bcf/d Gulf Coast Express Pipeline (GCX) that also is designed to move gas supply from the Permian to South Texas — and beyond.
GCX is to date the only confirmed new pipeline in the works for Permian gas supply. Potential connectivity for GCX is seen at the Agua Dulce gas hub near Corpus Christi, where more volumes could be moved to Mexico and via liquefied natural gas exports.
Kinder’s Sierrita Gas Pipeline, with 200 MMcf/d, has been serving Mexico markets since 2014. Sierrita is being expanded by about 323 MMcf/d to move more to Sonora, where the Puerto Libertad Pipeline would transport supply to the Gulf of California. The expansion is set to be in service by 2020 and include a 15,900 hp compressor station.
“We’ve got quite a bit happening, and we’re continuing to work with market participants to grow that connectivity at the border with Mexico,” Ruben said.
Many of the future gas supply opportunities lead back to the Permian, as “we’re continuing to see upward adjustments in projections” by producers for wellhead supply.
Ruben offered Kinder scenarios for future Permian gas production. In the base case, it expects volumes to reach 16 Bcf/d in two years or so.
“That’s a huge amount of gas that’s got to try and find a home and try to find a place to go,” he said. “From an upside perspective, we could see 20 Bcf/d of wellhead production in the basin. So when you think about those numbers and you think about all the capacity that’s been built out, it does create some challenges…”
To get an idea of how well the Permian may handle future gas flows, the company’s team stacked up all of the expected demand from the western markets in Arizona and California, as well as Mexican consumption trends, to determine the “economic capacity” for future projects.
Kinder’s experts determined that moving gas north from the Permian was a nonstarter economically, as supply would run head on into gas-on-gas competition from Rockies Express Pipeline, which is carrying supple Appalachian gas west, along with growing volumes from Oklahoma’s stacked reservoirs in the Anadarko Basin and beyond.
Some unused capacity was seen in the analysis in western flows, and there was some unused capacity to the Mexican border.
‘When you blend that in with capacity, it does create some compelling thoughts as far as what needs to happen to achieve balance within the basin,” Ruben said. “It’s a very compelling story.” GCX should begin transporting gas south in 2019, “and that gets us back into relative balance, but…based on how we see this growth should be moving forward from the basin,” more projects likely are needed to keep Permian gas in balance beyond 2020, he said.
“The good news is, if you are net buyer at Waha, there’s expected to be a lot of activity…”
(FinancialBuzz.com, 19.Jun.2018) – Despite the recent downturn in oil prices, Goldman Sachs remains optimistic.
According to Reuters, Goldman Sachs forecast a tighter oil market for a longer duration due to strong demand growth and the probability that rising supply disruptions could counter any increase in OPEC production.
“Our updated global supply-demand balance continues to point to further declines in inventories and higher oil prices in 2H18,” the bank said. Goldman also repeated its Brent price forecast for a peak of $82.50 per barrel throughout the summer and a year-end approximation of $75.
The avalanche of political and economic developments around the world that influence oil prices are making it difficult to determine what the relationship between demand and supply will be. Goldman Sachs explained in the report that they expect OPEC and Russia production to increase by 1 million barrels per day by the end of 2018 and by another half a million barrels per day in the first half of 2019. While a production increase would decrease oil prices, the supply numbers are expected to be offset by increased political and economic disruptions in Venezuela and Iran.
(Reuters, 13.Jun.2018) – Canadian energy company Enbridge Inc. said it started construction of the offshore border crossing section of its US$1.6-billion Valley Crossing natural gas pipeline between Texas and Mexico, according to a federal filing made available on Wednesday.
The company said in an e-mail the pipeline remains on track to enter service in October.
The latest filing pertains to a 1000-foot (305-meter) section of offshore pipe that extends to the U.S.-Mexico border. The remaining 165 miles of onshore and offshore pipe has been completed and commissioning activities will commence in the near future, Enbridge spokesman Devin Hotzel said in an e-mail.
The Valley Crossing project is designed to carry up to 2.6 billion cubic feet per day (bcfd) of gas from Texas to help Mexico meet its growing power needs as generators there shift away from fuel oil and imported liquefied natural gas.
One billion cubic feet is enough to fuel about five million U.S. homes for a day.
The Valley Crossing project has been under construction since April, 2017, according to the Enbridge website. In May, Enbridge said it had “substantially completed” the onshore part of the pipe and was working on the offshore part to meet a fourth-quarter 2018 in-service date.
Valley Crossing will connect in the Gulf of Mexico to the Sur de Texas-Tuxpan pipeline under construction by a joint venture between units of TransCanada Corp. and Sempra Energy. Once complete, it will be the biggest gas pipe between the two countries.
There are already about 20 pipelines that can move gas from the United States to Mexico with a total capacity of around 10.9 bcfd, according to U.S. energy data. That includes Howard Energy’s 0.6-bcfd Impulsora pipeline, which is expected to enter service this month.
Analysts have said, however, that constraints on the Mexican side of the border have so far limited a big increase in U.S. pipeline exports.
Since the start of the year, U.S. exports to Mexico have averaged 4.0 bcfd, up just a bit from the 3.9-bcfd average during the same period in 2017, according to Thomson Reuters data.
While the pipeline constraints remain, Mexican energy companies have been buying more U.S. liquefied natural gas (LNG) than any other country since February, 2016, when the first U.S. LNG export terminal opened in the lower 48 states at Cheniere Energy Inc.’s Sabine Pass in Louisiana.
Mexico bought 50 cargoes of LNG totalling 167.8 billion cubic feet of gas from the United States, 18.8 per cent of total U.S. LNG exports between February, 2016, through the end of 2017.
(Denis Chabrol, DemeraraWaves, 12.Jun.2018) – ExxonMobil on Tuesday reconfirmed that Guyana will pump up its first barrel of oil in March 2020, even as the Guyana government continued to fend off criticisms of the 2016 production sharing agreement.
Vice President of ExxonMobil Development Company, Lisa Walters said work was well advanced by several companies in Singapore, Brazil and the United States Gulf Coast to ensure that commercial oil production begins in less than two years. “We are on track for first oil in March of 2020,” she said. “In just a little over a year and a half, the Liza Destiny will deliver its first oil to its first tanker offshore,” she added.
ExxonMobil estimates that oil discoveries at Liza, Payara, Snoek and Turbot offshore Guyana total 3.2 billion barrels and would eventually lead to daily production of 500,000 barrels. ExxonMobil estimates that Liza Phase 1 will generate over US$7 billion in royalty and profit oil revenues for Guyana over the life of the project.
Walters said the drill-ship, Noble Bob Douglas, recently started drilling the production wells located at Liza more than 125 miles off the Demerara Coast. She said “all of the design work on the project is nearing completion” and “construction is well-underway worldwide” for the Floating Storage, Production, Storage and Offloading (FPSO) vessel named “Liza Destiny”. SBM Offshore has won the contract to construct that vessel, while TechnicFMC, and Saipem have been hired for sub-sea construction of the umbilical cords and flow-lines. Guyana Shorebase Inc was awarded the contract in June, 2017 for shore-base services and in August, 2017 the Noble Bob Douglas was hired for drilling services.
ExxonMobil’s Country Manager, Rod Henson also used the opportunity of the official start of the Liza Phase 1 Development Programme to show off that in the first quarter of 2018, over US$14 million were spent with Guyanese suppliers; together with its contractors ExxonMobil utilized 262 Guyanese registered suppliers, 227 of which are Guyanese owned.
Minister of Natural Resources, Raphael Trotman reiterated that the revised ExxonMobil Production Sharing Agreement has “the same or very similar contractual terms” as those Guyana has signed with other companies such as Anadarko Petroleum, Ratio, CGX, REPSOL, Ratio, Eco-Atlantic and Mid Atlantic.
“In that regard, they will enjoy the same rights and obligations as every other company that has been contracted by the government to explore and develop our hydrocarbons.
That they were the first to find a large deposit should no redefine their contractual terms or place them in any position less than that enjoyed prior to discovery. For government to do otherwise is not how responsible or how well-organised and governed States function,” she said.
The Minister of Natural Resources said the proceeds of Guyana’s oil production would be fairly shared among all Guyanese without discrimination as part of a process that would eventually lead to the removal of negative labels such as Third World, backwards, underdeveloped and developing from Guyana. “With the blessings that have been revealed, and are within our grasp, we purpose to develop a modern, peaceful and cohesive State-one in which every man, woman and child, without exception, reservation, and/or discrimination of any kind, is able to enjoy the full and equal benefits of the bounty we are about to be bestowed,” he said.
(Tsvetana Paraskova, OilPrice.com, 6.Jun.2018) — Venezuela’s President Nicolas Maduro has accused the United States of infiltrating senior positions at the Venezuelan oil industry.
“There was a process of penetration and infiltration in key positions of the petroleum industry, to control strategic information,” Maduro was quoted as saying at a meeting with workers at the struggling state oil firm PDVSA on Tuesday.
The embattled president, who has just won a presidential election deemed illegitimate by other nations, also called for an “economic counteroffensive” against what he described as a U.S. economic war on Venezuela.
“Now we will continue with an economic counteroffensive, the most difficult thing… we are going to win this battle for economic peace, for stability, for prosperity, and we are going to go the length in the fight against the criminal economy,” Maduro was quoted as saying.
Maduro’s claims against the U.S. come just as the Organization of American States (OAS) said in a resolution on Tuesday that it decided to “declare that the electoral process as implemented in Venezuela, which concluded on May 20, 2018, lacks legitimacy, for not complying with international standards, for not having met the participation of all Venezuelan political actors, and for being carried out without the necessary guarantees for a free, fair, transparent and democratic process.”
Earlier this week, U.S. Secretary of State Mike Pompeo asked the OAS to suspend Venezuela from the organization.
While attacking the U.S. for infiltrating the oil industry, Maduro told PDVSA workers to start a production “revolution” at the state oil company.
PDVSA’s oil production has been plummeting and it is currently around 1.4 million bpd, according to estimates.
PDVSA has recently told eight foreign clients that it would be unable to supply the contracted volumes of crude oil, a company employee told S&P Platts earlier this week. The affected clients due to the low availability of crude oil to export include Nynas, Tipco, Chevron, CNPC, Reliance, Conoco, Valero, and Lukoil, which will partially receive the volumes established by the contracts, according to the PDVSA official.
(Energy Analytics Institute, Special from Pietro D. Pitts, 28.May.2018) — Venezuela’s upstream, downstream and midstream sectors remain attractive, yet unattractive to investors.
Why the contradiction?
The three sectors remain highly attractive due to the fact that Venezuela — the country with the world’s largest crude oil reserve base and the eighth largest natural gas reserve base — is arguably one of the most attractive geological locations in the world. Petroleum reservoirs here contain light and medium oil deposits, while the Hugo Chavez Orinoco Heavy Oil Belt, also known as the Faja, contains the largest accumulation of heavy and extra-heavy crude oil (EHCO) in the world. From the prolific Lake Maracaibo in the west to the massive Faja in the east, the opportunity set is second to none. And that’s excluding other natural resources from iron ore to gold that makes this place that much more attractive.
