OIL & GAS UPDATE
TABLE OF CONTENTS
Crude oil output growth from deepwater areas may stagnate because current oil prices make it unprofitable to tap new deposits and large discoveries dwindle, a consultant said.
“The pace of growth will slow and then become flat for the next few years,” Michael Rodgers, a partner at PFC Energy, said in an interview at the Offshore Vessels conference in Singapore April 27. “There were not a whole lot of large commercial discoveries in the last couple of years.”
Production from deepwater blocks grew 67 percent a year between 2005 and 2008 following discoveries off Angola and Nigeria. That beat a growth of 1.3 percent in total crude oil output during the same period.
Global deepwater oil production may peak at 7.5 million barrels a day in 2013, Rodgers said.
Oilfield service providers including Schlumberger Ltd. and Transocean Ltd. and rig builders in South Korea and Singapore are counting on deepwater projects to drive earnings growth. Demand for deepwater drilling equipment, led by Brazil and India, continues to grow at a slower pace amid the global recession and lower crude oil prices, said Transocean, the world’s largest offshore oil driller, on April 22.
“Falling investment in commercial deepwater development will require fewer deepwater platforms in the next five years compared to the last five years,” Rodgers said. Production of oil from the deep seas accounted for 8 percent of global crude produced last year.
Output in deepwater areas, or those at water depths of more than 1,000 feet (305 meters), soared in the past five years as companies discovered large deposits in Angola, Nigeria and the Gulf of Mexico, Rodgers said.
The majority of deepwater areas have reached “maturity” and current projects are facing delays, he said.
Oil and gas explorers are postponing or scrapping deepwater projects, potentially reducing crude supplies by as much as 2.4 million barrels a day in 2011, Morgan Stanley said in a report in March. Oil prices in New York have declined more than 66 percent from a record $147.27 a barrel in July last year.
Out of a sample of 46 deepwater projects in places including Brazil, Africa, Norway, Asia and the Gulf of Mexico, about 27 may have an internal rate of return of less than 15 percent, the minimum required for international oil companies to invest in deepwater developments, according to Rodgers.
Oil must reach $50 a barrel for some developments to achieve more than 15 percent in returns, he said.
No new contracts have been awarded since August 2008 when Morgan Stanley estimated that companies needed 139 new production platforms to develop fields in deep seas. Since then, 11 orders have been canceled and 46 delayed by an average 15 months, according to last month’s Morgan Stanley report.
Worldwide spending on oil and gas exploration may drop 12 percent in 2009 to $400 billion, according to a report in December by Barclays Capital Research.
The Obama administration wants to reduce oil consumption, increase renewable energy supplies and cut carbon dioxide emissions in the most ambitious transformation of energy policy in a generation.
But the world’s oil giants don’t seem convinced that it will work. Even as Washington goes into a furor over energy, many of the oil companies are balking at investing in new technologies favored by the president, or even straying from commitments they had already made.
Royal Dutch Shell said last month that it would freeze its research and investments in wind, solar and hydrogen power, and focus its alternative energy efforts on biofuels. The company had already sold much of its solar business and pulled out of a project last year to build the largest offshore wind farm, near London.
BP, a company that has spent nine years saying it was moving “beyond petroleum,” has been getting back to petroleum since 2007, cutting back its renewables program. And American oil companies, which all along have been more skeptical of alternative energy than their European counterparts, are studiously ignoring the new messages coming from Washington.
“In my view, nothing has really changed,” Rex W. Tillerson, the chief executive of Exxon Mobil, said after the election of President Obama.
“We don’t oppose alternative energy sources and the development of those. But to hang the future of the country’s energy on those alternatives alone belies reality of their size and scale.”
The administration wants to spend $150 billion over the next decade to create what it calls “a clean energy future.” Its plan would aim to diversify the nation’s energy sources by encouraging more renewables, and it would reduce oil consumption and cut carbon emissions from fossil fuels.
The oil companies have frequently run advertisements expressing their interest in new forms of energy, but their actual investments have belied the marketing claims. The great bulk of their investments goes to traditional petroleum resources, including carbon-intensive energy sources like tar sands and natural gas from shale, while alternative investments account for a tiny fraction of their spending. So far, that has changed little under the Obama administration.
“The scale of their alternative investments is so mind-numbingly small that it’s hard to find them,” said Nathanael Greene, a senior policy analyst at the Natural Resources Defense Council. “These companies don’t feel they have to be on the leading edge of this stuff.”
Perhaps not surprisingly, most investments in alternative sources of energy are coming from pockets other than those of the oil companies.
In the last 15 years, the top five oil companies have spent around $5 billion to develop sources of renewable energy, according to Michael Eckhart, president of the American Council on Renewable Energy, an industry trade group. This represents only 10 percent of the roughly $50 billion funneled into the clean-energy sector by venture capital funds and corporate investors during that period, he said.
“Big Oil does not consider renewable energy to be a mainstream business,” Mr. Eckhart said. “It’s a side business for them.”
Shell, for example, said it spent $1.7 billion since 2004 on alternative projects. That amount is dwarfed by the $87 billion it spent over the same period on its oil and gas projects around the world. This year, the company’s overall capital spending is set at $31 billion, most of it for the development of fossil fuels.
Industry executives contend that comparing investments in oil and gas projects with their research efforts in the renewable field is misleading. They say that while renewable fuels are needed, they are still at an early stage of development, and petroleum will remain the dominant source of energy for decades.
In its long-term forecast, Exxon says that by 2050, hydrocarbons — including oil, gas, and coal — will account for 80 percent of the world’s energy supplies, about the same as today.
“Renewable energy is very real,” David J. O’Reilly, the chief executive of Chevron, said in a speech in New York last November. “We need it. It will be an essential part of the future I envision. But it’s not realistic to suppose we can replace conventional energy in a timeframe that some suggest.”
Chevron has spent about $3.2 billion since 2002 on “renewable and alternative energy and energy efficiency services,” according to Alexander Yelland, a spokesman. It plans to spend $2.7 billion in the three years through 2011 on a variety of projects, including a business that helps improve energy efficiency for companies and government agencies, he said.
Despite Washington’s newfound green enthusiasm, industry executives argue that replacing any significant part of the fossil fuel business will take decades, at best. Just to keep up with growth in demand for conventional sources of energy, producers will need to invest more than $1 trillion each year from now to 2030, according to the International Energy Agency.
“Many of these companies see the world is changing,” said Daniel Yergin, the chairman of Cambridge Energy Research Associates and a historian of the industry. “But the challenge for a very large company is to get critical scale. People tend to forget the scale of the energy business.”
The world consumes about 85 million barrels of oil a day. The United States alone would require six times its arable land — and 75 percent of the world’s cultivated land — to supply its needs with ethanol made from corn, according to calculations by Vaclav Smil, an energy expert at the University of Manitoba.
More realistic, and modest, targets are proving tough to reach. Congress’s ethanol mandate, which requires oil companies to use 36 billion gallons of ethanol by 2020, cannot be achieved, experts say, without major technological advances that are still years away.
To increase supplies, most companies are looking to tar sands in Canada or converting coal or natural gas into liquid fuels, technologies that emit far more carbon dioxide than conventional oil does.
Shell, a major investor in Alberta in Canada, says that traditional oil supplies will not be enough to meet the growth in the world’s energy needs over the next half-century. In 2007, BP invested in Canadian tar sands, prompting criticism that it was “recarbonizing” itself.
John M. Deutch, a professor at the Massachusetts Institute of Technology and a former director of central intelligence, said there was little point in criticizing oil companies without first establishing federal rules that set a price on carbon dioxide emissions. Once that happens, he said, companies will adapt their strategies.
“What role will oil companies play in the future in alternatives to conventional hydrocarbon? The correct answer is nobody knows,” Mr. Deutch said. “The important thing is for the government to establish a carbon policy. You can be absolutely confident that oil companies will pursue that, as will any other companies.”
One area where companies are increasingly focused is the development of liquid fuels from plants. BP said it would soon build a demonstration plant in Florida for a type of ethanol made from plant material; Shell has worked with several firms since 2002 to develop ethanol from nonfood crops. Last year, it signed agreements with six companies, including one in Brazil, and decided to drop its other renewable efforts to focus solely on biofuels.
“Biofuels feels closest to our core business,” said Darci Sinclair, a company spokeswoman.
Other areas also hold significant promise for the industry, like technologies to capture carbon dioxide emissions and store them underground, and energy-efficiency programs, especially in the transportation sector. Exxon, long the most skeptical of the oil companies toward alternative energy investments, is working on long-term programs to improve fuel economy and reduce emissions.
In the end, many analysts say they believe that oil companies are waiting for a winning technology to emerge. Alan Shaw, the chief executive of Codexis, a biotechnology company in Silicon Valley that works with Shell, said oil companies were not blind to the new political reality but they were also in the business of making a profit.
“Don’t lose heart with Big Oil,” Mr. Shaw said. “They aren’t at a point where they are ready to invest yet, but they are getting there. I think in the next 10 years, they will invest hundreds of times more than they have in the past 10 years.”
If the world wants to limit global warming to 2°C by 2050, it will have to leave three quarters of its proved reserves of oil, gas and coal in the ground, according to two climatology studies.
In a paper published recently in the British scientific journal Nature, scientists from the Potsdam Institute of Climate Impact Research established a limit of one trillion tonnes for carbon dioxide emissions during the first half of this century if severe impacts from global warming were to be avoided.
As a third of that amount has been emitted in the past nine years; that, would mean cutting greenhouse gas emissions by more than 50 per cent from 1990 levels by mid-century, and leaving most fossil fuel reserves untouched.
“The study has, for the first time, calculated how much greenhouse gas emissions we can pump into the atmosphere between now and 2050 to have a reasonable chance of keeping warming lower than 2°C,” the institute said in a statement.
“If we continue burning fossil fuels as we do, we will have exhausted the carbon budget in merely 20 years,” said Malte Meinshausen, the study’s lead researcher. “Only a fast switch away from fossil fuels will give us a reasonable chance to avoid considerable warming.”
Myles Allen, the lead author of a companion study by Oxford University researchers, said substantial reduction in carbon emissions would have to begin before 2020, and emissions would eventually need to be phased out entirely.“To avoid dangerous climate change, we will have to limit the total amount of carbon we inject into the atmosphere, not just the emission rate in any given year,” he said.