However, above surface issues continue to ruin the energy party due to continued political, economic and financial turmoil as well as an ongoing humanitarian crisis. A look at just some of the micro issues of these crises, in no specific order, including corruption, price and currency controls, five-digit inflation, homicide rates among the highest in the world, kidnappings of foreigners and embassy employees, worthless currency, the Petro, a brain-drain of talent, a FDI drought, Nicolas Maduro, ongoing nationalization threats, gas deficits, black and brown outages, refinery output trending towards nothing, oil production in steady decline, service providers payment backlog, political appointees at PDVSA, drug trafficking, and mismanagement of resources, continue to prove Venezuela is not for the light of heart investors.
Taking these issues, among others, coupled with recent detentions of executives from companies from Houston-based Citgo Petroleum to PDVSA to California-based Chevron Corporation only serve as evidence to the still complicated operating environment that exists in this OPEC nation of around 30 million citizens.
Nowadays, political issues above ground continue to dictate what goes on below ground, even if indirectly. When has that ever been otherwise in Venezuela? There’s no doubt Venezuela — or if you prefer, Cuba with petroleum and the Russians (in contrast or comparison to Cuba and the Soviets in the past) — will remain a country to watch for petroleum investors for many years to come.
(AP, 27.May.2018) – Venezuela’s former oil czar said crude production in the OPEC nation will continue to plummet in the aftermath of President Nicolas Maduro’s re-election, as the embattled socialist leader takes the country down an increasingly authoritarian path that scares off private investment and leads to more international sanctions against his Government.
In a rare interview, Rafael Ramirez on Friday blasted Maduro, saying that in the wake of his recent victory he has showed no signs of reversing policies blamed for hyperinflation and widespread shortages.
“The demons have been unleashed,” Ramirez, who went into exile after a bitter split last year with Maduro, said in a phone interview from an undisclosed location. “Maduro keeps insisting on the same rhetoric, taking no responsibility for his own actions.”
Maduro coasted to another six-year term in an election last Sunday that was boycotted by the biggest opposition parties and condemned as rigged in his favour by several foreign governments. The Trump Administration responded by tightening sanctions on the Government, making it tougher for State-run oil giant PDVSA to raise badly-needed cash to pay off creditors and jumpstart production.
Ramirez, who headed the oil industry for a decade until 2014, said a purge that started last year and has led to the arrest of more than 80 PDVSA managers, including its president, as well as the arrest last month of two managers at Chevron, has paralysed oil production.
Since Ramirez was removed from his dual post as energy minister and PDVSA boss in 2014, production has tumbled almost 40 per cent, to 1.4 million barrels of oil per day, the lowest level in seven decades. He predicts that unless Maduro changes course, it could fall soon to 900,000 barrels per day, the bulk of which is already sold at a huge loss domestically or used to pay off debts to China and Russia.
He also pointed to a recent decree signed by Maduro giving PDVSA’s newly installed president, Major General Manuel Quevedo, special powers to rewrite the terms of PDVSA’s joint ventures with foreign oil companies, circumventing the constitutionally-mandated oversight of the Opposition-controlled National Assembly.
“There’s a climate of terror inside the oil industry and everyone is afraid to make decisions,” he said.
PDVSA and Venezuela’s Information Ministry didn’t respond to requests seeking comment.
Ramirez, who was close to the late Hugo Chavez, quit as the country’s ambassador to the United Nations in December amid a public feud with Maduro over the direction of economic policy. Ramirez had been arguing for a more pragmatic course that included unifying Venezuela’s multi-tiered exchange rates while Maduro doubled down on policies to attack criminal “mafias” and going after opposition groups he blamed for waging an “economic war” with the backing of the US.
In January, chief prosecutor Tarek William Saab announced he would seek Ramirez’s arrest for allegedly profiting from illegal oil sales. Several close associates including his nephew have already been arrested in Venezuela and two former deputies were picked up in Spain last year on a US warrant as part of a separate probe led by prosecutors in Houston into corruption at PDVSA under Ramirez’s watch.
Ramirez rejects the accusations and said that his conscience is clear. Since leaving the US last year, he said he’s moved among cities around the world and avoided returning to Venezuela for fear of arrest.
“It hurts me because in the name of pursuing corruption Maduro has destroyed the industry so he can take control of PDVSA,” he said.
He said that none of the people running PDVSA today have experience in the oil industry, and coupled with the departure of thousands of oil engineers, the company that is the source of almost all of Venezuela’s export earnings is on the verge of collapse. A recent display of what he considers the current management’s incompetence was its failure to outmanoeuvre Houston-based ConocoPhillips’ attempts to collect on a US$2 billion arbitration award, which forced PDVSA to scramble and divert oil tankers from its facilities in the Dutch Caribbean for fear of seizure.
Ramirez said that he headed off a similar legal action years ago by Exxon Mobil in the United Kingdom.
“What’s surprising, and concerning, is that PDVSA didn’t anticipate this,” he said. “If the actions of a single company have jeopardised the entire country, imagine what will happen if the US imposes sanctions.”
(Energy Analytics Institute, Aaron Simonsky, 24.May.2018) – Energy Analytics Institute, formerly LatinPetroleum Inc., continues to promote its “Energy Education Initiative” in the Americas, also known as “NRG ED.”
NRG ED is structured to work with K-12 schools, community colleges, four-year colleges and universities, workforce training programs, communities and businesses, and aims to promote reduction of non-renewable energy usage in favor of renewable energies. However, the core of the initiative is education, without which the NRG ED initiative would not be.
“At its core the initiative is really focused on education,” said Chad Archey, Editor-in-Chief at Energy Analytics Institute from Atlanta, Georgia.
EAI views basic education as most important in the overall learning process and also promotes educational initiatives and research from grade school to the professional level related to the energy sector. EAI aims to foment constructive dialogue regarding energy usage as well as ways to reduce the carbon footprint left by non-renewable energy resources through the following: 1) educational consultancy, 2) development and distribution of educational and training materials, and 3) promotion of debate and discussion regarding renewable energy alternatives.
Energy Analytics Institute (EAI), formerly LatinPetroleum Inc. (dba LatinPetroleum.com), is a Houston-based independent company focused on producing non-biased news, updates and special reports for investors interested in the Latin America and Caribbean petroleum sectors.
(Platts, 18.May.2018) — Ahead of Sunday’s presidential election in Venezuela, Risa Grais-Targow, director-Latin America, at the Eurasia Group, spoke to S&P Global Platts about the expected US response, the impact of rising oil prices on sanctions and the ongoing collapse of the country’s oil sector.
The interview has been edited for brevity and clarity.
PLATTS: What do you expect the US response will be to Sunday’s election?
GRAIS-TARGOW: I think the US has already been pretty clear that they view these elections as fraudulent. So I think, at a minimum, they will reject the results and refuse to recognize them. There could be some additional sanctions in response as well.
PLATTS: What will those sanctions look like?
GRAIS-TARGOW: The signaling from the [Trump] administration in more recent weeks has been less in the direction of aggressive sanctions right off the bat. I think especially with [exit from] the Iran deal they seem to be a bit more concerned about international oil prices and higher domestic gasoline prices. Obviously, their Iran policy contributes to that and it seems like, even though we have a more hawkish foreign policy team, there may be a bit more reluctance to add Venezuela to those pressures as well. I think that it would be, maybe, milder sanctions to begin with, something more like a ban on the sale of diluents and lighter crudes to Venezuela or potentially an insurance-related ban that would affect their oil cargoes. But it seems like the import ban that was being discussed a few months ago more actively is now looking like something that would only happen over a longer time frame.
PLATTS: What would need to occur for an import ban to go forward?
GRAIS-TARGOW: In general, the preference here has been to escalate sanctions. The fact that we haven’t had those initial, targeted sanctions for the oil sector happening before the vote means that you start with them after the vote. To the extent that it doesn’t change the Maduro administration’s behavior then we could still escalate towards an import ban. But it seems like we would probably start with milder actions and escalate towards that, using the threat of more aggressive actions as a potential deterrent.
PLATTS: Is there an outcome Sunday in Venezuela that wouldn’t draw a US response?
GRAIS-TARGOW: I think the only scenario in which we don’t is if [Venezuelan presidential candidate Henri]Falcon somehow manages to win, which, in my view, is pretty unlikely at this point.
PLATTS: What impact have existing sanctions had on Venezuela’s oil sector?
GRAIS-TARGOW: Some of the sanctioned individuals had been executives at PDVSA, so what we saw last year was some reluctance to enter into deals with PDVSA. The existing sanctions, the financial sanctions that were imposed in August, those have had a much more severe impact on the oil sector. They don’t allow the government to issue promissory notes to service providers and so that’s really hurt their ability to maintain these relationships with service providers and it’s one of the reasons that we’ve seen such aggressive production declines over the past six months or so.
PLATTS: How much are oil prices at the moment impacting what the US response to Venezuela could be?
GRAIS-TARGOW: It’s certainly a factor. We had Trump tweeting out a few weeks ago this attack on OPEC over oil prices. It does seem to be something that he’s concerned about. If you look at historic trends, higher domestic gasoline prices tend to really change domestic economic sentiment and generally tend to hurt the administration. That’s something the government obviously wants to avoid with November mid-terms. Especially since we’re entering into peak summer driving season, that’s become more of a consideration as they think about the policy response to Venezuela.
PLATTS: Where is rock bottom for Venezuela’s oil sector? Are we already there?
GRAIS-TARGOW: I think we’ve all been shocked at the acceleration of production declines. I’ve generally seen a floor owing to the joint ventures, which are much more functional than PDVSA’s solely operated production. That range is 900,000 b/d to 1.1 million b/d that are being operated as joint ventures. That, to me, has always been the floor. The challenge now is that the government has been more aggressive with its joint venture partners and so now we’re in a new era where we could see the joint venture partners starting to reduce their presence or suspend operations. If we see some of the western companies starting to pull out owing to safety concerns or some of these issues and concerns about their human capital then I think that floor starts to sink further.
(Energy Analytics Institute, Aaron Simonsky, 18.May.2018) – Venezuela’s oil production continues to fall, and further declines are anticipated due to a number of problems at state oil company PDVSA, according to a report by Caracas Capital Markets.
“Venezuela’s oil production has now fallen from 3.5 million barrels per day when Hugo Chavez was elected in 1998 to 1.436 bpd last month. Instead of going up to 6-8mm bpd where Venezuela’s oil production should have been by 2008, Venezuela’s oil production has returned to the level it first achieved in 1949,” wrote Russ Dallen, Managing Director at Caracas Capital Markets, in a report last week to clients.
Dallen, a bond trader, further said: “We haven’t yet fallen back to 1948 levels, but we anticipate that we will return to 1948 this month, when Venezuela was producing 1.339 million bpd. By 1950, Caracas was producing 1.497 million bpd — even more than it is currently producing.”
The U.S. is now exporting over 1.6 million barrels of crude oil per day – more than all of Venezuela’s total production, according to Dallen who wanted to “put Venezuela’s disastrous fall in oil production to 1.436 million bpd in perspective.”
Further declines in Venezuela’s oil production are expected due to a number of problems that continue to stymie PDVSA, wrote Dallen.
(Energy Analytics Institute, Jared Yamin, 14.May.2018) – Venezuela’s state oil company Petróleos de Venezuela, S.A. (PDVSA) is bankrupt, at least that what its former president Luis Giusti thinks.
“If you look at the signs … they all point to a company that is bankrupt,” said Giusti during a televised interview on the Bayly show on 27 April 2018 with host Jamie Bayly.
Giusti initiated his career at Shell Corporation in Venezuela. He later worked at Maraven, S.A., a PDVSA operating affiliate. In 1994, Giusti was named chairman and CEO of PDVSA, positions he maintained until March of 1999, according to data posted to the website of the Center for Strategy & International Studies (CSIS), an organization where Giusti served as a senior advisor directly after departing PDVSA in 1999.
At the helm of PDVSA, Giusti oversaw major reforms to the Venezuelan petroleum sector including opening the sector to private participation, which attracted foreign direct investments (FDI) between 1995-2004 estimated at around $30 billion.
An engineer by profession, Giusti graduated from the University of Zulia in 1966, and received a M.S. in petroleum engineering from the University of Tulsa in 1971.
What follows are short extracts from the interview:
BAYLY: Why has Venezuela sent so much oil to the U.S. over the years?
GIUSTI: A lot of Venezuela barrels always went to the U.S. for a reason that is clear and precise, and that is due to the decisions made by many refineries along the Gulf Coast to invest in deep conversion capacity and to buy cheaper raw material.
Of the seven refineries in Venezuela only one is operating and the reason is simple and much more than efficiency losses and installation deteriorations. They’re simply not operating because there is no petroleum in Venezuela to process. (See Note 1)
BAYLY: If the US asked you what it could do to assist Venezuela such as to cease imports of Venezuelan crude oil or cease exports of U.S. gasoline to Venezuela, what would you recommend?
GIUSTI: It’s a bit difficult because you need to surmise the crises the citizens are living right now and take into consideration whether such a measure could turn everything around to achieve a change in a reasonable time in Venezuela. I would say that is the main concern.
BAYLY: How much money has been stolen from PDVSA?
GIUSTI: Venezuela and PDVSA are in the situation they are now due to a mismanagement of funds, without even talking about corruption.
After ten years of discretional uses of resources under the mandate of Chavez, we know that much of the funds went to personal accounts. Over a good 10-year period of Chavismo the amount that has been stolen could easily surpass $100 billion.
BAYLY: Is PDVSA bankrupt?
GIUSTI: Since PDVSA is a company of the state, it will never declare in bankruptcy. But, if you look at signs such as: not being able to pay bond returns, the Chinese’s unwillingness to lend more money, declining production levels, and salaries around $5 per month, among others signs, they all point to a company that is bankrupt.
BAYLY: What about the fact that is now run by military personnel?
GIUSTI: Military personnel who could be good or bad in their profession run PDVSA, but they are military personnel that don’t know anything about the petroleum sector.
BAYLY: How does Venezuela exit this disaster?
GIUSTI: It’s a hard question to answer but we are in the presence of a binary decision. There will not be talks about our understandings, or that we will team up. The scenario comes down to the persons in power leaving or there’s no way to resolve this.
Editor’s Note 1: The PDVSA refineries located in Venezuela include: Amuay (645 Mb/d), Cardon (310 Mb/d), Puerto La Cruz (187 Mb/d), El Palito (140 Mb/d), Bajo Grande (16 Mb/d) and San Roque (5 Mb/d), according to PDVSA data.
(Reuters, 13.May.2018) – A Curacao court has authorized ConocoPhillips to seize about $636 million in assets belonging to Venezuela’s state oil company PDVSA due to the 2007 nationalization of the U.S. oil major’s projects in Venezuela.
The legal action was the latest in the Caribbean to enforce a $2 billion arbitration award by the International Chamber of Commerce (ICC) over the nationalization.
The court decision, first reported by Caribbean media outlet Antilliaans Dagblad on Saturday, says Curacao can attach “oil or oil products on ships and on bank deposits.”
Conoco and PDVSA did not immediately respond to requests for comment on the decision, which was seen by Reuters and dated May 4.
Conoco earlier this month moved to temporarily seize PDVSA’s assets on Aruba, Bonaire, Curacao and St. Eustatius. That threw Venezuela’s oil export chain into a tailspin just as Venezuela’s crude production has crumbled to a more than 30-year low due to underinvestment, theft, a brain drain and mismanagement.
Reuters reported on Friday that PDVSA was preparing to shut down the 335,000 barrel-per-day Isla refinery it operates in Curacao amid threats by Conoco to seize cargoes sent to resupply the facility.
PDVSA is also seeking ways to sidestep legal orders to hand over assets. The Venezuelan firm has transferred custody over the fuel produced at the Isla refinery to the Curacao government, the owner of the facility, according to two sources with knowledge of the matter.
PDVSA transferred ownership of crude to be refined at Isla to its U.S. unit, Citgo Petroleum, one of the sources said.
For the time being, PDVSA has suspended all oil storage and shipping from its Caribbean facilities and concentrated most shipping in its main crude terminal of Jose, which is suffering from a backlog.
(Tsvetana Paraskova, OilPrice.com, 28.Mar.2018) – If crisis-hit Venezuela was hoping to pay off its US$3.15-billion debt to Russia with its new cryptocurrency, those hopes have been shattered as the Russian Finance Ministry announces that it won’t be accepting digital coin.
Venezuela will not be paying any part of its debt to Russia with its cryptocurrency, the head of the Russian Finance Ministry’s state debt department, Konstantin Vyshkovsky, has said.
In November last year, Russia threw a life-line to Venezuela after the two countries signed a deal to restructure US$3.15 billion worth of Venezuelan debt owed to Moscow. Under the terms of the deal, Venezuela will be repaying the debt over the next ten years, of which the first six years include “minimal payments”.
The following month, Venezuelan President Nicolas Maduro announced that his country would be issuing an oil-backed cryptocurrency, which it did, in February this year.
Maduro’s propaganda machine is touting the digital coin as a ‘ground-breaking’ first-ever national crypto currency, the El Petro–backed by 5 billion barrels of oil reserves in Venezuela’s Orinoco Belt.
But most observers see this crypto issuance as a desperate attempt to skirt U.S. financial sanctions.
Earlier this month, U.S. President Donald Trump banned U.S. purchases, transactions, and dealings of any digital coin or token issued for or by the government of Venezuela.
Last week, Time magazine reported that Russia secretly helped Venezuela in creating the Petro, with the purpose of undermining the power of U.S. sanctions, the magazine reported, citing sources familiar with the effort.
Russia slammed the Time report as “fake news”, with Deputy Director of the Information and Press Department of the Russian Foreign Ministry, Artyom Kozhin, saying that Russia and Venezuela had never worked together on the development of the Venezuelan cryptocurrency.
Russia and China are the last holdouts that still finance Venezuela, which is digging deeper into the downward spiral of economic crisis, hyperinflation, and crumbling oil production. However, China is reportedly thinking of cutting off Venezuela from new loans. This would leave Russia as the only financial supporter of the Maduro regime, and if all it’s got is a crypto coin that no one really believes in to pay off debt, loans are likely to be plentiful.
(Reuters, David Alire Garcia & Marianna Parraga, 27.Mar.2018) — Mexico awarded just under half of the 35 shallow-water blocks it tendered on Tuesday, in an auction muddied by the promises of the presidential frontrunner to review contracts awarded under a historic energy opening if he wins the July 1 election.
The country’s oil regulator awarded 16 blocks in the Gulf of Mexico to firms including Spain’s Repsol, France’s Total, Italy’s Eni, Britain’s Premier Oil and Mexico’s state-run Pemex, which was the biggest winner overall.
A final, competitive round of bidding in the Southeast Basins improved what started as a patchy showing, with little interest in fields believed to contain high amounts of natural gas.
About $8.6 billion in investment is expected from the projects to be developed in the awarded blocks, Mexico’s Energy Minister Pedro Joaquin Coldwell said, with early production starting in 2022 and a production potential of 280,000 barrels per day (bpd).
Andres Manuel Lopez Obrador, who has a comfortable lead in most polls, said that if he wins the July vote, he would review more than 90 contracts signed since Mexico passed legislation in 2013 ending Pemex’s 75-year monopoly, looking for signs of corruption.
Running for office for a third time, Lopez Obrador has also said he would hold a referendum on the future of the reform, and ask President Enrique Pena Nieto to cancel two auctions planned for the second half of the year.
Mexico’s next president takes office in December.
Despite the political uncertainty, Tim Davis, the group exploration manager for Premier Oil, said he was bullish about the future of the oil and gas opening.
“I think you could see a slowdown (if Lopez Obrador wins). But … I think they will see the benefits,” of the investment that’s coming in and the invigoration of new ideas and new companies arriving.
Repsol and Premier Oil individually claimed two areas each in the shallow-water fields offered in the Burgos basin, where less than a third of blocks were awarded. Premier won another block in a consortium with DEA Deutsche Erdoel and Sapura Energy.
Consortia made up of state-run Pemex, Mexico’s Citla Energy, Spain’s Cepsa, Britain’s Capricorn Energy and Germany’s DEA Deutsche Erdoel posted winning bids for four blocks in the Tampico-Misantla-Veracruz basin further south along the Gulf. There, around a third of blocks were awarded.
In the final Southeast Basins tender, competition was higher, and the oil regulator awarded all eight of the shallow-water blocks it tendered to consortia including Total, Eni, Royal Dutch Shell and Pemex.
“This is very high percentage (of awarded blocks),” said Coldwell.
Mexico’s government collected $124 million in cash payments from the auction, below the $525 million collected in a January deepwater auction.
The Southeast Basins areas are located in a portion of the Gulf where many of the companies that won blocks on Tuesday had already secured areas in earlier shallow and deepwater bidding rounds.
By securing neighboring blocks in the Gulf, companies are able to build clusters in order to reduce infrastructure costs.
Mexico’s Deputy Secretary for Hydrocarbons Aldo Flores blamed the weaker early interest on the quantity of natural gas areas in the auction, saying companies were more interested in finding crude.
“This will continue to be a challenge for us given the abundance of natural gas in Texas at very low prices,” Flores told Reuters on the sidelines of the auction in Mexico City.
Mexico is also competing for private companies’ interest with Brazil, which is holding its own auction this week, with another scheduled in June.
Brazil holds its own election in October, with the most likely leftist contender in the presidential race, Ciro Ferreira Gomes, warning he would expropriate energy assets bought by investors if he wins.