Bill Hare, a co-author of the Potsdam study, which used sophisticated computer modeling to reach its conclusions, said: “To keep warming below 2°C, we cannot burn and emit the carbon dioxide from more than a quarter of the economically recoverable fossil fuels up to 2050, and in the end only a small fraction of all known fossil fuel reserves.”
The scientists’ warnings – reminiscent of the observation of the former Saudi oil minister, Sheikh Ahmed Yamani, that the Stone Age did not end for lack of stone – have direct relevance to top-level international negotiations on carbon emissions taking place under the UN Framework Convention on Climate Change (UNFCCC), in the hope of concluding a new treaty on emission cuts beyond 2012 at a conference in Copenhagen this December.
The Potsdam and Oxford studies drew on research reported in “numerous assessments” by the Intergovernmental Panel on Climate Change, according to the statement.
The panel, and more than 100 of the countries that signed the UNFCCC, had endorsed the 2°C warming limit, the Potsdam Institute added.
But the path to a new accord on emissions, to replace the Kyoto agreement expiring in 2012, is anything but straight.
On April 30 Todd Stern, the US chief climate change negotiator, said international talks on battling global warming would be “extremely difficult”.
Hurdles include how much emissions should be cut by 2020, and how much emerging economic powers such as China and India should contribute to reductions.
Developing countries “want to see very significant action from developed countries”, Mr Stern said at the conclusion of a two-day meeting in Washington called by Barack Obama, to lay the foundation for the Copenhagen summit.
Mr Obama has re-engaged the U.S. in climate-change negotiations after his predecessor, George W Bush, declined to sign the Kyoto agreement over concerns that a mandatory cap on carbon emissions would harm the U.S. economy.
Since taking office in January, Mr Obama has championed efforts to enact legislation, now before the U.S. Congress, calling for the country’s first government-mandated limits on carbon emissions. His budget proposal calls for a 14 per cent reduction from 2005 levels by 2020.
Possible mechanisms for achieving the cuts include energy efficiency measures, switching to nuclear power and renewable energy for power generation, and the widespread adoption of carbon capture and storage technology at coal-fired power plants and other industrial sites. In combination with such measures, many more vehicles would need to run on power produced from carbon-free sources, instead of petrol.
Most of the required initiatives would be costly to introduced, a major stumbling block as the world struggles to recover from its worst recession in decades. Some, such as proposals to build more atomic power plants, continue to face stiff opposition in the U.S. and Europe from environmental groups.
But China is forging ahead with plans to build dozens of nuclear stations, which could reduce the country’s dependence on coal-fired generation.
On April 29, it signed a deal with Kazakhstan to purchase 24,200 tonnes of uranium, used to fuel atomic plants, from its Central Asian neighbor until 2020. The agreement also called for a joint venture between the two countries to build nuclear plants in China.
The economic downturn has had a pronounced impact on demand and the price of oil. Despite this, massive investments are still needed to ensure the industry has enough production capacity to meet future demand. Automation expenditures by the upstream oil and gas sector, which includes exploration, production, and pipelines, are expected to grow at a compounded annual growth rate (CAGR) of nine percent over the next five years. The market was $6.9 billion in 2007 and is forecasted to grow to $10.4 billion by 2012, according to a new ARC Advisory Group study.
The current economic climate offers many challenges, including plummeting demand, a collapse in once lofty oil prices, and a very uncertain outlook. Though oil and gas companies have made some adjustments in response to the downturn, they still plan to make major investments in coming years to build capacity for an inevitable increase in demand over the long term. “With the global economic downturn as a backdrop, it would be understandable if oil companies were to dial back their capital investments as a response to reduced demand and falling oil prices. However, many of the major oil companies are maintaining their capital spending plans into 2009 and beyond,” according to Analyst Allen Avery, the principal author of ARC’s “Automation Expenditures for Upstream Oil & Gas Industry Worldwide Outlook”.
Increase in demand over the long term will continue to drive significant growth in capital investments and automation expenditures in the global oil & gas industry. With access to only a minority percentage of proven reserves, integrated oil companies must attempt to replace their reserves in remote areas that are much less hospitable and more dangerous — both environmentally and politically. This is driving huge expenditures in large, complex, and difficult capital projects in the production segment.
According to estimates, demand for petroleum products will increase substantially as the economies in developing regions improve and per capita energy consumption increases. Today’s production and processing capacities struggle to keep ahead of the demand curve and both upstream and midstream facilities will need to be expanded. New sources, such as tar sands, shale oil, and coal-to-liquid gas, will require new midstream and production facilities to be developed, increasing demand for automation systems and field devices.
Regionally, the highest growth rates will occur in Asia and Latin America. Asia’s share of sales will reach 25 percent, and while expenditures in Latin America will nearly double over the forecast period, the region will still remain a relatively small portion of the overall market. Despite the strong growth in developing regions, the Middle East, home to the world’s largest conventional oil and gas deposits, will grow at average rates. North America’s upstream business, because it relies on non-conventional projects such as the Canadian Tar Sands, will trail the market.
Fluor’s shares jumped April 2 as the engineering and construction company announced a $619 million contract to design and build a gas-fired power plant in Virginia. But an analyst said the Irving-based company's success in the gas business is a "psychological headwind."
Fluor said it has won a contract to design and build a 580-megawatt plant west of Richmond, Va., for Dominion Virginia Power, and will work with Dominion on the project.
The combustion-turbine power plant will run primarily on natural gas with ultra low-sulfur diesel fuel as a backup. The plant is expected to begin operating in late summer 2011.
Broadpoint AmTech analyst Will Gabrielski maintained a "buy" rating, but cut his price target to $50 from $58. He said many projects in 2009 will be "back-end loaded" and that investors may potentially lose interest in anything but oil and gas projects.
"We fully acknowledge that Fluor's oil and gas success has become a psychological headwind as nothing lasts forever," Gabrielski said in a note to investors. "Even so, prospects remain healthy, in general." He believes energy business will be strong, though most of the work will be in the second half of the year and in 2010. And government projects also are "making a comeback," he said.
Chesapeake Energy Corporation has elected to curtail approximately 400 million cubic feet (mmcf) per day of its gross natural gas production due to continued low wellhead prices. The reduction includes the 200 mmcf per day curtailment of natural gas production previously announced on March 2, 2009. Chesapeake has resumed 7,000 barrels per day of oil production from previously curtailed oil wells.
The company’s 400 mmcf per day curtailment represents approximately 13% of Chesapeake’s current gross operated natural gas production capacity. The wells that have been curtailed are primarily located in the Mid-Continent and Barnett Shale regions. Until natural gas prices strengthen, the company plans to limit production from most newly completed wells in the Barnett and Fayetteville shales to 2 mmcf per day and in the Marcellus and Haynesville shales to 5 and 10 mmcf per day, respectively, in addition to the approximate 400 mmcf per day curtailment.
The company is able to make this decision because of its strong financial condition and extensive natural gas hedging positions. In addition, because of the steeply declining production profile of new natural gas wells and the upward trending slope of the NYMEX natural gas futures curve, Chesapeake believes deferring production and revenue to future periods with higher natural gas prices creates greater shareholder value than selling production into the current unusually low priced natural gas market.
Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “As a result of recession-related reduced demand and abundant U.S. production, natural gas prices have remained soft in recent months. However, we believe substantially lower drilling activity and natural reservoir depletion will work to rebalance U.S. natural gas markets by late 2009 or in early 2010. This recovery is already partially reflected in the NYMEX natural gas forward strip, but we believe it will become much more pronounced in the months to come as U.S. natural gas production declines begin to accelerate and the economy begins to recover. Our analysis indicates that the incremental returns for deferring revenue to future periods are very attractive and may in fact become exceptional once demand recovers and the NYMEX curve increases.
“We believe that Chesapeake’s strong financial condition and extensive hedges provide us with the operational and financial flexibility to make prudent natural gas revenue maximization choices. We will continue to work to protect and enhance shareholder value, particularly in the current challenging economic environment. Additionally, Chesapeake and other producers remain well positioned to readily meet increased market demand for natural gas as the economy recovers and as power generation and transportation markets further expand their use of natural gas in the years to come.”
Enbridge Inc. on April 13 declared the launch of a non-binding open season for the proposed LaCrosse Pipeline, an interstate pipeline to transport natural gas from Carthage, Texas, to Washington Parish in Southeastern Louisiana.
The non-binding open season was scheduled to run through May 15, 2009. The information received during this process will be used to finalize the design and final capacity for the proposed project.
The company expects the proposed pipeline to interconnect with at least five to six major interstate pipelines along this route and it could include up to as many as 12 pipeline interconnections, depending on shipper interest. The pipeline may also be extended to Florida Gas Transmission's Station 10 near Wiggins, Mississippi.
Enbridge expects the proposed project to be completed in late 2011 or early 2012.
Halliburton, the second-largest oilfield-services provider, on April 20 announced a 35 per cent fall in its Q1 profits on a decline in exploration and production spending linked to the fall in global oil prices.
In all, net income at the company dropped to $378m, or 42 cents a share, from $580m, or 63 cents, a year earlier. Consolidated revenue in the first quarter, meanwhile, was $3.9bn, down 3 per cent from the first quarter of 2008.
CEO Dave Lesar noted the problem for Halliburton in the quarter was its high exposure to North American drilling activity. He explained:
“During the first quarter, we experienced significant volume reduction and margin compression due to the steep downturn in North America drilling activity. The first quarter brought unprecedented declines in the rig count and prolonged weakness to the commodity markets. These industry-wide declines have been exacerbated by restrictions to some of our customers’ access to capital and the decrease in global demand for oil and natural gas.”
As for the outlook:
“Industry prospects will continue to be weak in the coming quarters, and visibility to the ultimate depth and length of this cycle remains uncertain. However, we believe that the long-term prospects of the industry remain sound. We will continue to manage through this downturn focusing on expanding our market position, reducing input costs, and delivering the superior execution our customers have come to expect. We will make the strategic investments to emerge even stronger when the industry recovers,” concluded Lesar.
With revenue growth at Halliburton’s outside North America’ operations coming in at 3 per cent, it’s no surprise the firm is increasingly looking to expand operations overseas. However, in the immediate future its’ unlikely Halliburton will be able to deliver anything but a performance correlated to U.S. drilling activity. The demand for oil services and drilling equipment continues to shrink with the rig count. Over the past six weeks the number of U.S. working rigs is down by 300 or 22 percent. Texas, New Mexico and Louisiana all had significant losses, especially Texas which lost 168 rigs - over half the national total.
U.S. rig counts, as compiled by Baker Hughes: U.S. rigs for 4/17/2009 were 975, Down 30 compared to 4/10/2009, Down 852 compared to 4/18/2008.
ExxonMobil Corp. is rigging up to begin drilling at the big Point Thomson gas and condensate field 60 miles east of Prudhoe Bay. The company completed the move of a drill rig and other equipment over 50 miles of ice road to the site, the company said in a press release issued April 22.
"We are moving forward with drilling and development activities at Point Thomson. Construction crews recently completed the final installation of camps and support facilities at the existing gravel pad to accept the rig. We are on schedule to begin production at Point Thomson by the end of 2014.” said Craig Haymes, ExxonMobil's Alaska production manager.
The project involves development of a gas cycling and condensate production project that will initially produce 10,000 barrels per day of liquid condensates, which will be shipped by pipeline to the Prudhoe Bay area and mixed with crude oil in the Trans-Alaska Pipeline System.
If the reservoir performs as expected, the condensate project could be scaled up, ExxonMobil officials said in past briefings. Over 250 people are employed on the project, and employment is expected to average 500 when production begins in 2014.
The company has been involved in a dispute with the state of Alaska over past work obligations but an agreement brokered earlier this year allowed ExxonMobil to proceed with the first two of five wells planned for the $1.3 billion project. Discussions are continuing on a resolution of remaining issues, Haymes said.
Equipment at the site was being assembled and drilling of the first well is expected to begin in May. Under state rules drillers cannot penetrate hydrocarbon bearing zones on new projects after April 15, so the plan is to drill the first and second wells to a depth above where hydrocarbons would be encountered this summer, and then complete the wells next winter. ExxonMobil and partners Chevron, BP and ConocoPhillips, who also own part of the Point Thomson leases, will spend $250 million this year on drilling after having spent $120 million last year in preparations for the project.
Point Thomson has an estimated 8 tcf of gas and 200 million barrels of condensates of reserves, although the field has not been developed to date. Gas reserves in the field are essential to a planned $30 billion-plus natural gas pipeline proposed for the North Slope.
Mustang, part of international energy services company John Wood Group PLC ("Wood Group"), has completed work on a 37-mile, 14-inch hydrogen pipeline for Air Products.
The pipeline, constructed between Norco and Chalmette, Louisiana, traversed Lake Pontchartrain, where it was buried under the lake-bed.
Among the project challenges was the requirement that the pipeline cross two hurricane protection levees. Both were safely crossed under the watchful care of the U.S. Army Corps of Engineers. The pipeline links to Air Products' existing hydrogen pipeline system, creating a more than 150-mile continuous pipeline network with what will be 15 hydrogen production source points. Mustang provided project management, engineering, design, right-of-way services, mapping, drafting, surveying, environmental permitting, and inspection for the project.
"The success of this pipeline project can be attributed to the team members who understood the importance of this project to Air Products," said LeRoy H. Remp, lead project engineer at Air Products. "The entire team remained focused on the need to work closely with all stakeholders including property owners and permitting agencies. Overall, the entire project execution went smoothly through all phases of the project."
Mustang President Steve Knowles commented, "We are pleased to have been an integral part of this unusual and challenging project. It was the first pipeline to cross Lake Pontchartrain since Hurricane Katrina, and by using an existing pipeline corridor, our project team was able to reduce the potential environmental impact."
Air Products serves customers in industrial, energy, technology and healthcare markets worldwide with a unique portfolio of atmospheric gases, process and specialty gases, performance materials, and equipment and services. Since 1940, Air Products has built leading positions, in key growth markets such as semiconductor materials, refinery hydrogen, home healthcare services, natural gas liquefaction, and advanced coatings and adhesives. Air Products has annual revenues of over $10 billion, operations in over 40 countries, and 21,000 employees around the globe.
A massive natural-gas discovery in northern Louisiana heralds a big shift in the nation's energy landscape. After an era of declining production, the U.S. is now swimming in natural gas.
Even conservative estimates suggest the Louisiana discovery -- known as the Haynesville Shale, for the dense rock formation that contains the gas -- could hold some 200 trillion cubic feet of natural gas. That's the equivalent of 33 billion barrels of oil, or 18 years' worth of current U.S. oil production. Some industry executives think the field could be several times that size.
"There's no dry hole here," says Joan Dunlap, vice president of Petrohawk Energy Corp.
Huge new fields also have been found in Texas, Arkansas and Pennsylvania. One industry-backed study estimates the U.S. has more than 2,200 trillion cubic feet of gas waiting to be pumped, enough to satisfy nearly 100 years of current U.S. natural-gas demand.
The discoveries have spurred energy experts and policy makers to start looking to natural gas in their pursuit of a wide range of goals: easing the impact of energy-price spikes, reducing dependence on foreign oil, lowering "greenhouse gas" emissions and speeding the transition to renewable fuels.
A climate-change bill being pushed by President Barack Obama could boost reliance on natural gas. The bill, which could emerge from the House Energy and Commerce Committee in May, is expected to set aggressive targets for reducing emissions of carbon dioxide, the most prevalent man-made greenhouse gas.
Meeting such goals would require quickly moving away from coal-fired power plants, which account for substantial carbon emissions. President Obama wants the U.S. to rely more on renewable energy such as wind and solar power, but those technologies aren't ready to shoulder more than a fraction of the nation's energy burden. Advocates for natural gas argue that the fuel, which is cleaner than coal, would be a logical quick fix. In addition, billionaire energy investor T. Boone Pickens has been touting natural gas as an alternative to gasoline and diesel for cars and trucks.
"The availability of natural-gas generation enables us to be much more courageous in charting a transition to a low-carbon economy," says Jason Grumet, executive director of the National Commission on Energy Policy, who was a senior adviser to President Obama during the campaign.
Just three years ago, the conventional wisdom was that U.S. natural-gas production was facing permanent decline. U.S. policy makers were resigned to the idea that the country would have to rely more on foreign imports to supply the fuel that heats half of American homes, generates one-fifth of the nation's electricity, and is a key component in plastics, chemicals and fertilizer.
But new technologies and a drilling boom have helped production rise 11% in the past two years. Now there's a glut, which has driven prices down to a six-year low and prompted producers to temporarily cut back drilling and search for new demand.
The natural-gas discoveries come as oil has become harder to find and more expensive to produce. The U.S. is increasingly reliant on supplies imported from the Middle East and other politically unstable regions. In contrast, 98% of the natural gas consumed in the U.S. is produced in North America.
Coal remains plentiful in the U.S., but is likely to face new restrictions. To produce the same amount of energy, burning gas emits about half as much carbon dioxide as burning coal.
Natural gas has never played more than a supporting role in the nation's energy supply. Crude oil, refined into gasoline or diesel, fuels nearly all U.S. cars or trucks. Coal is the dominant fuel for generating electricity.
Natural-gas production in the U.S. peaked in the early 1970s; then fell for a decade due to weak prices and declining gas fields in Texas, Louisiana and elsewhere. Production bounced back in the 1990s with the discovery of new fields in New Mexico and Wyoming, but by 2002, output was falling again -- this time, most experts thought, for good. Believing the U.S. would soon need to import liquefied natural gas from overseas, companies such as ConocoPhillips, El Paso Corp. and Cheniere Energy Inc. spent billions on terminals, pipelines and storage facilities.
The supply fears drove up prices, which spurred innovation. Oil-and-gas companies had known for decades that there was gas trapped in shale, a nonporous rock common in much of the U.S. but considered too dense to produce much gas.
In the 1980s, Texas oilman George Mitchell began trying to produce gas from a formation near Fort Worth, Texas, known as the Barnett Shale. He pumped millions of gallons of water at high pressure down the well, cracking open the rock and allowing gas to flow to the surface.
Oklahoma City-based Devon Energy Corp. bought Mr. Mitchell's company in 2002. It combined his methods with a technique for drilling straight down to gas-bearing rock, then turning horizontally to stay within the formation. Devon's first horizontal wells produced about three times as much gas as traditional vertical wells.
The development of the Barnett Shale almost single-handedly reversed the decline in U.S. natural-gas production. Last year, the Barnett produced four billion cubic feet of gas a day, making it the largest field in the U.S. Other companies such as Newfield Exploration Co., Southwestern Energy Co. and Range Resources Corp. found shale fields across the U.S.
One of the most aggressive companies was Oklahoma City-based Chesapeake Energy Corp., which got into the Barnett a couple of years behind cross-town rival Devon, and was an early entrant into the second big U.S. field, the Fayetteville Shale in Arkansas. In 2005, Chesapeake Chief Executive Aubrey McClendon sent teams of geologists across the country with a mission: Find the next Barnett. Less than two years later, they told him they had it, in Louisiana.
The Haynesville Shale is centered in northern Louisiana, one of the country's oldest oil- and gas-producing regions. Wildcatters had explored beneath the lush cow pastures and cotton fields as far back as the 1870s. Shreveport, the region's largest city, saw decades of booms and busts until the 1980s, when a glut of cheap oil from overseas all but killed the region's oil industry.
Oil companies knew about the Haynesville Shale, but it was considered a less viable prospect than the Barnett. The shale lies 10,000 or more feet below ground, where high pressure and 300-degree temperatures are enough to fry high-tech drilling equipment.
But in 2006, Chesapeake drilled an exploratory well and decided the results were promising enough to justify the higher cost of drilling in such harsh conditions. By late 2007, Mr. McClendon says, "we knew that we had a tiger by the tail."
In March 2008, as oil and gas prices were soaring, Chesapeake went public with its findings. The rush was on: dozens of companies dispatched agents to the area to lease land for drilling, turning farmers and ranchers into millionaires overnight.
"There was excitement in the air," recalls Jeffrey Wellborn, a Shreveport resident who sits on the board of the local Sierra Club. "You thought everyone in the world had won the lottery."
The frenzy marked the peak of a nationwide drilling boom that was fueled by a combination of soaring energy prices and easy credit. It didn't last. Between July and October, oil and gas prices fell by more than 50%, and kept falling.