(Reporting by David Alire Garcia, Adriana Barrera and Marianna Parraga; Writing by Gabriel Stargardter Editing by Frank Jack Daniel, Susan Thomas and Diane Craft)
(Exxon Mobil, 28.Feb.2018) – Exxon Mobil Corporation announced its seventh oil discovery offshore Guyana, following drilling at the Pacora-1 exploration well.
ExxonMobil encountered approximately 65 feet (20 meters) of high-quality, oil-bearing sandstone reservoir. The well was safely drilled to 18,363 feet (5,597 meters) depth in 6,781 feet (2,067 meters) of water. Drilling commenced on Jan. 29, 2018.
“This latest discovery further increases our confidence in developing this key area of the Stabroek Block,” said Steve Greenlee, president of ExxonMobil Exploration Company. “Pacora will be developed in conjunction with the giant Payara field, and along with other phases, will help bring Guyana production to more than 500,000 barrels per day.”
The Pacora-1 well is located approximately four miles west of the Payara-1 well, and follows previous discoveries on the Stabroek Block at Liza, Payara, Liza Deep, Snoek, Turbot and Ranger.
Following completion of the Pacora-1 well, the Stena Carron drillship will move to the Liza field to drill the Liza-5 well and complete a well test, which will be used to assess concepts for the Payara development. ExxonMobil announced project sanctioning for the Liza phase one development in June 2017. Following Liza-5, the Stena Carron will conduct additional exploration and appraisal drilling on the block.
The Stabroek Block is 6.6 million acres (26,800 square kilometers). Esso Exploration and Production Guyana Limited is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration Ltd. holds 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent interest.
(Exxon Mobil, 5.Jan.2018) – Exxon Mobil Corporation announced positive results from its Ranger-1 exploration well, marking ExxonMobil’s sixth oil discovery offshore Guyana since 2015.
The Ranger-1 well discovery adds to previous world-class discoveries at Liza, Payara, Snoek, Liza Deep and Turbot, which are estimated to total more than 3.2 billion recoverable oil-equivalent barrels.
ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. began drilling the Ranger-1 well on Nov. 5, 2017 and encountered approximately 230 feet (70 meters) of high-quality, oil-bearing carbonate reservoir. The well was safely drilled to 21,161 feet (6,450 meters) depth in 8,973 feet (2,735 meters) of water.
“This latest success operating in Guyana’s significant water depths illustrates our ultra deepwater and carbonate exploration capabilities,” said Steve Greenlee, president of ExxonMobil Exploration Company. “This discovery proves a new play concept for the 6.6 million acre Stabroek Block, and adds further value to our growing Guyana portfolio.”
Following completion of the Ranger-1 well, the Stena Carron drillship will move to the Pacora prospect, 4 miles from the Payara discovery. Additional exploration drilling is planned on the Stabroek Block for 2018, including potential appraisal drilling at the Ranger discovery.
The Stabroek Block is 6.6 million acres (26,800 square kilometers). Esso Exploration and Production Guyana Limited is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration Ltd. holds 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent interest.
(Exxon Mobil, 5.Oct.2017) – Exxon Mobil Corporation announced it made a fifth new oil discovery after drilling the Turbot-1 well offshore Guyana.
Turbot is ExxonMobil’s latest discovery to date in the country, adding to previous discoveries at Liza, Payara, Snoek and Liza Deep. Following completion of the Turbot-1 well, the Stena Carron drillship will move to the Ranger prospect. An additional well on the Turbot discovery is being planned for 2018.
ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. began drilling the Turbot-1 well on Aug. 14, 2017 and encountered a reservoir of 75 feet (23 meters) of high-quality, oil-bearing sandstone in the primary objective. The well was safely drilled to 18,445 feet (5,622 meters) in 5,912 feet (1,802 meters) of water on Sept. 29, 2017. The Turbot-1 well is located in the southeastern portion of the Stabroek Block, approximately 30 miles (50 kilometers) to the southeast of the Liza phase one project.
“The results from this latest well further illustrate the tremendous potential we see from our exploration activities offshore Guyana,” said Steve Greenlee, president of ExxonMobil Exploration Company. “ExxonMobil, along with its partners, will continue to further evaluate opportunities on the Stabroek Block.”
The Stabroek Block is 6.6 million acres (26,800 square kilometers). Esso Exploration and Production Guyana Limited is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration Ltd. holds 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent interest.
(Exxon Mobil, 25.Jul.2017) – Exxon Mobil Corporation announced it has discovered additional oil in the Payara reservoir offshore Guyana, increasing the total Payara discovery to approximately 500 million oil-equivalent barrels.
These positive well results increase the estimated gross recoverable resource for the Stabroek Block to between 2.25 billion oil-equivalent barrels and 2.75 billion oil-equivalent barrels.
The well was successfully drilled by ExxonMobil affiliate Esso Exploration and Production Guyana Limited and encountered 59 feet (18 meters) of high-quality, oil-bearing sandstone in the Payara field.
It was safely drilled to 19,068 feet (5,812 meters) in approximately 7,000 feet (2,135 meters) of water. The well is only 12 miles (20 kilometers) northwest of the recently funded Liza phase 1 project on the Stabroek Block, which is approximately 130 miles offshore Guyana.
“Payara-2 confirms the second giant field discovered in Guyana,” said Steve Greenlee, president of ExxonMobil Exploration Company. “Payara, Liza and the adjacent satellite discoveries at Snoek and Liza Deep will provide the foundation for world class oil developments and deliver substantial benefits to Guyana. We are committed to continue to evaluate the full potential of the Stabroek Block.”
The Stabroek Block is 6.6 million acres (26,800 square kilometers). Esso Exploration and Production Guyana Limited is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration Ltd. holds 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent interest.
(Exxon Mobil, 13.Jul.2017) – Exxon Mobil Corporation announced that its subsidiary ExxonMobil Exploration and Production Suriname B.V., along with co-venturers Hess and Statoil, signed a production sharing contract for Block 59 with Staatsolie Maatschappij Suriname N.V., the national oil company of Suriname. The block adds significant acreage to ExxonMobil’s operated portfolio in the Guyana-Suriname Basin.
Deepwater Block 59 is in water depths ranging from nearly 2,000 meters to 3,600 meters, located approximately 190 miles (305 kilometers) offshore Suriname’s capital city, Paramaribo. The block is 2.8 million acres, or 4,430 square miles, and shares a maritime border with Guyana, where ExxonMobil is the operator of three offshore blocks, including the world-class Liza field discovered by ExxonMobil in 2015.
“We look forward to working with Staatsolie and our co-venturers to evaluate the potential of this new acreage,” said Steve Greenlee, president of ExxonMobil Exploration Company. “Adding this block enhances our leading global deepwater portfolio.”
Suriname represents a new country for ExxonMobil’s upstream business. The company has investments throughout South America. Following contract signing, the co-venturers are preparing to begin exploration activities, including acquisition and analysis of seismic data.
ExxonMobil and consortium partners Hess and Statoil each hold a third of the interest in the block. ExxonMobil is the operator.
(Exxon Mobil, 16.Jun.2017) – Exxon Mobil Corporation said it has made a final investment decision to proceed with the first phase of development for the Liza field, one of the largest oil discoveries of the past decade, located offshore Guyana.
The company also announced positive results from the Liza-4 well, which encountered more than 197 feet (60 meters) of high-quality, oil-bearing sandstone reservoirs, which will underpin a potential Liza Phase 2 development. Gross recoverable resources for the Stabroek block are now estimated at 2 billion to 2.5 billion oil-equivalent barrels, which includes Liza and other successful exploration wells on Liza Deep, Payara and Snoek.
The Liza Phase 1 development includes a subsea production system and a floating production, storage and offloading (FPSO) vessel designed to produce up to 120,000 barrels of oil per day. Production is expected to begin by 2020, less than five years after discovery of the field. Phase 1 is expected to cost just over $4.4 billion, which includes a lease capitalization cost of approximately $1.2 billion for the FPSO facility, and will develop approximately 450 million barrels of oil.
“We’re excited about the tremendous potential of the Liza field and accelerating first production through a phased development in this lower cost environment,” said Liam Mallon, president, ExxonMobil Development Company. “We will work closely with the government, our co-venturers and the Guyanese people in developing this world-class resource that will have long-term and meaningful benefits for the country and its citizens.”
The Liza Phase 1 development can provide significant benefits to Guyana, including jobs during installation and operations, workforce training, local supplier development and government revenues to fund infrastructure, social programs and services.
The development received regulatory approval from the government of Guyana.
The Liza field is approximately 190 kilometers offshore in water depths of 1,500 to 1,900 meters. Four drill centers are envisioned with a total of 17 wells, including eight production wells, six water injection wells and three gas injection wells.
The Liza field is part of the Stabroek Block, which measures 6.6 million acres, or 26,800 square kilometers. Esso Exploration and Production Guyana Limited is operator and holds a 45 percent interest in the block.
Hess Guyana Exploration Ltd. holds a 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent.
Esso Exploration and Production Guyana Limited is continuing exploration activities and operates three blocks offshore Guyana – Stabroek, Canje and Kaieteur. Drilling of the Payara-2 well on the Stabroek block is expected to commence in late June and will also test a deeper prospect underlying the Payara oil discovery.
(Energy Analytics Institute, Pietro D. Pitts, 27.Jan.2017) – Taiwan’s president got the call, Mexico’s president will get a wall. At least, that’s what U.S. President Donald Trump is proclaiming.
From all accounts, Mexico’s President Enrique Peña Nieto has not been shown the same courtesy as Taiwan’s President Tsai Ing-wen. Witnessing the manner in which Trump has treated trade partner Mexico over the U.S.-Mexico border wall, it is safe to assume that other partners could be in for worse or harsher treatment less they offer something that is first in Americas’ interest. The visit by United Kingdom’s Primer Minister Theresa Mary May to Washington is a case in point regarding the latter.
Trump may be a successful and wealth businessman but much talent is missing and desired in his role as a statesman. The ruthless manner in which he is dealing with Mexico, a key trading partner under the North American Free Trade Agreement (NAFTA), in the name of nationalism, is alarming at most.
As a result, countries in the Latin American and Caribbean (LAC) region — and worldwide for that matter — that export products and services to the U.S. better brace themselves for what U.S. Speaker of the House of Representatives Paul Ryan recently called ‘an unconventional’ presidency.
LAC region countries that should be worried — if not already, they should and better be — about the ongoing bout between Trump vs. Peña Nieto include but are not limited to: Argentina (some exports to the U.S.: aluminum, wines), Brazil (mineral fuels, aircraft, iron, steel), Chile (copper, fish, seafood, wine), Colombia (mineral fuels, coffee, cut flowers), Ecuador (mineral fuels, seafood), Peru (precious metals, mineral fuels), and Nicolas Maduro’s Venezuela (crude oil). The list goes on.