The weakening economy eroded demand for both oil and gas. Natural gas, unlike oil, suffered from a supply glut. U.S. gas production rose 7.2% last year, while oil production fell 1.9%. As a result, oil prices are up 12% since the start of 2009. Natural-gas prices have fallen 41% to their lowest since 2002.
Gas producers saw their profits evaporate and share prices slump. Liquefied-natural-gas imports plunged, leaving import terminals nearly idle. Worried about a glut, companies cut back sharply on drilling and formed a lobbying group to try to boost demand.
The growing supply created opportunities for policy makers and environmentalists, who saw natural gas as a possible solution to the nation's energy problems. Some groups suggested burning more gas and less coal for power generation. Others favor its use in vehicles.
Mr. Pickens has spent millions promoting an energy plan that aims to, among other things, convert thousands of big-rig trucks to run on natural gas. Mr. Pickens has large investments in natural gas and stands to benefit if his plan is adopted. In TV ads, Internet videos and speeches, he emphasizes a different goal: reducing U.S. dependence on foreign oil.
Mr. Pickens said at a recent speech in Dallas that the U.S. is importing two-thirds of its oil even as the country is "absolutely overwhelmed with natural gas." If the reverse were true, he said, he would favor burning oil.
Some environmentalists have embraced Mr. Pickens's plan as a way to fight climate change. Carl Pope, executive director of the Sierra Club, says he sees natural gas as a "bridge fuel" that could help the U.S. burn less coal and oil until renewable sources of energy are ready to take over.
The dual message of energy security and environmental responsibility has helped Mr. Pickens win powerful allies, including Senate Majority Leader Harry Reid, House Speaker Nancy Pelosi and dozens of elected officials from both parties. A bipartisan bill providing tax incentives for natural-gas cars looks likely to pass this year.
Not everyone shares Mr. Pickens's enthusiasm for natural-gas vehicles. Major users of natural gas, such as utilities and chemicals companies, are concerned the plan would drive up prices -- an outcome that would benefit producers.
Energy Secretary Steven Chu and some other policy makers have expressed doubts about the practicality of retrofitting hundreds of thousands of service stations to offer natural gas. Some environmental groups, including the Natural Resources Defense Council, have argued that natural gas is better used to replace coal for power generation, and that cars should run on electricity generated by the sun, wind and natural gas.
Market forces are already helping natural gas make inroads against coal and oil. Gas is now cheaper than coal in many parts of the country, leading utilities to burn more gas. Of the 372 power plants expected to be built in the U.S. over the next three years, 206 will be fired by gas and just 31 by coal, according to the Energy Information Administration.
Natural gas is gaining market share far more slowly in transportation. Earlier this year, AT&T announced it would convert up to 20% of its truck fleet to run on natural gas, largely because it has been cheaper than gasoline in recent years. Cities including New York, Los Angeles and Atlanta have converted part of their bus fleets to run on natural gas, for air-quality reasons.
Shreveport could be the next city to make the switch. In March, Mayor Cedric Glover announced that the oil capital turned natural-gas boomtown would abandon diesel and convert its bus fleet to natural gas.
At a recent Louisiana Oil and Gas Association (LOGA) luncheon, President Don Briggs warned that the agenda of President Barack Obama threatens business like never before.
Obama's "dream green team": Energy Secretary Steven Chu, Interior Secretary Ken Salazar, EPA administrator Lisa Jackson and climate change advisor Carol Browner, represent "the worst nightmare for our industry," Briggs said. "When I say green, I mean they are not our friends."
It is not Obama's desire to develop renewable fuel sources that bothers Briggs so much as what he perceives as the administration's contempt for the oil industry. Obama's 2010 budget proposal would repeal various tax breaks that have long buoyed domestic fuel production and impose new fees on the industry.
The changes would be unwelcome to the industry in any year. But with a recession in full force, and commodity prices crashing in response, Briggs said the policies could crush oil and gas companies and depress production. National security is also at stake, he said, because the United States will need fossil fuel to power cars and factories until alternative energy sources are commercially viable.
"The bottom line is, we're addicted to oil," Briggs said. Oil prices have plummeted to less than $50 a barrel after reaching highs of around $147 last summer. Still, crude-oil costs are closer to prices seen in recent years. In 2007, the average cost for a barrel of crude oil was about $72, according to the Energy Information Administration. In 2006, the average barrel of crude cost about $66.
After increasing production to cash in on last year's skyrocketing prices, oil and gas companies have pulled back in recent months. Only 955 oil and gas rigs were operating in the United States in recent weeks, down from 1,842 during the same period in 2008, according to Baker Hughes Inc.
Louisiana has seen a less-dramatic decline, with 132 rigs operating in the state during the same time period, down from 152 at the same time last year. A natural gas discovery in north Louisiana called the Haynesville Shale has helped keep the state's drilling business afloat. While capping production in other parts of the country, companies are continuing to drill in the highly productive Haynesville.
Extra work from the north Louisiana shale has offset losses in oilfields and in the offshore industry, said J. Denis Taylor, a managing partner of Audubon Engineering of Metairie, which provides support services to the exploration industry.
"A year ago, we were insanely busy," said Tim Sicard, a project manager for Audubon.
Outside the Haynesville Shale, however, companies are beginning to feel the pinch.
LLOG Exploration Co. of Covington is drilling about four wells at the moment, said Mitch Ackal Jr., the company's vice president of business development. A year ago, LLOG would have been drilling eight to 10 wells.
"Everything is on hold right now," Ackal said, adding that LLOG has not had to resort to layoffs of its roughly 75 employees in Louisiana.
Overall, Louisiana has seen a slight downturn in energy-related employment. The mining and logging sector, which largely consists of drilling and drilling-support services, fell to 53,400 jobs in March, according to data from the Louisiana Workforce Commission, which counted 54,000 jobs in the sector in March 2008.
Briggs said he would not be surprised to see a further decline in the months ahead.
Shell plans to drill its first test well in the Chukchi Sea in the summer of 2010 or 2011, using the Frontier Discoverer drill ship. The company also plans to drill a second well in the Beaufort Sea with the same vessel later in the summer, according to Pete Slaiby, general manager for Shell Exploration and Production's Alaska operations.
Slaiby also spoke about the company's plans at an Anchorage Chamber of Commerce meeting April 20.
A third well might be drilled if weather and ice conditions allow, he said.
In the Beaufort Sea, Shell would pick alternative prospects to those the company planned to drill in 2007 and 2008, and which are now subject to litigation and an injunction ordered by the U.S. 9th Circuit Court of Appeals in San Francisco.
Slaiby said the company has several other interesting prospects on its Beaufort Sea leases that can be tested while the court considers the lawsuit on the wells planned two years ago. The contested prospects are in an area 15 miles to 20 miles offshore from Point Thomson, east of Prudhoe Bay, and in the path of migrating bowhead whales.
Environmental groups and Inupiat whalers filed suit to block Shell's drilling on those locations. The appeals court initially issued a decision voiding the U.S. Minerals Management Service's permits for the drilling, but then in an unusual move, voided its own decision earlier this year. The court has not yet issued a new ruling.
Slaiby also said issues raised in a separate decision issued earlier this month by the 5th U.S. Court of Appeals in Washington, D.C., do not affect Shell's Beaufort Sea leases, although they could affect the Chukchi Sea.
The 5th Circuit Court's decision faulted the U.S. Minerals Management Service on its analysis of environmental effects of drilling, and that affects the U.S. Outer Continental Shelf five-year leasing program beginning in 2005, which covers six lease sales in the U.S. Gulf of Alaska as well as the Chukchi Sea sale.
Shell hopes that issues affecting the Chukchi Sea will be resolved before the company's wells are to be drilled, Slaiby said.
Shell has invested hundreds of millions of dollars in preparations for its Alaska exploration programs, as well as over $2 billion spent in bonus bids for federal OCS leases in the Chukchi Sea.
The company had a false start in 2007, when it marshaled a fleet of two drillships and numerous support vessels to drill the three prospects north of Point Thomson, and then was stopped by the litigation.
Slaiby said Shell has scaled back its exploration plans to one drilling vessel, partly because of difficulty in getting government permits for the more ambitious two-rig exploration program the company had initially planned.
Air quality permits required by the U.S. Environmental Protection Agency have been a particular source of frustration, he said. Shell has spent $13 million over three years attempting to get EPA's approval on permits for the Beaufort wells.
Part of the problem is that the agency's air permit program is geared more for onshore than offshore operations. For example, a requirement in regulations for fencing is obviously unneeded and impractical offshore, he said.
Another problem has been that EPA's Region 10 offices in Seattle, which administer permits for the Alaska region, has been understaffed, Slaiby said.
An exploration program in 2010 or 2011 would still involve a small flotilla of support vessels. Slaiby said an oil spill response vessel built by Arctic Slope Energy Services for work in Arctic regions and under long-term charter to Shell, will be on hand as well as a spill response barge and a tanker capable of holding oil recovered if a spill were to occur.
The most difficult problem, however, is that the environmental review and permitting process mandated by the National Environmental Protection Act sets out a minefield for potential litigation.
"The regulators are professionals, and the NEPA process has been in place since the 1970s and it is managed by professionals, but lawsuits are costing companies like Shell to waste hundreds of millions of dollars due to delays," Slaiby said. "It's ironic that people who oppose offshore development don't seem to be concerned about our increasing reliance on oil imported from overseas, or that even the best-run tanker systems are five times more prone to an oil spill than an offshore producing platforms."
In Canada’s drilling sector, industry insiders say service firms are trying to save cash by tearing equipment off idle drilling rigs to repair ones that are working. This is the traditional slow time of the year for Alberta’s oil and gas exploration sector, as the melting landscape imposes weight limits on backcountry roads and makes many out-of-the-way regions of the province impassable.
Spring is also traditionally when drilling companies pull equipment back to their maintenance yards in places such as Nisku and Blackfalds or park them in truckers’ yards or on their last drilling lease to repair and equip them for the summer season that starts in early June.
This year, fewer of those rigs will be redeployed. “I’m not sure the overall rig fleet (count) will decline, but a bunch of them will be mothballed,” said Duane Mather, chief executive of Nabors Canada, which has 85 drilling rigs in Western Canada, mostly in Alberta.
“Everybody’s already doing that. If you have three or four rigs in one area . . . you aren’t going to bid all of those rigs. You’ll just bid one of them.”He said if a company can avoid spending money by moving parts from one rig to another, it will.