Most of my concern is for the latter country since crude oil exports constitute 96 percent of its foreign export revenues, and due to the fact that this OPEC-member country is the lone one in the LAC region with basically one export product. Additionally, should Trump view the asset expropriations in the oil sector under late Venezuelan President Hugo Chávez as unfair (remember U.S.-based oil giants ConocoPhillips and ExxonMobil were pushed out or kicked out, depending on your view of what happened and how), the government of Maduro & Company could be in for a big surprise. Trump’s revival of the Keystone XL Pipeline project could easily displace some if not all of the crude oil that Venezuela currently exports to the U.S. Gulf Coast.
On the flip side, Trump’s ‘America First’ nationalist message could someday be a good thing for importreliant Venezuela seeing that the country – which imports basically everything, is practically a war zone with homicide rates constantly around 30,000 each year, and which cannot devalue its already worthless currency to export itself out of its crisis – will need to rebuild nearly all its industries once the regime change occurs. How and when are the lingering questions regarding said change.
If there were ever a time to push for strengthening regional integration among the LAC region countries, it’s now. Existing initiatives that come to mind including Mercosur, Alba, and Celac, among others, should be revisited and improved. If Mexican products are indeed slapped with a 20 percent tax into the U.S., many will need to be redirected to other countries around the world. Why shouldn’t some of these products be redirected to LAC region countries?
Back to Venezuela. Since Maduro is unlikely to visit Washington and Trump less likely to visit Caracas, we’ll all have to wait for their political bout to play out on Twitter. It would be wise if LAC region officials started to have these regional trade discussions now and take a proactive, not reactive approach to Trumpism.
(Energy Analytics Institute, Pietro D. Pitts, 14.Sep.2016) – On a brief taxi ride from Punto Fijo’s Josefa Camejo International Airport to the main highway that crosses this city and connects to one of the many refining complex entrances here, a scrawny dog with mange can be seen emerging from an endless pile of discarded trash.
In this small refining town broken beer bottles, dirty diapers, and discarded personal items cling to trees and bushes as far as the eye can see in either direction along the short stretch of highway that separates the two massive refineries here: Amuay and Cardón. The refineries comprise the lion’s share of the processing capacity at PDVSA’s 971,000 barrel-a-day Paraguana Refining Complex, also commonly known as the CRP by its Spanish acronym. The CRP refineries combined with three others spread across this country have produced cumulative financial losses of $53 billion in the last eight years. Definitely not chump change.
Venezuela is home to a wealth of natural resources from gold to iron ore and holds the world’s eighth-largest natural gas reserves and the largest crude oil reserves, according to BP’s Statistical Review of World Energy. Yet, images of the immediate surroundings of the CRP paint a different financial storyboard about the well-being of Venezuela’s all important oil sector – which generates 96 percent of the country’s foreign export earnings.
Despite Venezuela’s claim to fame in terms of the size of its oil reserves, the South American country has been reduced to importing refined products because its refineries can’t meet local demand. The country’s refining sector is in a virtual state of emergency due to low processing rates, numerous unplanned plant stoppages, as well as accidents and injuries that state oil company Petróleos de Venezuela S.A. prefers to not report, according to oil union officials here. All summed up, PDVSA’s refining sector – especially within Venezuela – is a financial drain on the company as operating losses continue to mount year after year.
Venezuela – a founding member of the Organization of Petroleum Exporting Countries or OPEC — is engulfed in an economic crisis that started way before oil prices began their long downward trend. Political uncertainty, an ongoing threat of asset expropriations as well as currency and price controls have only helped to starve the capital-intense oil sector here of necessary foreign investments. PDVSA, as the Caracas-based company is known, continues to lack the necessary cash to properly revive the country’s oil sector in its majority partnership role, while local Venezuelan oil companies are few and in between and often lack the financial firepower of many of their international peers.
Many Venezuelan-based economists from Datanálisis President Luis Vicente León to Ecoanalitica Director Asdrubal Oliveros blame part of the economic crisis on the failure by former populist Venezuelan President Hugo Chávez to divert financial resources to the country’s private sector importers and the all-important upstream, midstream and downstream sectors during his tenure from 1999-2013 amid robust oil prices. In general, PDVSA’s problems mirror Venezuela’s economic crisis. The country’s economy has not fared any better under the presidential tenure of Nicolas Maduro, the man hand-picked by Chávez to succeed him prior to his untimely death in 2013. By most people’s accounts, considering the scarcities here of everything from milk to basic medicines, widespread looting, and runaway crime, things are much worst.
Oil-dependent Venezuela continues to rely heavily on its exploration and production or upstream sector to generate the bulk of its petroleum sector revenues. However, Venezuela’s oil output appears to be on an unstoppable decline, reaching 2,095,000 barrels per day in July of 2016 compared to 2,361,000 barrels per day in 2014, according to Organization of Petroleum Exporting Country’s Monthly Oil Market Report, citing secondary sources. Data from direct communications is just slightly more optimistic. Nevertheless, the downward continues.
Oil workers in red work overalls can be seen everywhere in the streets of Punto Fijo, either hailing taxis or waiting in the shade of trees for public transportation. Due to the ongoing economic crisis that has also affected Venezuela’s transportation industry – like countless other industries here – many cars and taxis in these parts and others in this resource-rich country don’t have air conditioning and/or visually lack some part or another such as a rearview or side mirror, working locks, a speedometer or a functioning trunk. The market for used tires, or anything used, is booming in Venezuela as new tire imports have come to a virtual halt.
Inside the CRP complex – physically off limits to visitors without permission from PDVSA but very visible through the wired fences — the scene within is arguably not much better, as years of under-investment on maintenance, upgrades and safety protocols by the state oil company have unfortunately left the refineries and the grounds similarly forsaken. Against a backdrop of a country in the midst of an ongoing political crisis, many refinery workers here say a combination of 12-16 hours work days, a lack of employee benefits and arguably the lowest salaries for refinery workers anywhere in the world (in dollar terms) has also taken a toll on them as well as their colleagues.
Whether the refineries or the workers are in worst condition, is a judgment call, but at first glance they both appear to be on their last legs.
In the last eight years, PDVSA’s refining, trade and supply division accumulated net losses in each of the consecutive years since 2008, which was the last time the division reported a positive gain from its combined operations in Venezuela. All tallied, the division accumulated losses of $53 billion during 2008-2015, according to data compiled from PDVSA’s financial reports.
“With a cash crunch they have focused all efforts in the upstream where you make the money,” said Francisco J. Monaldi, Ph.D. and Fellow in Latin American Energy Policy & Lecturer in Energy Economics at Rice University’s Baker Institute for Public Policy in an e-mailed response to questions. “The lack of human resources adds to the lack of investment to generate the operational difficulties.”
Refining sector stoppages and costly repairs are generating large production and economic losses for PDVSA, said oil union representative Larry López during a late afternoon sit down chat at a run-down restaurant just two blocks from the Amuay refinery.
Venezuela doesn’t need refineries to be a major exporting country, former PDVSA President Rafael Ramírez told me in 2014 during a company-sponsored media trip to visit the CRP on the anniversary of the deadly explosion at Amuay that left at least 48 people dead. To this day, it is unclear if those comments justify the lack of attention that has been given to the country’s refining sector even now under the leadership of Stanford-trained Eulogio Del Pino.
Venezuela’s Information Ministry, the clearing house for questions for all of the country’s ministries, and media officials with PDVSA and the Venezuelan Oil Ministry did not reply to emails seeking comment on the company’s refining sector strategy or general comments for this article. Venezuela’s newly elected Petroleum Chamber President was also unavailable to comment on this article.
“Our refineries have always produced products to cover demand in the domestic market as well as the Caribbean. To export to the US and Europe we really don’t need to have refineries,” said Carlos Rossi, president of Caracas-based consulting firm EnergyNomics and formerly an economist with the Venezuelan Hydrocarbons Association or AVHI, in an interview in Caracas.
“Because the refineries have been seen as a low priority, PDVSA has focused more attention on the Faja,” said Rossi referring to the Hugo Chávez Oil Belt, formerly known as the Orinoco Heavy Oil Belt, home to one of the largest non-conventional oil deposits in the world.
PDVSA’s total hydrocarbon workforce mushroomed during 2000-2015 as the company stressed more importance on political affiliation and less on university or technical experience, said Eddie Ramírez, the director of Gente del Petróleo and a former PDVSA employee, in a phone interview from Caracas. At year-end 2015, PDVSA employed 114,259 direct hydrocarbon sector workers, up from just 42,267 when Chávez rose to power in 1999, according to PDVSA data.
PDVSA’s refining sector, which employed 9,391 workers in 2015, represented just 8.2 percent of the company’s total workforce in that year. In 2010, just 3,584 workers were employed in the refining sector, which represented a mere 3.8 percent of PDVSA’s total workforce.
Given PDVSA’s cash problems and its inability to generate positive free cash flow, the company’s plans to build six new multi-billion dollar upgraders, boost oil production and refining capacity to 6,000,000 barrels per day and 1,800,000 barrels per day respectively by 2019 seem to be optimistic and represent a major challenge for the state oil company.
PDVSA owns six refineries in Venezuela, which the company reports are strategically located to supply refined products to its major consumers. The refineries – which had a total combined processing capacity of 1,303,000 barrels per day, as of year-end 2015 – produce a product slate including but limited to: 91 and 95 grade gasolines, jet and diesel fuel, light naphtha, liquefied petroleum gas, solvents and residuals.
Due to a combination of problems, the six refineries were just processing a combined 616,000 barrels per day in August 2016, translating into an average utilization for PDVSA’s domestic refineries of 47.3 percent, said Ivan Freites, an oil union official with the United Federation of Venezuelan Oil Workers or FUTPV, which represents a large portion of PDVSA’s workers, during an interview in Punto Fijo.
Two refineries are located in Venezuela’s western Falcon state including: Amuay, with a 645,000 barrel-a-day processing capacity; Cardón, with a 310,000 barrel-a-day capacity; while the smaller Bajo Grande is located in Zulia state, with a 16,000 barrel-a-day capacity. Together, the three refineries make up the CRP, according to PDVSA’s annual report for 2015, with a product slate destined 55 percent for the domestic market and 45 percent for the export market.
More centrally located is the El Palito refinery in Carabobo state with a 140,000 barrel-a-day capacity while the remaining two refineries located in Venezuela’s eastern Anzoátegui state include Puerto La Cruz, with an 187,000 barrel-a-day capacity and the smaller San Roque, with a 5,000 barrel-a-day capacity.
In 2015, Venezuela’s domestic refining sector reported average utilization rates of 66.2 percent, according to PDVSA’s operational and financial data from last year. This compares to an average utilization rate of 70.6 percent in 2014 and an average utilization rate of 72.8 percent during 2011-2014.
The CRP has suffered much more deterioration and lower utilization rates than the other refineries. Average utilization rates at the complex reached just 60.5 percent in 2015, down compared to 72 percent in 2011 and an average 67.7 percent during 2011-2014, according to PDVSA data, which differs to what oil union officials report.
“Average utilization rates at the CRP were just 53 percent in 2015,” said Freites, a stocky, long-time oil union official. “The complex is damaged to the point that it almost makes better sense to build new refineries than to fix the incalculable problems that exist.”