“I would say there are probably 100 rigs in the fleet across the province that are older-generation stuff.” said Mather. “That’s not competitive so it will get left laying and will get cannibalized for major components that are in good condition because those rigs are going to be the last ones to ever go to work regardless of what the market is.”
Ken Mullen, president of Savanna Energy Services Corp., said just two of his firm’s 87 Western Canada-based rigs were working as of April 20, as customers are affected by a slow first quarter, an earlier than usual spring breakup and the sinking natural gas price.
“There’s no incentive for guys to get back to work,” Mullen said. “They’re not going to spend any extra dollars to try to pull things through the mud or accelerate any programs. That’s for sure.”
Savanna’s rigs are all relatively new — the company was founded in 2001 — but they are being selective in spending money to recertify the rigs with the provincial regulator, a process they must undertake every 1,000 working days, effectively reducing the number of rigs that can be deployed.
Recertification can cost from $75,000 to 10 times that, depending on what needs to be done.
“The downside of having a brand new fleet is that if there’s no activity out there, it’s a newer, higher capital cost fleet that’s sitting idle,” he said.
Canada’s largest drilling company, Precision Drilling Trust, reported it had laid off 14 per cent of its workforce in Canada and the United States in the first quarter and is consolidating facilities because of the drilling slump.
It expects capital spending to fall by $29 million this year from earlier estimates of about $240 million, in part due to deferred maintenance.
“Right now, if we can avoid buying some drill pipe, we’ll avoid buying drill pipe,” said chief executive Kevin Neveu.
Don Herring, president of the Canadian Association of Oilwell Drilling Contractors, said estimating the size of the drilling fleet is difficult.
His organization collects a fee to list its member’s equipment, but doesn’t guarantee that gear is ready to be employed or even certified by the province.
“There will be a number of companies that will park equipment,” he said. “But there’s no incentive for them to tell us they’re going to do that.
“They’ll take the least efficient rigs and park them. The ones that cost the most to move, generally, are the ones they’ll retire. They won’t market them.”
Scavanging of parts is also common during downturns, he said.
Alberta’s new drilling incentive program that started April 1 may have actually resulted in less business for drillers, Mullen said.
Some customers put off starting wells until after the program kicked in so they could get the $200-per-meter drilling credit, but the natural gas price continued to fall in the meantime, making the overall economics look worse.
John Tasdemir, service sector analyst for Tristone Capital, agreed that service companies are saving money where they can these days to weather the drilling slump.
“Typically, you use this downtime to spend money on your equipment . . . people are absolutely not doing that this year,” he said. “You only spend on the rigs that are going to go to work.”
Similarly, service companies are using up their inventories of gear such as drill pipe before ordering any more.
“Last year, let’s say you worked 100 rigs,” he said. “This year you think you’re only going to work 50 rigs, so you’ve got 50 rigs of spare consumable parts, so capital spending is going to drop dramatically.”
Mather added there are very few new rigs being built, although Nabors has two nearly complete rigs being built for a “targeted niche in the market.”
Mullen pointed out Savanna moved 16 rigs to the United States in the past 18 months, but that market has also slowed.
As of April 14, the Canadian Association of Oilwell Drilling Contractors noted there were a total of 862 rigs in the western Canadian fleet, down three per cent from 887 a year earlier.
Only 91 of the rigs are shown as working this year, with 771 idle, compared with 101 working and 786 idle last year.
A key difference is that a dramatically lower number of wells are predicted to be drilled this year. The contractor association revised its forecast downward in February to 11,176 wells, about one-third less than last year.
Tristone said recently there will likely be only 10,500 wells drilled in Western Canada this year, down 24 per cent from its previous forecast, with only 6,500 wells in Alberta, a 45 per cent drop from 2008 due to low natural gas prices and lack of capital.
Activity levels were expected to be flat in British Columbia, and fall by 25 per cent in Saskatchewan due to increased spending on the Montney and Horn River shale plays.
Peters & Co. has forecast just 10,000 wells will be drilled in 2009.
Chad Friess, a service sector analyst for UBS, said in a recent note the slowdown in the first quarter is a sign of things to come.
“The U.S. natural gas market remains two (billion) to three billion cubic feet per day oversupplied and, in the absence of a sooner than expected economic recovery, we don’t expect the market to balance until Q4 as the supply impact of a 1,200-plus decline in the rig count begins to take hold,” he wrote.
“This, coupled with Canadian exports which are down 14 per cent (1.2 bcf per day) year over year should serve to balance the market, offsetting expected higher LNG imports.”
TheTransCanada's Keystone XL Pipeline is a 1,980-mile-long, $7.2 billion project with a capacity to carry 900,000 barrels a day of crude oil from Hardisty, Alberta, to refineries on the Texas Gulf Coast.
Along its 283-mile path through Eastern Montana, the pipeline will drop $57.6 million a year in property tax revenues from Phillips to Fallon counties, Gov. Brian Schweitzer said last July when announcing the pipeline. In a joint project rollout with officials from TransCanada, the governor said just the Montana portion of the pipeline would cost $1 billion.
The Montana portion is part of the Steele City Segment, one of three segments that will take the pipeline to the Gulf Coast. The Steele City Segment begins in Hardisty, crossing the border north of Malta at the Port of Morgan and exiting southeast of Baker into South Dakota. It will pass through Philips, Valley, McCone, Dawson, Prairie and Fallon counties.
Keystone XL slices through South Dakota and Nebraska to connect at Steele City, Neb., with the Keystone Cushing Segment, a separate project now being built between Steele City and Cushing, Okla. From Cushing, Keystone XL picks up again with the Gulf Coast Segment, which extends to Nederland, Texas. The final segment, the Houston Lateral, stretches to a point near the Houston Ship Channel.
The Gulf Coast and Houston Lateral are expected to be finished in 2011. Construction on the Steele City Segment should begin in the fall of 2010 or the spring of 2011, depending on the speed of the permitting, and be completed in 2012.
Local officials along the route generally are pleased at the prospect of a big boost in tax revenues that the pipeline would bring. But landowners have voiced reservations about their compensation and about impacts to their land and agriculture operations.
"It's not much that the property owners will get out of it," said Jim Skillestad, a farmer-rancher who also is a Dawson County commissioner.
And landowners and environmentalists have challenged the company's plan to use a thinner-walled pipe than has been the accepted standard.
"Thicker pipe provides a little extra insurance," said Paul Blackburn, a South Dakota environmental lawyer.
According to specifications provided in Keystone XL's Montana Major Facilities Siting Act application, TransCanada will use 36-inch diameter steel pipe treated inside and out with a corrosion-resistant coating.
Typically, trenches will be 7 to 8 feet deep and 4 to 5 feet wide. Topsoil will be excavated and preserved so it can be used in reclamation. The pipeline will be buried at a minimum depth of 4 feet, except in areas of consolidated rock, where it will be at least 3 feet deep.
Pipes will be welded together above ground. The application said every weld will be inspected using radiographic, ultrasound or other leak detection methods approved by the U.S. Department of Transportation. The line will be pressure-tested with water before crude starts flowing.
TransCanada plans 30 pumping stations along the entire route, including seven in Montana. Each will be constructed on a 5-acre fenced and locked site.
Safety valves will be installed at intervals and can be shut off automatically to isolate leaks. Valves will be placed on both sides of rivers it crosses. The pipeline will be bored under 10 Montana rivers and streams, including the Milk, Missouri and Yellowstone rivers.
To service pump stations and safety valves, local electric co- ops will build about 180 miles of new power lines, the application said.
Supervisory Control and Data Acquisition systems, a satellite-based system managed from Operations Control Center in Calgary, will operate the pipeline and provide remote emergency shutdown of valves when leaks are detected. Shutdown takes about nine minutes, plus three minutes to close valves to isolate and drain the leak site.
Major leaks are rare, the application said.
"For any one mile segment, this probability is equivalent to one spill every 8,400 years," it said.
TransCanada plans aerial patrols of the line 26 times a year, none more than three weeks apart, in accordance with federal regulations.
The Montana segment of the pipeline will be constructed in four "spreads" ranging from 80 to 120 miles each, the application said. Between 450 and 500 people will be working on each spread, with another 50 performing inspections. TransCanada spokesman Bud Anderson said contractors will probably be hiring some local people to work on the project.
The application said that as a rule of thumb, clearing, grading and trenching takes about three weeks. Although the permanent right of way will be 50 feet, the temporary construction easement includes an additional 60 feet.
Welders should he able to average 1.25 miles per day, or about 7.5 miles in a six-day work week. After the welding is complete, another seven weeks of work begins, including inspection of welds, coating of joints, lowering the pipe into the trench, backfilling, right-of-way cleanup, hydrostatic testing, reseeding and other reclamation.
The project will disturb a total of about 4,300 acres along the long ribbon of its route.
TransCanada plans to use existing roads where possible but anticipates that 3.5 miles of new permanent road will be needed for access to valves and pump stations. These roads will be 15 feet wide and will be used about once a month, the application said.
The estimated life of the pipeline is about 50 years. TransCanada said that it has not yet written a plan of abandonment.
TransCanada Corp. on April 23 filed paperwork for approval to begin the work needed to get U.S. regulators' approval for its proposed multibillion-dollar natural gas pipeline from Prudhoe Bay to Alberta, Canada.
The Calgary-based company is pursuing one of the two pipelines proposed. The rival project, a joint venture of North Slope producers BP and Conoco Phillips -- already has applied for the so-called pre-filing status with the Federal Energy Regulatory Commission.
The pre-filing allows the backers of the projects to coordinate and communicate better with FERC staff as they prepare for a formal application to have their projects sanctioned.
Both pipeline proposals are in early stages of development as the companies involved study the strengths and weaknesses of different routes, conduct initial engineering, estimate costs and do other work. A decision on whether to proceed with construction could be a couple of years from now.
Federal regulators have said that both competing projects are unlikely to be completed.
Construction of a major underground oil pipeline along the eastern edge of Illinois’s Sangamon County could begin as early as this summer.
An energy developer and the Canadian consul general from Chicago were in Springfield recently to seek support for the endeavor as a major boost for jobs and energy security, including a meeting scheduled April 29 with Gov. Pat Quinn.
The first section of the nearly 3-year-old, $350 million construction project has been completed to an area about 50 miles northeast of Peoria.
But the final phase has run into opposition from environmental groups and some landowners, who say the pipeline would only encourage continued reliance on polluting petroleum products and would violate property rights.
“Canada has the second-largest reserves in the world. There’s 170 billion barrels of reserves, and 97 percent are in the oil sands,” said Don Thompson, president of The Oil Sands Developers Group.
Thompson was referring to oil fields in Alberta, Canada, which already supply much of the oil refined in Illinois.
Canadian consul general Georges Rioux estimated $15 billion worth of refinery upgrades and pipeline construction have been completed or begun in order to improve the energy infrastructure connecting Canada and the United States.
Another transcontinental pipeline is nearing completion in Missouri that would connect Canadian oilfields to a major refiner at Wood River, just northeast of St. Louis.
Rioux said the company is well along in negotiating property rights for the remaining section of the Illinois pipeline and would like to complete construction by early 2010. But he said the visit to Springfield and with Quinn also is intended to head off long-term measures such as the “low-carbon” fuel rules recently approved in California.
Congress also is considering low-carbon emission rules as part of a national climate bill to limit pollutants linked to global warming, including petroleum products.
“Right now, about 50 percent of the oil coming into the Midwest is coming from Canada. That’s going to go up in the next 10 years to about 75 percent,” said Rioux, who added that the Canadian government has continued its discussions with the Obama administration.
“We’re working very hard in Washington to come up with a North American approach to climate change. We’re working to come up with a North American approach to car emissions,” Rioux added.
Opponent filings at the ICC, including from a group of Sangamon County landowners, contend Enbridge has not proved the need for additional capacity that would, in some cases, allow the company to take land by eminent domain.
The filing also takes issue with the company’s claim that the pipeline is needed to protect the nation’s energy supplies.
“These vague notions of energy security and independence cannot provide proof positive of public need as such benefits are indefinite,” according to documents filed in court by the opponents.
Thompson and Rioux are accompanied on their Springfield visit by Illinois Petroleum Council executive director Dave Sykuta. Sykuta said meetings also are planned with legislators, who eventually may be called upon to approve state climate-change rules.
Sykuta said industry projections are that U.S. consumption of 150 billion gallons of oil annually will increase to 180 billion by 2030, even with smaller, more fuel-efficient cars and conservation measures.
“We can talk about ethanol and all the alternatives, and that’s fine, but in the end, the heavy lifting for the Illinois and U.S. economies is still going to be done by oil and natural gas-based products,” Sykuta said.
Sangamon County Farm Bureau manager Jim Birge said the group is monitoring the potential impact on farmland but has not taken a position on the project.
“We’ve met with them. Last year, we were dealing with the Rockies Express pipeline, and this just happens to be petroleum,” Birge said, referring to a major east-west gas pipeline that cuts through southern Sangamon County.
“There’s still a lot of permits and lots of studies that have to be done. We are watching it until it gets a little more defined,” he said.
ICC spokeswoman Beth Bosch said a deadline has not been set for a decision, but she said draft orders have been filed, “and that’s usually a sign” a ruling is near.
Announced in 2006 by Enbridge Inc., the $350 million project would extend a 36-inch-diameter, underground oil pipeline from Flanagan, northeast of Peoria, to a major refinery at Patoka, just east of metro East St. Louis. A section of the pipeline would cut through eastern Sangamon County, along the border with Christian County.
The southern extension would complete a network from “oil sands” in Alberta, Canada, to downstate Illinois refineries, and eventually the Gulf Coast.
Initial capacity of 400,000 barrels a day could be increased to 800,000.
A petition for approval of the pipeline’s final section is pending before the Illinois Commerce Commission. If approved, the company plans to begin construction this summer and complete construction by early 2010.
Petrobras issued a letter of intent to SBM Offshore for a lease and operate contract covering SBM's existing floating production storage and offloading vessel (FPSO) Capixaba. The FPSO will work for a period of 12 years at the Cachalote field offshore Brazil.
FPSO Capixaba will be disconnected from its current location at the Golfinho field offshore Brazil and after transfer to a shipyard, the FPSO will be modified and upgraded for the new application. The FPSO will then return to Brazil for offshore hook up, installation and operation on the Cachalote field.
The execution schedule extends for a period of eight months, from planned disconnection at the Golfinho field in June 2009, to first oil on the Cachalote field in February 2010. The relocation and upgrade work will require a significant additional capital investment in the unit, resulting in an amended lease contract with a new lease rate which will be payable from date of start-up on the Cachalote field.
The order represents an additional portfolio value of approximately US$1 billion for the total of the relocation fee and the non-discounted total of the fixed lease rates payable over the 12 year lease period, after deduction of the remaining years' revenues from February 2010 under the original FPSO Capixaba lease.
Cuba would welcome U.S. companies’ help developing its oil industry should the 47- year trade embargo on the communist island come to an end, said Manuel Marrero Faz, senior oil adviser at the Ministry of Basic Industries.
“We are open,” said Marrero Faz, noting that Chinese, Russian and Angolan companies are in talks to explore areas about 100 miles off the U.S. coast. “We’re very close to each other. We’re neighbors. Why not do business?”
Should nearby U.S. companies offer services and supplies, Cuba would be able to lower its costs and pick up the pace of development, said Marrero Faz, who learned geology as a student in the former Soviet Union. The difficulty of getting equipment from partners halfway around the world is a key reason only one offshore well has been drilled so far, he said.
Marrero Faz’s comments represent one of the strongest signals yet that Cuban President Raul Castro is ready for a new relationship with the U.S. under President Barack Obama. In Washington, Cuba’s incipient oil industry is helping fuel a growing campaign to ease the trade embargo that President John F. Kennedy imposed in 1962 to try to topple Fidel Castro’s Soviet-allied regime.
U.S. business interests -- watching from the sidelines as global competitors scoop up contracts -- as well as lawmakers and policy groups are becoming more vocal that the time for a change has come.
“It’s stupid that the U.S. prohibits its companies from coming here,” said Gustavo Echeverria, a researcher at Cuba’s Center for Petroleum Investigation, who spoke after giving a presentation at a Havana oil conference last month. “Everyone else is taking the fields on its doorstep.”
The Havana conference was attended by New Delhi-based Oil & Natural Gas Corp., and Rio de Janeiro-based Petroleo Brasileiro SA and Caracas-based Petroleos de Venezuela SA, which already have exploration agreements.
Madrid-based Repsol YPF SA, Hanoi-based Vietnam Oil & Gas Group and Kuala Lumpur-based Petroliam Nasional Bhd., which also have accords and attended the conference, have opened offices in Havana’s Miramar district.
“We would definitely like to continue here,” said Sushil Chandra, Cuba project coordinator at the Indian company, known as ONGC.
While Obama has expressed support for relaxing some restrictions on family visits and cash remittances to Cuba, Vice President Joe Biden said March 28 that the U.S. has no plans to lift the trade embargo.
Any move to do so would be controversial in Congress. Easing the sanctions, without demanding concessions to lessen “the oppression of the people by the regime, will serve to strengthen the dictatorship and demoralize the Cuban people,” a group of congressmen including Florida Republicans Lincoln Diaz-Balart and Ileana Ros-Lehtinen said in a March 24 letter to Obama.
Cuba says its offshore deposits hold 20 billion barrels of oil, enough to supply the U.S. for almost three years. The government hasn’t disclosed how it arrived at the figure, which is more than quadruple the almost 4.2 billion barrels estimated to lie beneath Alaska’s Arctic National Wildlife Refuge.
The U.S. Geological Survey estimates Cuba’s North Basin region, one of three offshore areas believed to hold oil, has 4.6 billion barrels.
In the Caribbean, along Cuba’s north coast facing Florida, 19 miles from Havana, a drilling tower is seen. The rig, brought to Cuba by a unit of China National Petroleum Corp., or CNPC, is being used by the island’s state-owned oil company, Cubapetroleo.
Russian companies including OAO Gazprom, Russia’s largest company, and OAO Rosneft, both based in Moscow, are in talks with the Cuban company, known as Cupet, and may sign contracts for as many as four exploration blocks by the end of the year, Marrero Faz said. CNPC, China’s biggest oil producer, may also reach an exploration deal by the end of 2009, he said.
Toronto-based Sherritt International Corp., Cuba’s largest foreign-energy partner, has produced oil from Cuban wells since 1992. Its average output of 31,200 barrels a day in 2008 accounted for two-thirds of the country’s domestic production, according to the company’s Web site.
Just as U.S. producers are blocked from projects only five days by tanker from Louisiana refineries, oil service companies such as Houston-based Halliburton Co., are also unable to take advantage of their proximity to undercut competitors on price, said Jorge Pinon, energy fellow at the University of Miami.
“We have a long-term relationship here, and clearly the Americans don’t,” said Peter Huff, president of Calgary-based Datalog Technology Inc., a company that helps detect oil for Cupet, Repsol and Sherritt in Cuba. “That’s a competitive advantage for us.”
U.S. oil companies including Texaco Inc., acquired by Chevron Corp. in 2001, and what’s now Irving, Texas-based Exxon Mobil Corp., last operated in Cuba in 1960, when their refineries were expropriated.
Exxon Mobil spokesman Len D’Eramo said the company’s global exploration program is confidential. Chevron spokesman Justin Higgs didn’t respond to requests for comment.
Charlie Rowton, a ConocoPhillips spokesman, said the company doesn’t speculate about future activities.
Pressure in the U.S. is growing for Obama and Congress to open up to Cuba. Senator Richard Lugar of Indiana, the senior Republican on the Foreign Relations Committee, said in a report last month that U.S. policy toward Cuba has failed.
The Brookings Institution, a Washington-based research and policy organization, said in a report in February that the U.S. should license energy companies to work in Cuba as part of full restoration of trade and diplomatic relations. The National Foreign Trade Council, a Washington-based group of companies and trade associations, is also calling for U.S. firms to work on the island.
Still, investing in Cuba has risks. The offshore reserves are unproven by U.S. standards and drilling an exploratory well at 1,500 meters (4,921 feet) beneath the sea would cost about $100 million, Marrero Faz said. As oil hovers around $50 a barrel, it’s less attractive than when crude prices set a record above $140 a barrel in July 2008.
“There isn’t a sense of urgency,” said Pinon, who signed the Brookings report. “But in the long term, of course U.S. oil companies want to come.”