In contrast, average utilization rates at El Palito reached 71.4 percent in 2015, down from 90.7 percent in 2011 and an average 89.5 percent during 2011-2014 while at Puerto La Cruz rates reached 93.2 percent in 2015, up from 88 percent in 2011 and an average 88.6 percent during 2011-2014, according to PDVSA.
Figures reported by PDVSA are always overly positive and extremely optimistic, said Freites, 53, during an early happy hour brunch which included Venezuelan ‘tequeños’, a special mix here of fried cornmeal with cheese on the inside accompanied with another popular import here: whisky.
From oil towns in Midland, Texas to Maracaibo to Monagas and Punto Fijo in Venezuela, oil men have at least one thing in common: their love for food and the typical companions Grants, Chivas, and the rest of the supporting cast. However, the economic crisis here has forced many oilmen to settle for whatever is available at the kitchen table. With bottled water sometimes unavailable, Johnnie Walker becomes a name to trust.
PDVSA data differs significantly from that provided by oil union officials here and other international agencies due to the opaque operating and reporting nature of the state oil company. A quick comparison of Venezuela’s production figures as reported by PDVSA and Venezuela’s Oil Ministry as compared to figures reported by OPEC in its monthly reports or even BP in its yearly statistical review serve to prove the point.
Cash-strapped PDVSA recently reiterated plans to boost its domestic refining capacity to 1,800,000 barrels per day by 2019 but has not detailed plans for its existing refineries – which continue to process at less than optimal levels – and has been quiet about plans to build new refining capacity. Only the Puerto La Cruz refinery is known to be undergoing a deep conversion process aimed at boosting its ability to process heavier Venezuelan crudes, according to PDVSA.
Recent agreements signed by PDVSA with authorities from the governments of Aruba, Venezuela and Citgo Aruba related to the restart of a 209,000 barrel-per-day refinery located in San Nicolas, Aruba point to potential issues PDVSA may have building new refineries or even six planned new upgraders, a special type of refinery, due to financial constraints whereby at first glance it appears easier to buy refining capacity than build it from scratch.
It is not a priority to build refineries since it is much better to invest in upstream activities to maximize your limited resources, said Monaldi, also the founding director and a professor at the Center for Energy and the Environment at IESA in Venezuela. New refineries are not great moneymakers and require low capital cost to make any money, he said.
Just a handful of streets separate the Amuay refinery from the Las Piedras fishing neighborhood. Not far away, rusted out American gas-guzzlers like the Ford Maverick and even the Ford F-1, seemly pulled straight off the set of the 1970’s U.S. television show Sanford and Son, can be seen littering the narrow streets here as well as the ones behind Cardón refinery in the neighborhood that bears its name, Punta Cardón. Residents of the latter neighborhood, basically live under the constant flare of gas and whatever else might come from the refinery that is practically in their backyards.
All of PDVSA’s Venezuelan refineries seem to suffer from some type of operational deficiency. At any given time and sometimes at the same various units from different refineries are down for unplanned repairs ranging from the Amuay flexicoker, alkylation, and catalytic units; the Cardón distillation units; the three Puerto La Cruz atmospheric distillation units to the El Palito FCC unit, thus, drastically reducing domestic processing capacity and output, said Frietes. On a number of occasions in the past two years complete operations at PDVSA’s principal refineries have been halted due to operational issues.
Reduced utilization rates at the CRP have created shortages of oil derivatives including unfinished oils, lubricants, finished motor gasoline and special naphthas. As a result, Venezuela is importing more derivatives such as products for gasoline as well as light oils from the U.S. and even far off countries such as Russia and Algeria to mix with its heavy and extra-heavy crude oils produced in the Faja, even as it continues to offer oil to regional neighbors ranging from Cuba to Nicaragua under attractive financing terms.
Despite the need to import oil and products, Venezuelan oil exports continued to member countries belonging to regional initiatives ranging from the Cuba-Venezuela Cooperation Agreement (CIC) to PetroCaribe but declined 6.6 percent to 185,000 barrels per day in 2015 compared to 198,000 barrels per day in 2014, according to PDVSA data. The volumes in 2015 were down 27.3 percent compared to 255,000 barrels per day supplied to member countries in 2009.
“PDVSA continues to give away oil while in Venezuela inventories of gasoline, gasoil, diesel, LPG and lubricants are insufficient to cover domestic demand,” said Freites, a stern critic of PDVSA.
Operating deficiencies in Venezuela have created export opportunities for refiners along the North American Gulf Coast. U.S. net imports of oil and refined products from Venezuela ranging from distillate fuel oil to MTBE (oxygenate) averaged 751,000 barrels a day in the 12-month period ended June 2016 compared to 711,000 barrels a day in the same year-ago period, according to data posted to the U.S.-based Energy Information Administration’s website. However, U.S. net imports of the same products from Venezuela averaged 1,590,000 barrels-a-day in the 12-month period ended June 2001 in the early years of the Chávez government.
Productivity at the CRP is down due to the increase in workers and the decline in output, said a former PDVSA refinery safety manager who worked for 29-years at the company. He didn’t want to reveal his name since he still does contract work for PDVSA in Punto Fijo and feared retaliation from the company. Oil workers must be oil workers and not politically divided like today as it is affecting the productivity of the employees and the company, he said during an interview at a small building in downtown Punto Fijo which serves as the local office of the FUTPV.
“It is still politically hard to justify massive Imports. But the economics are very clear. In the long run, if you can sustain international market prices in the domestic market you may be able to open the downstream to private investment,” said Monaldi.
Grade school kids and university students blend into the scenery of an oil town gone bust. Many will never reach PDVSA’s professional ranks unless they have connections within the company and/or support the socialist ideas, or at least those expressed by Maduro and his government. More than anything, PDVSA refinery workers in faded red work overalls dominate the landscape in Punto Fijo and the surrounding towns seemingly unaffected by hot weather, strong wind gusts and refineries constantly emitting gas and other substances into the air. What has affected them is the continued economic crisis and low wages, many say here.
Under the sweltering sun, improvisations are the order of the day at the CRP for many refining workers frequently forced to scramble to solve recurring small problems turned into major ones due to the lack of basic replacement parts. The practice of using emergency stapling techniques to fix routine vapor leaks at processing units, or product leaks along pipelines, is commonplace nowadays, says Freites, who is the spokesperson for many refining and oil union workers not willing to go on record due to fear of retaliation or work dismissal from PDVSA.
Similar scenes are said to resonate at the Puerto La Cruz and El Palito refineries, said José Bodas, another oil union official, in a telephone interview from Carabobo state.
PDVSA is using stapling methods to fix pipeline and unit leaks instead of properly fixing or repairing them due to a lack of funds to procure the necessary replacement parts, said the former PDVSA safety manager. PDVSA is more reactive than preventative and is conducting more corrective maintenance than preventative maintenance due to the lack of financial resources. It’s not necessarily a money thing but just the way PDVSA works today, he said.
Lackluster security measures to protect the PDVSA refineries and workers have allowed crime incidents to edge up within the complexes’ gates. Stolen work bags and purses, missing clothing and other personal items and car break-ins are daily work hazards beyond those related to working in a domestic refining sector where accidents, sadly enough, are more the norm than in many other countries with refining operations. In the country with the highest murder rate in the world, according to the website WorldAtlas.com, not even the confines of the refinery complex are safe enough to shield workers from the realities on the streets in Punto Fijo, Ciudad Ojeda, Anaco and other major oil and gas towns across Venezuela.
Safety is no longer a priority for PDVSA as funds are being spent haphazardly on non-necessary projects, said the former PDVSA safety manager with his salt-and-pepper mustache and Italian surname. He says many current PDVSA bosses only respond to accidents when they are officially reported by the media.
On its part, PDVSA claims there were just 154 total injuries at the CRP, El Palito and Puerto La Cruz refineries in 2015. This compares to 173 in 2014, 276 in 2012, and 298 in 2010, according to PDVSA data in its social and environmental statements on its website. Still, union officials here say the numbers don’t reflect the real case scenario since a lot of accidents and injuries go undocumented.
As the sun falls over the horizon, workers use their mobile phones in some areas of the CRP seemly unaware of the work hazards. Thieves that regularly enter the complex via the various gate openings to rob copper, bronze, nickel as well as other materials and equipment, also rob workers of their mobile phones whenever possible. The resale market for mobile phone parts is big in Venezuela amid an economic crisis that has impacted not just food importers, but the telecommunications and airline industries as well, among others.
The multiplier effect on this town and surrounding communities can visibly be seen in the fishing regions of Punto Fijo from Las Piedras to Los Taques where white and blue collar oil workers in the good ole days would be seen almost everywhere eating and taking in the sun with family and coworkers or clients. That’s not the scene here anymore. Local mayors have for years promised money to fishing communities and fishermen in the region but many, like other family members, remain unemployed. Many have turned to crime to rob and steal things they can resell to get basics like food or medicines for their families.
“Whatever was taken over from the transnational companies doesn’t work here,” said Jaime Antonio Diaz, 44, during an interview at a lightless restaurant in Los Taques. “If the Fourth Republic was bad, then the Fifth Republic is the worst,” he said as a stray cat entered the premise through an entrance door kept open to let in fresh air and natural light.
Diaz’s comments refer to the two most recent republics in Venezuela. The Fourth Republic was the period in Venezuelan history marked by the Punto Fijo Pact in 1958 for the acceptance of democratic elections in that year. Nationalization of Venezuela’s oil industry was a point frequently criticized by Chávez as a one of many failures of the Fourth Republic. The Fifth Republic Movement (MVR by its Spanish acronym) was a leftist political party founded in the late 1990s by then-presidential candidate Chávez. It was later dissolved in 2007 to give way to Chávez’s new political party the United Socialist Party of Venezuela (PSUV).
From refinery workers fleeing low pay and increased worksite accidents to unemployed fishermen and engineers driving taxis, Punto Fijo is going through what many say is one of its worst periods in decades.
Within visible distance of the dirt roads of Los Taques nearly 30 or more towering wind power turbines can be seen off the immediate horizon on the return trip from Los Taques to Punto Fijo. Despite the strong winds here, the turbines are not operational and have yet to generate power for commercial or domestic usage, according to Freites, owing to corrupt deals between Venezuelan government officials and the company that supplied the towers. Venezuela – which has long suffered from a natural gas deficit in its industrialized western Zulia state – has plans to use non-associated natural gas production from the Cardón IV offshore project as well as power generated by these turbines to reduce the need to import costly diesel fuel. From the look of things here, it is quite obvious the latter is not something PDVSA officials want to openly talk or brag about. However, it’s safe to assume somebody made a killing on the turbine deal.
While the wind turbine project – like others envisioned in this small country with a population close to 31 million – looks good on paper in the boardroom, the corruption here more often than not turns the project into a financial bonus for some individuals at the costs of local jobs and wasted resources for a country teetering on the brink of financial default.