Mexican tycoon Carlos Slim has set his sights on Chicontepec, an oil project that state monopoly Petroleos Mexicanos is pouring money into despite the price crash.
Slim's Servicios Integrales GSM has attended project meetings and paid bidding fees for a 170-well contract, according to documents on Mexico's Compranet government procurement Web site.
Industry executives expect the unit of industrial conglomerate Grupo Carso SAB to be a main competitor when bids come in on April 7.
Mexican oil production is in freefall, forcing Pemex to ramp up drilling in an effort to correct decades of underinvestment. This makes Pemex a top client for oil service providers during a year when other integrated oil companies from Canada to the Middle East are cutting costs and mothballing drilling equipment.
Unlike most foreign drillers bidding for Chicontepec, Mexico-based Servicios Integrales GSM won't have to haul equipment in from abroad, which would lower its startup costs. Also, the two most established players at Chicontepec, Schlumberger (SLB) and Weatherford (WFT), have their hands full after they both won larger drilling contracts last month at the geologically complex basin. This means they are less likely to cast lowball bids to fence out smaller rivals.
Schlumberger may not even compete. They haven't turned up at any project meetings or bought the bidding rules for the 170-well tender, said an oil executive who has attended the meetings.
Schlumberger wasn't immediately available for comment.
Slim, a telecoms magnate ranked by Forbes magazine as the world's third richest man, has sprawling industrial concerns that rake in profitable government contracts ranging from highways to water treatment plants. At Chicontepec, Pemex plans to invest $11 billion over the next four years, making it an attractive target for drillers struggling with a global industry down cycle.
The upcoming contract is designed to attract smaller companies looking for a foothold at Chicontepec and to give Pemex a more diverse pool of suppliers. The previous two contracts were each for 500 wells, three times as large.
Halliburton (HAL), Baker Hughes (BHI), and Nabors Industries Ltd. (NBR), as well as China's Sinopec, are all looking to set up shop at Chicontepec.
Over the years Slim has profited from Mexico's oil industry the only way a private company can, by winning contract work with the state monopoly. Mexican law still blocks anyone but Pemex from owning or selling crude.
Slim's engineering and construction companies have built offshore platforms and other infrastructure for Pemex. He was even briefly a member of Pemex's board in 2001 under an effort by then-president Vicente Fox to make the state oil monopoly more efficient. Slim and other businessmen named to the board were withdrawn, however, after the move caused an outburst of oil nationalism.
Slim has recently taken a wider interest in oil services. In March he raised to 15.67% his stake in U.S.-based Bronco Drilling, a company that has three rigs operating in Mexico and sees scope for more work south of the border.
The Chicontepec contract will be a challenge for whoever wins. Each well produces only around 100 barrels a day, compared to 10,000 barrels a day at more prolific wells in Mexico's shallow waters of the Gulf.
Tulsa based Flow-Quip, Inc. has been selected by PEMEX Mexico to supply four Hydra-PAK SE Series fail-safe electric actuators capable of storing energy for two strokes of each valve without electrical power.
PEMEX is doing an expansion and upgrade of the JPC Maya Crude Oil Dehydration Facility at Dos Bocas Marine Crude Oil Marine Terminal in Tabasco, Mexico.
Flow-Quip's valve actuators, supplied with four 36" ANSI 150 full port pipeline ball valves, will be installed on a pipeline to the 600,000 bbl/day capacity facility.
Flow-Quip President Milton Fore said, "These are critical pipeline inlet and outlet shut off valves that must operate in case of a facility shutdown, even if electrical power is not available. Flow-Quip's over 30-year history with valve actuators enables us to customize actuator solutions for clients like PEMEX."
Flow-Quip, Inc. is a Tulsa-based manufacturer of valve actuators and valve automation systems for applications and industries worldwide. The company provides on/off and modulating valve automation solutions to refineries, pipelines, offshore platforms, power plants, water treatment facilities and municipal water systems. Flow-Quip manufacturers and tests complete valve automation packages from the very basic to the most sophisticated.
Northern Technologies International Corporation on March 31 announced the signing of multiple Research and Development (R&D) contracts with Petroleo Brasileiro S.A. -- Petrobras research and development group at the Leopoldo Americo Miguez de Mello Research & Development Center (CENPES). The joint team from NTIC, Petrobras and CENPES led by Mr. Marcelo Schultz of Petrobras will undertake a 20-month Petrobras funded effort to explore, understand and resolve bottom plate corrosion issues in Aboveground Storage Tanks (ASTs).
A second 12-month Petrobras sponsored project has also started aimed at field trials of certain pipeline protection technologies. These initiatives will help mitigate corrosion for critical Oil and Gas industry infrastructure. The projects are directly between NTIC and Petrobras and will primarily be supported by NTIC's R&D facilities in Beachwood, Ohio. Any new intellectual property generated will be jointly owned by NTIC and Petrobras with NTIC having access to commercialization rights.
"We believe that our joint efforts will bring innovative solutions to problems that not only Petrobras, but also the Oil and Gas Industry have been facing for years regarding corrosion protection for the bottoms of aboveground storage tanks," said Mr. Marcelo Schultz, Corrosion Specialist at Exploration & Production Department of Petrobras -- RJ. "At Petrobras, we are constantly investing in new technologies that can affect positively the performance of our equipment and processes, and specifically reduce the risk of any environmental impact," continued Mr. Schultz.
"We are excited about these projects as they include not just elements of primary research into corrosion mechanisms, but the application of this knowledge to develop and test commercially viable solutions," said Professor Efim Lyublinski, Vice President -- New Technologies and Applications. "Having a globally respected oil company like Petrobras provide their operational facilities for field trials speaks to the enormous trust and confidence they have in NTIC's capabilities, and the significant value they expect to gain from our joint activities," Professor Lyublinski continued.
"Petrobras is a world leader in the Oil and Gas Industry and we are proud of our association with them. The problems we are addressing with Petrobras are common across oil companies worldwide and we expect to be able to leverage NTIC's Joint Venture network to support oil and gas clients worldwide with the results of our projects," said Patrick Lynch, President and CEO of NTIC. These projects, as well as others, are helping NTIC shore up the core solution development capabilities that are critical to expanding our portfolio of field tested and proven solutions."
ZERUST(r) Oil & Gas corrosion solutions are based on NTIC patented and/or proprietary technologies and are intended to significantly extend the service life of oil and gas industry infrastructure beyond the capabilities of conventional alternatives. NTIC has a core R&D team dedicated to the Oil & Gas sector based in Beachwood, Ohio and is currently conducting joint R&D, trials and is in commercial implementation with multiple oil companies around the world.
Petrobras has 109 production platforms and 15 refineries. It operates 23,142 kilometers of pipelines. Petrobras operates in Brazil, Argentina, Mexico, Portugal, the United States, Peru and Turkey, among others. Petrobras research and development programs are coordinated by the Leopoldo Americo Miguez de Mello Research & Development Center (CENPES: undefined, undefined, undefined %). In 2007, Petrobras invested R$ 1.04 billion in R&D through CENPES and entered into 62 agreements with 28 institutions for the expansion of its laboratory infrastructure in Brazil, putting R$ 131 million into projects with an average duration of two years
Northern Technologies International Corporation develops and markets proprietary environmentally beneficial products and technical services either directly or via a network of joint ventures and independent distributors in over 50 countries. NTIC's primary business is corrosion prevention. NTIC also offers worldwide on-site technical consulting for rust and corrosion issues. NTIC's technical service consultants work directly with the end users of NTIC's products to analyze their specific needs and develop systems to meet their technical requirements.
Peru will take bids for oil and natural gas exploration blocks in July as part of the South American nation’s biggest-ever drive to line up energy investment, said the head of Perupetro, the state oil-contracting agency.
The areas in the northern and central jungle and southern highlands will be awarded in November after meeting with potential investors in the US and UK, Perupetro boss Daniel Saba said April 1 in Lima.
“These are practically Peru’s last available exploration areas,” Saba said. “Companies are looking to invest in exploration this year despite low oil prices as they plan for the long term.”
The contracts are part of an effort to attract $10 billion in energy investments needed to double Peru’s oil and natural- gas output over the next five years, said a Bloomberg report.
Peru said the value of its oil and gas exports rose by 23% to $2.8 billion last year.
Companies in Peru are slated to spend about $1.4 billion in oil and gas exploration this year, up from $1.1 billion last year, Saba said.
Peru has a record 107 exploration contracts with companies including ConocoPhillips, Reliance Industries, and Petrobras.
Petrovietnam has signed framework agreements with state oil companies from Argentina, Bolivia and Nicaragua as part of efforts to acquire more oil assets in South and Central America.
"The agreements paved the way for Petrovietnam to carry out oil and gas surveys and buy oil assets in those countries," a Petrovietnam spokesman said April 2.
He said the group would dispatch exploration teams to the three countries this year to survey potential oilfields there.
Last year Petrovietnam also entered into cooperation agreements with state oil companies in Cuba, Venezuela and Peru to explore for oil and gas there as it sought to offset declining output at home.
In February Petrovietnam said its venture with Venezuela's PDVSA would start producing oil from Venezuela's block Junin 2, estimated to hold 97 million tonnes of recoverable oil, in two years, reported Reuters.
Peabody Energy on April 15 announced an agreement with the Government of Australia to become a founding member of the Global Carbon Capture and Storage (CCS) Institute, an international initiative to accelerate commercialization of CCS technologies.
The new organization has a mandate of facilitating development of 20 integrated, industrial-scale carbon capture and storage demonstration projects worldwide by 2020. The Australian Government has committed to host the institute and provide A$100 million annually to fund the effort.
"We are privileged to join other international organizations as a founding member of the Global CCS Institute. Coal is the world's fastest-growing fuel, with global coal use expected to grow over 60 percent by 2030. Initiatives such as these are essential to enable all of us to meet our shared goals of robust economies, sustainable energy and an improved environmental footprint," said Peabody Chairman and Chief Executive Officer Gregory H. Boyce.
"We are confident that coal with CCS will be the low-cost, low-carbon alternative and are pleased to support this initiative by the Australian Government, which will accelerate the commercialization of carbon capture and storage technology. We also congratulate Prime Minister Rudd for his leadership in this area and his determination to achieve our shared objective: greater use of clean coal with near-zero emissions."