One thing continues to thrive here: the contraband of fuels. Contraband of cheap Venezuelan gasoline continues to nearby Colombia, Guyana, Trinidad and Tobago and Aruba despite efforts to deter it and a decision by this government to boost gasoline prices in February of 2016 to 6 bolivars a liter from 9.7 centavos. While demand for gasoline has declined in Venezuela due to economic crisis and a higher cost for gasoline, its elevated price is still quite low compared to nearby markets; thus, making it still very attractive for trade internationally.
Large fishing boats – refitted by the Venezuelan military and now under the control of military officers that pose as fishermen – continue to leave the pier near Las Piedras with domestic fuel. These so-called ‘gasoil mafias’ continue to exchange Venezuelan refined products on the high seas in international waters in seemingly another way the military is kept happy and loyal by Maduro and company, according to Rossi, author of the book ‘The Completion of the Oil Era: The Economic Impact (Energy Policies, Politics and Prices).’
Barefoot grade school kids with just shorts on, play baseball on the dirt roads and side streets in numerous poor communities in and around Punto Fijo. Using broomsticks and makeshift baseballs, they can be seen enjoying their game despite the extreme poverty they live in and not having gloves. Despite being a Latin American country, baseball, not soccer is the sport of choice here and seen here as the way to rise out of poverty, at least for many males. On the other side, females here dream of being Ms. Venezuela or Ms. World.
“This government only saves itself by changing the model,” said León, referring to what the Maduro government needs to do to stay in power.
Whether the model change comes tomorrow, next year or in 2019, Venezuela’s hydrocarbon sector is in need of drastic changes. However drastic and radical these changes may have to be, investors will continue to keep Venezuela on their radar screens, hoping for a chance to invest in the country with one of the largest resource bases on the planet. However, from the looks of things, with foreign diplomats and oil men continuing to get kidnapped here, Venezuela is not yet ready for the massive return of foreign companies or better yet the foreign companies aren’t ready to return under the existing circumstances.
The recently announced departure of Schlumberger, the world’s largest oilfield services company, should serve as a reminder to potential investors about the condition of the oil sector here which still contends with a massive brain drain of national and international talent from companies from Halliburton to Total, Chevron, Statoil and a host of smaller companies lacking the deep pockets to survive without quarterly or sometimes monthly cash flow.
“The low wages continue to produce brain drain and that makes worse the operational problems,” said Monaldi.
Top Venezuelan officials and PDVSA executives blame the economic and petroleum sector crisis here on an economic war waged they say by opposition leaders with the backing of persons and institutions from Bogotá, Miami, Washington and even Madrid. The open denial of internal problems created by widespread mismanagement, errored financial and economic decisions as well as a number of actions including asset expropriations have handcuffed the country’s private sector and brought the all-important petroleum sector to a near halt. That hasn’t stopped other countries from stepping in to fill the void when and where it is possible. Case in point: Algeria just started to supply oil to Cuba amid mounting issues at PDVSA.
The Amuay explosion on August 25, 2012, as regrettable as it was, was an early wake-up call about what PDVSA had (and has) become after more than a decade of so-called socialism. Amid continued corruption at PDVSA and a hydrocarbon sector where funds mysteriously disappear, the financial and economic dreams of a handful or more have smashed the hopes of many in Punto Fijo and all across this major oil producing South American country.
“A lot of people here are changing sides due to the mismanagement of resources by the Chávez and now the Maduro government,” said Ali, a 50-year old taxi driver of an old Toyota Corolla, who requested his last name not be used in this article for fear of retaliation from PDVSA or government officials.
Ali’s sentiment resonates across all parts of this country from many petroleum engineers and other professionals that have left the industry to drive a taxi, wait tables or do anything where the wages are better.
“The sad part of all this is that we could have another August 25th,” said Freites.
(Editing by Peter Wilson)
(Exxon Mobil, 18.Jun.2016) – Exxon Mobil Corporation has reached an agreement with PBF Energy Inc. for the sale and purchase of its 50 percent interest in Chalmette Refining, LLC in Chalmette, Louisiana.
PBF Energy will purchase 100 percent of Chalmette Refining, LLC, which is a joint venture between affiliates of Petróleos de Venezuela, S.A. (PDVSA) and ExxonMobil.
The agreement includes the Chalmette refinery and chemical production facilities near New Orleans, La. and the company’s 100 percent interests in MOEM Pipeline, LLC and 80 percent interest in each of Collins Pipeline Company and T&M Terminal Company. ExxonMobil operates Chalmette Refining, LLC and Mobil Pipeline Company, an ExxonMobil affiliate, operates the logistics infrastructure.
“This decision is the result of a strategic assessment of the site and how it fits with our large US Gulf Coast Refining portfolio,” said Jerry Wascom, president of ExxonMobil Refining & Supply Company.
“We regularly adjust our portfolio of assets through investment, restructuring, or divestment consistent with our overall global and regional business strategies,” said Wascom. “ExxonMobil remains committed to doing business in Louisiana through ongoing operations at the Baton Rouge refinery and chemical plants, the development and production of oil and natural gas resources, and sales of fuels and lubricants. All of these businesses are unaffected by this agreement.”
Subject to regulatory approval, change-in-control is anticipated to take place by the end of 2015. Details of the commercial agreements are proprietary.
(Energy Analytics Institute, Piero Stewart, 8.Oct.2015) – Rumors have it that Venezuela’s Finance Minister Rodolfo Marco Torres had to be corrected on a number of occasions while talking about the country’s financial situation.
(EIA, 25.Sep.2015) – The amount of unproved technically recoverable shale natural gas around the world has reached 7,576 Tcf, higher than previously estimated, according to a survey by the U.S.-based Energy Information Administration (EIA).
New names were added to the list of countries with shale reserves. The U.S. holds 622.5 Tcf of recoverable shale gas that is sufficient in meeting domestic demand for about 27 years, lower than the previously projected 37 years, the survey found.
(PBF Energy, 30.Jul.2015) – On 18.Jun.2015, PBF announced that its subsidiary signed a definitive agreement to purchase Chalmette Refining, LLC, consisting of the 189 Mb/d Chalmette Refinery and related logistics assets, from ExxonMobil and PDV Chalmette, LLC.
The purchase price for the assets is $322 mln, plus working capital including inventory to be determined at closing. The transaction is expected to close prior to YE:15, subject to customary closing conditions and regulatory approvals.
(Petrobras, 25.Jun.2015) – Petrobras announced that on 25.Jun.2015, a hearing was held before the federal court in New York regarding the motion to dismiss presented by Petrobras in the class action lawsuit in which the company is a defendant. The purpose of the motion to dismiss is for the federal court to determine if, from a legal point of view, the allegations are sufficient to proceed to the evidentiary stage of the case (discovery).
After hearing the oral arguments, the judge informed that he will enter his decision on the motion to dismiss in due course.
(Moody’s, 22.Jun.2015) – Moody’s Investors Service changed PBF Holding Company LLC’s rating outlook to positive from stable. Moody’s also affirmed PBF’s Ba3 Corporate Family Rating (CFR), Ba3-PD Probability of Default Rating, and Ba3 senior secured notes ratings following its announced acquisition of the Chalmette refinery.
“PBF’s positive rating outlook reflects the expected increase in refining scale and geographic diversification, and the potential for better crude sourcing and product distribution ability if the Chalmette refinery acquisition closes as anticipated in 2015,” said Arvinder Saluja, Moody’s VP. “This acquisition builds on PBF’s four year track record of operating its existing three refineries.”
On 19.Jun.2015, PBF’s parent, PBF Energy Inc., announced that it has signed an agreement to purchase the Chalmette refinery with 189,000 b/d throughput capacity from subsidiaries of ExxonMobil (Aaa stable) and Petroleos de Venezuela, S.A. (Caa3 stable). The $322 million purchase price plus an estimated $300 million – $500 million of working capital will be funded using a combination of cash and debt. The transaction is subject to customary closing conditions and regulatory approvals, and is expected to close in the 4Q:15.
(Harvest Natural Resources, Inc., 19.Jun.2015) – On 19.Jun.2015, Harvest Natural Resources, Inc. entered into a strategic relationship with CT Energy and CT Energia Holding, Ltd., an international energy trading firm, designed to maximize the long-term success and value of Harvest’s Venezuelan operations and its 20.4% investment in Petrodelta.
Under the terms of this strategic relationship, the company entered into a term sheet with PDVSA for the repositioning and growth of Petrodelta’s business. The company agreed to appoint two of CT Energy’s designees as the company’s representatives on the Petrodelta board of directors.
CT Energia has entered into a management contract with the Company to oversee Harvest’s Venezuelan day-to-day operations and to assist in the development of a plan for the business operations and financing for Petrodelta and the negotiation of definitive documents to implement such plan.
Terms of the transaction with CT Energy include:
— The company sold CT Energy a $25.2 mln, 5year, 15% non-convertible senior secured promissory note (“15% Note”) and a $7 mln, 5-year, 9% convertible senior secured note (“9% Note”). The 9% Note is immediately convertible into 8,506,097 shares of Harvest common stock at an initial conversion price of $0.82. Harvest also issued to CT Energy 69.75 shares of a newly-created series of preferred stock that carry voting rights equivalent to the shares of common stock underlying the unconverted portion of the 9% Note.
— Harvest issued CT Energy a warrant to purchase up to 34,070,820 shares of Harvest’s common stock at an initial exercise price of $1.25/share (“CT warrant”). The CT warrant will become exercisable only after the 30-day volume weighted average price of Harvest’s common stock equals or exceeds $2.50/share (“Stock Appreciation Date”) and Harvest’s stockholders approve certain proposals related to the transaction with CT Energy by a majority of votes cast, as required by the New York Stock Exchange (NYSE) shareholder approval rules. The CT warrant is cash-exercisable, but CT Energy may surrender the 15% Note to pay for a portion of the aggregate exercise price.
— The company sold CT Energy a five-year 15% non-convertible senior secured note (“additional draw note”), under which CT Energy may elect to provide $2 mln of additional funds to the company per month for up to 6-months following the 1-year anniversary of the closing date of the transaction (up to $12 mln in aggregate). If funds are loaned under the additional draw note, interest will be compounded quarterly at a rate of 15% per annum and will be payable quarterly on the first business day of each Jan., Apr., Jul. and Oct., commencing 1.Oct.2016. If by 19.Jun.2016 (“Claim Date”), the volume weighted average price of the company’s common stock over any consecutive 30-day period has not equaled or exceeded $2.50/share, the maturity date of the additional draw note will be extended by two years and the interest rates on the additional draw note will adjust to 8%. During an event of default, the outstanding principal amount will bear additional interest at a rate of 2% per annum higher than the rate otherwise applicable.
— Harvest issued to CT Energy 69.75 shares of the company’s newly created Series C preferred stock, par value $0.01/share. The primary purpose of the Series C preferred stock is to provide the holder of the 9% Note with voting rights equivalent to the common stock underlying the unconverted portion of the 9% Note. Shares of the Series C preferred stock are entitled to vote on certain matters submitted to a vote of the stockholders on an “as converted” basis.
— At our upcoming annual shareholder meeting on 9.Sep.2015, Harvest stockholders will be asked to approve certain proposals related to the transaction under NYSE shareholder approval requirements and to approve an amendment to Harvest’s charter to authorize new shares of common stock in an amount sufficient for future needs, including the full conversion of the 9% Note and full exercise of the CT warrant issued in the transaction.
— If stockholder approval is not obtained, CT Energy has the right to accelerate full repayment of the 9% and 15% notes upon 60-days’ notice. Upon acceleration of the notes, Harvest would be required to seek alternative financing for liquidity and the strategic relationship with CT Energia would be terminated.
— CT Energy appointed three members to the company’s board of directors, including one appointee serving as an independent director under the NYSE and Securities and Exchange Commission (SEC) rules.
(Exxon Mobil Corporation, 18.Jun.2015) – ExxonMobil reached an agreement with PBF Energy Inc. for the sale and purchase of its 50% interest in Chalmette Refining, LLC in Chalmette, Louisiana.
“This decision is the result of a strategic assessment of the site and how it fits with our large US Gulf Coast Refining portfolio,” said Jerry Wascom, president of ExxonMobil Refining & Supply Company.
PBF will purchase 100% of Chalmette Refining, LLC, which is a JV between affiliates of Petróleos de Venezuela, S.A. (PDVSA) and ExxonMobil.
The agreement includes the Chalmette refinery and chemical production facilities near New Orleans, Louisiana and the company’s 100% interests in MOEM Pipeline, LLC and 80% interest in each of Collins Pipeline Company and T&M Terminal Company. ExxonMobil operates Chalmette Refining, LLC and Mobil Pipeline Company, an ExxonMobil affiliate, operates the logistics infrastructure.
We regularly adjust our portfolio of assets through investment, restructuring, or divestment consistent with our overall global and regional business strategies, said Wascom.
“ExxonMobil remains committed to doing business in Louisiana through ongoing operations at the Baton Rouge refinery and chemical plants, the development and production of oil and natural gas resources, and sales of fuels and lubricants. All of these businesses are unaffected by this agreement,” said Wascom.
Subject to regulatory approval, change-in-control is anticipated to take place by YE:15. Details of the commercial agreements are proprietary.
(Moody’s, 7.Apr.2015) – LNG suppliers are curtailing their capital budgets, amid low oil prices and a coming glut of new LNG supply from Australia and the U.S.A., Moody’s Investors Service said in its report, “Lower Oil Prices Cause Suppliers of Liquefied Natural Gas to Nix Projects.”
Moody’s says low LNG prices will result in the cancellation of the vast majority of the nearly 30 liquefaction projects currently proposed in the U.S.A., 18 in western Canada, and 4 in eastern Canada.
(Energy Analytics Institute, Jared Yamin, 13.Mar.2015) – The United States is not contemplating applying any measures against Venezuela’s petroleum sector, according to the daily newspaper El Universal, citing an U.S. official who requested anonymity.
“The sanctions against the military officials does not have an impact on the Venezuelan economy nor the petroleum sector. With respect to energy, it’s the U.S. energy companies that buy the oil and they are the ones that will decide whether or not to buy it,” said the U.S. official.
(Petrobras, 6.Mar.2015) – Petrobras announces that on March 4, 2015, the presiding judge appointed Universities Superannuation Scheme, Ltd. as the lead plaintiff in the Class Action filed against Petrobras in the New York federal court.
A conference call between the presiding judge, Petrobras and the lead plaintiff will take place on March 6, 2015, in order to plan the next steps in the proceeding.
As the company stated on February 13th, 2015, it has hired a specialized U.S. law firm and will defend itself against the allegations in this lawsuit.
(Harvest Natural Resources, Inc., 18.Feb.2015) – Harvest Natural Resources, Inc. announced that on February 13, 2015, the company received notification from the New York Stock Exchange (NYSE) that it had fallen below the NYSE’s continued listing standard, which requires a minimum average closing price of $1 per share over 30 consecutive trading days.
Under the NYSE’s rules, Harvest has a period of six months from the date of the NYSE notice to bring its share price and 30 trading-day average share price back above $1. During this period, Harvest’s common stock will continue to be traded on the NYSE, subject to the company’s compliance with other NYSE continued listing requirements. As required by the NYSE, in order to maintain its listing, Harvest will notify the NYSE that it intends to cure the price deficiency.
The company’s business operations, securities reporting requirements and debt obligations are unaffected by this notification.
(Energy Analytics Institute, Pietro D. Pitts, 18.Sep.2013) – Tudor Pickering Holt & Co. LLC Managing Director David Pursell spoke with Energy Analytics Institute in a brief interview from Dallas, Texas.
What follows are excerpts from the brief interview.
EAI: Are PDVSA’s CITGO assets along the US Gulf Coast strategic?
Pursell: They are strategic because they’re high complexity refineries that can handle the heavy Venezuelan crude grade. Plus, the products they make are going into the U.S., which is the most important refined product market in the world.
EAI: Could PDVSA’s CITGO assets be used as compensation if PDVSA were ordered to pay large lawsuit damages?
Pursell: You could probably take those assets in lieu of payment if ultimately there is a large damage award and the Venezuelans say they’re not going to pay you. The question is who’s going to buy those? If you buy cheap from Venezuela and a court later says we’re going to take them from you. Does this scare away a buyer?
EAI: Will Canadian crudes compete with Venezuelan crudes if the Keystone Pipeline is eventually built?
Pursell: Canadian crude will definitely compete with Venezuelan crude, as both are going to U.S. Gulf Coast.
EAI: How do you view PDVSA today?
Pursell: Venezuela before Chavez had three operating companies that were very good, they were clearly top quartile, Chavez came in, meshed them together and gutted technical expertise for political reasons and now PDVSA is a terrible company. He basically took PDVSA and made it Pemex, inept and not very good.
Pursell holds a Masters in Petroleum Engineering. He has worked on a number of technical petroleum engineering consulting projects in Venezuela.
(Energy Analytics Institute, Pietro D. Pitts, 9.Aug.2013) – Oil Outlook President Carl Larry spoke with Energy Analytics Institute in a brief interview from Houston, Texas.
What follows are excerpts from the brief interview.
EAI: Are US refiners benefiting from PDVSA’s refinery problems in Venezuela?
Larry: We have seen production in the US in the last year picking up and we are seeing a lot of refinery runs, which have lifted exports which are at a record high.
Because of gasoline usage that we have seen in Venezuela, it has created an opportunity for US Gulf Coast refineries to pick up the slack to really push out more exports.
Additionally, we see a lot of the US Gulf Coast refineries bringing in a lot of heavy and medium crudes from either Venezuela or Saudi Arabia. The focus has shifted from bringing in lighter sweets, which we have done historically, to bringing in more medium to heavy grades (heavier sour grades). Further, we are seeing more being pulled out of Cushing and down into now the Gulf Coast.
There is an abundance of light sweet because of the shale programs, whether Eagle Ford in Texas or Bakken, and we are seeing a lot of that get pushed to the East Coast and the Mid-West.
We have seen a desperate need for sours and heavies ever since 2004-2005 when the refineries in the Gulf Coast were switching their slates to a heavier grade because of the cost differences.
Now we are experiencing a situation where it is cheaper to bring in light sweet in but the refineries are now geared up to bring in medium to heavy. We are seeing a lot more production but because of that we are seeing more pressure on the heavier sour grades.
Exports are key here. The longer we can keep those refineries up and running, it’s a good thing for the US refining system but at end of the day it is all about global demand and not so much US demand.
EAI: Could PDVSA be at a point whereby it is ready to divest of its CITGO Corp. refining operations in the US?
Larry: Venezuela is facing the same issues as a refiner as Saudi Arabia. There is not this demand in the US for product anymore and definitely not crude, so like Saudi Arabia there is race to get to Asia and especially China and get in front of them and sign longer term deals. So, the longer Venezuela deals with the US and the up and down demand here, the more time they are losing with bigger customers.
I can see why they would want to strengthen those ties before someone else stepped in. I could see PDVSA wanting to exit the US since there is not
really a big need here anymore for refineries or crude for that matter.
The focus for PDVSA and Venezuela should be the up and coming countries that will be demanding more oil, probably China and maybe Japan as well.
EAI: What companies would you put on a short list as being interested in the CITGO refineries?
Larry: I think ExxonMobil is a name that will come to the forefront, but Chevron Corp. might be another one that might be looking to expand. With significant exposure in Latin America, the refineries could be a natural fit for Chevron if there is an opportunity to expand.
EAI: Do you see a market for PDVSA’s Caribbean refineries?
Larry: It all depends on global demand. The Caribbean refineries are looking for a lot more global demand to make their margins profitable. The US is no longer relying on the Caribbean to give it the product, the demand is now going in the opposite direction. So, PDVSA’s refineries and others in the Caribbean become more global macro-sensitive than they have been in the past.
PDVSA’s 100% controlled US subsidiary CITGO Corp. owns outright three refineries with combined processing capacity of 749,000 b/d. PDVSA also has a 50% interest in two additional refineries with a combined processing capacity of 679,000 b/d, according to PDVSA’s 2012 annual report.
(Energy Analytics Institute, Piero Stewart, 17.Jun.2013) – The Public Affairs Manager with Houston-based Citgo Petroleum, Fernando Garay, comments via phone regarding declining imports of Venezuelan crude oil in the U.S.
“We are not worried about the prospect of declining oil supplies from our Caracas-based parent company PDVSA and have no problem looking to other markets for supply.”
(Energy Analytics Institute, Pietro D. Pitts, 19.Jul.2013) – Brookshire Advisory and Research President Gianna Bern spoke with Energy Analytics Institute in a brief interview from Chicago, IL.
What follows are excerpts from the brief interview.
EAI: Do you think PDVSA will move to increase rates on Petrocaribe member countries that are not exporting products that are needed in Venezuela?
Bern: I think PDVSA will manage its export-import agreements very carefully. As such, I am not surprised by the rate increases associated with various export-import partners, and I think there will be rate increases where there is a path of least resistance.
Venezuela’s electricity sector has been in need of infrastructure improvements for the past decade and so now we see increased diesel fuel supplies being dedicated to generate electricity instead of transport. Consequently, Venezuela has been increasing its imports of reformulated gasoline from the USA and at a time when the USA’s production of oil has been increasing.
However, not all countries had the same faith. Officials from Honduras and Guatemala emerged from the July 2013 Petrocaribe conference in Managua as the first countries to openly express concern over potential rate increases, although it is unclear whether they will abandon the initiative.
EAI: Why would PDVSA increase interest rates on Petrocaribe loans?
Bern: My suspicion is that it is cash flow driven. PDVSA is still taking steps to increase its cash flow, so this is probably just one initiative we are seeing by the company to improve its very challenging financial situation.
EAI: Could these interest rate increases be a game breaker for the members?
Bern: At first glance an interest rate increase may be substantial but each country will have to make a decision based on their economic interest and whether they want to continue moving down the path with PDVSA. However, I do not think the solution is one of longevity.