Australian Prime Minister Kevin Rudd first proposed the institute as a means to speed the delivery of CCS demonstration projects through greater international coordination and cooperation. The institute will complement existing global CCS efforts by bringing together the world's leading carbon researchers, industry consortia and governments to coordinate a broad range of industrial-scale demonstration projects needed to commercialize technologies.
The institute will become the first global body focused on widespread global deployment of CCS by identifying and supporting necessary research, providing input to governments on regulatory frameworks, and helping develop technologies from the pilot stage to commercial-scale operations.
Technology advances are being made around the globe to capture and store carbon dioxide in oil fields, deep saline storage and beneath the ocean floor in geology that offers both ample space and permanence. Carbon dioxide has been used successfully for enhanced oil recovery for several decades, and CCS could lead to production of another 2 to 3 million barrels of oil per day in the United States alone, according to a study by the National Coal Council. Coal with CCS is also the low-cost clean energy option: Recent Carnegie Mellon research shows that coal with CCS is 15 to 50 percent less expensive than nuclear, wind or natural gas with CCS.
Peabody Energy is advancing signature projects around the world to commercialize near-zero and low-carbon emission technologies, including GreenGen in China, the COAL21 Fund in Australia and FutureGen in the United States. The company's support for the Global Carbon Capture and Storage Institute follows its $10 million commitment to leading academic institutions to facilitate clean coal and advanced mining technologies research at Washington University in St. Louis, the University of Wyoming and the University of Arizona.
Peabody Energy is the world's largest private-sector coal company, with 2008 sales of 256 million tons and $6.6 billion in revenues. Its coal products fuel 10 percent of all U.S. electricity generation and 2 percent of worldwide electricity.
Royal Dutch Shell PLC is delaying or dropping some alternative-energy projects in China as too costly, given current oil prices, executives said April 14.
Lim Haw-Kuang, executive chairman of Shell Companies in China, said in Beijing that because of the economic downturn, it decided to postpone a joint venture with Shenhua Group, China's top coal producer and parent of China Shenhua Energy Co., to turn coal into liquid fuel.
Shell had conducted a feasibility study with Shenhua to build a coal-to-liquid plant in the country's western Ningxia Autonomous Region. Shenhua has been independently pursuing coal-to-liquid projects with its own technology in the country's Inner Mongolia region, but the collapse of oil prices and China's scarcity of water resources have made many of these projects unviable.
Mr. Lim said coal gasification -- turning coal into gas, often for use as a feedstock for making chemicals -- has been a strong driver of Shell's growth in China. It has reached 20 licensing deals in recent months with Chinese companies to use Shell technology. He didn't name any of the companies.
Shell executives said they have also abandoned a foray in northern China into oil shale, a costly and technologically challenging type of oil to produce.
Separately, Shell confirmed it was talking to potential Chinese partners about a joint bid to develop oil fields in Iraq, CEO Jeroen van der Veer said.
Shell Chief Financial Officer Peter Voser, in Beijing to meet with government officials and company executives and expected to take over soon as chief executive, said on April 14 the company is working on restarting the Soku liquefied-natural-gas plant in Nigeria "sooner rather than later."
Violence in the fossil-fuel rich Niger Delta has forced Shell to shut down part of its oil and natural-gas production in the West African country.
India has started its largest auction of oil and gas fields, offering 70 areas for exploration when energy producers are cutting investments because of falling prices and the global recession.
The nation is offering 24 deep-water blocks and 28 shallow- water blocks for exploration, Oil Secretary R.S. Pandey said. The fields on offer include 18 on-land blocks, he said.
Asia’s third-largest energy consumer, seeking to cut oil imports, attracted bids for 45 of the 57 areas offered in the previous auction last year, when crude climbed to a record. Worldwide spending on oil and gas exploration may drop 12 percent in 2009 to $400 billion, Barclays Capital Research said.
“There might not be as much enthusiasm this time as in previous rounds,” Tony Regan, an independent analyst based in Singapore, said before the auction opened. “The biggest concern for companies is that India doesn’t allow export of oil or gas and, of course, pricing.”
The government has set the price of gas at $4.2 per million British thermal units, excluding transportation costs and taxes, based on crude oil costing at least $60 a barrel.
Bids for the 70 fields will close on Aug. 10, Pandey said. The South Asian nation is also seeking bids for exploration of gas trapped in coal seams in 10 areas. Contracts for the fields will be signed within four months of the bids’ closing, the government said in a statement.
The auction this year may be held in two phases, with the second part to be scheduled after the government assesses the response to the first, Pandey said.
“The question was whether to go ahead or sit tight,” Pandey said. “We decided to open the auction because the best antidote for a slowdown is to generate economic activity. There is a question about liquidity, yes. But liquidity will improve.”
The government is optimistic also because a shortage of drilling equipment, which deterred explorers last year, has eased. Rig use in Asia fell to the lowest in 12 months in March as the global recession sapped crude demand and squeezed credit, according to data from Baker Hughes Inc.
“Exploration in India will increase as more rigs become available,” said V.K. Sibal, director general of hydrocarbons, the nation’s oil regulator.
The use of rigs on land and water peaked at 265 in June, a month before oil prices reached a record $147.27 a barrel. Crude has since dropped 65 percent as the weak economy dents energy demand, prompting explorers to reduce or postpone drilling plans.
Increased availability of drilling equipment may not be enough to attract big overseas bidders.
“The squeeze on rigs is coming down and oil prices generally are expected to move up and that would keep companies interested,” said Regan, a former Royal Dutch Shell Plc employee. “But the big oil companies are unlikely to radically change their minds about India. There’s always a feeling among them that Indian companies will be favored.”
India is hoping explorers will be encouraged by the start of production this month from the biggest gas field operated by Reliance Industries Ltd., the nation’s most valuable company.
“We are hoping to catch investors’ imagination and show India is a prospective place to invest,” Pandey said.
India awarded 44 areas last year to companies, including BHP Billiton Ltd., the world’s largest mining company, and Oil & Natural Gas Corp., India’s biggest exploration company. A bid for one field by Cairn Energy Plc was rejected.
Explorers remain concerned about the withdrawal of a tax break for gas production, which led to bids for fewer fields than offered in the auction last year.
“The uncertainty on the taxation issue is a worry for investors,” said Niraj Mansingka, an analyst at Edelweiss Capital Ltd. in Mumbai. “Lower crude prices will not act as a deterrent as companies will bid with a long-term prospect in mind.”
India scrapped the seven-year income-tax holiday for gas in last year’s budget, while retaining it for oil projects.
“Investors have drawn our attention repeatedly on the issue of the tax holiday on gas,” Pandey said. “That is a matter under consideration of the government.”
The world’s second fastest-growing major economy started auctioning fields to overseas and domestic companies in 1999. Companies have spent around $10 billion on exploration and production from 1999 until December 2008, Pandey said.
Indonesian state-owned gas distribution company PGN hopes that its capital expenditure will increase to US$200 million in 2009, from US$150 million a year earlier, its financial director Riza Phalevi Tabrani said.
"Half of the US$200 million or US$100 will be used to develop pipeline distribution networks, while the remaining US$100 would be used to increase the capacity of PGN's subsidiaries," he said April 12.
Most of the capital expenditure funds (US$115 million) would be obtained from the company's internal sources, while the remaining US$85 million would come from the World Bank.
He said that PGN's projects in 2009 included the development of a liquefied natural gas receiving terminal in West Java.
The construction of the receiving terminal was urgent, to help overcome the LNG supply problem in the region, which needed a supply of about three million tons.
The supply capacity at present is only about 1.5 million tons.
Tabrani said the completion of some of the South Sumatra-West Java project (SSWJ) in 2008 had helped increase the company's cash flow.
"The cash flow of the company at the end of last year reached US$300 million," he said.
According to Tabrani, PGN has set itself a gas sales target of about 700-800 million metric standard cubic feet per day (MMSCFD) in 2009, higher than last year, which stood at 600 mmscfd.
Total E&P Nederland has awarded Subsea 7 a $26-million engineering, procurement, installation, and commissioning (EPIC) contract for the flowlines and subsea works on the K5CU development project in the Dutch sector of the North Sea.
The Subsea 7 work scope is to engineer, procure, install, and commission 15 km (9.3 mi) of 10-in. (25-cm) gas and 3-in. (7.6-cm) di-ethylene glycol (DEG) pipeline connecting the new un-manned K5CU satellite platform with the existing K5A riser platform. In addition, Subsea 7 will install a caisson riser system at the K5A platform and complete pre-commissioning activities topside to topside from K5CU to K5A.
Work will begin with engineering in the second quarter, followed by fabrication of the rigid pipelines at Subsea 7's North Sea Spoolbase at Vigra, Norway. Offshore installation is scheduled for the summer of 2010 using Subsea 7 in-house pipelay and construction vessels.
Air Products will play a key role in the world's first full demonstration of oxyfuel carbon capture and sequestration with the signing of an agreement with Vattenfall AB. Air Products will install its proprietary carbon dioxide (CO2) capture, purification and compression system at Vattenfall's research and development facility in Schwarze Pumpe, Germany.
Air Products will focus specifically on the purification and compression of oxyfuel combustion flue gas. The two companies also executed a joint research and development agreement related to the project. Air Products' pilot plant is to be operational at Schwarze Pumpe in December 2010.
Thermo Fisher Scientific's new M-Pulse multi-path ultrasonic liquid flow measurement system can accurately measure fluids from as low as 0.06cSt up to 1500cSt. The system's wider viscosity range was determined during recent testing and indicates its ability to further optimize use of multi-product hydrocarbon pipelines.
Pipeline operators can now run thick crude followed by gasoline, without requiring recalibration between the hydrocarbons. To fulfill larger pipe requirements, the M-Pulse now features an extended spool-size range including 500mm and 600mm spools along with the standard 100mm to 400mm spools. All spool sizes measure as low as 1ft/s and as high as 50ft/s to provide the highest turndown ratio of 50:1.
The flowmeter has no moving parts and removes the need for calibration after replacing the transducer. The M-Pulse comprises of a flowmeter and flow computer. Customers can use the Thermo Scientific Sarasota Density Meter in conjunction with the M-Pulse to provide rapid, repeatable measurement of liquid density for real-time control.
Both instruments will be on display at Achema in Frankfurt, Germany from 11-15 May 2009.
The construction of the Burgas-Alexandroupolis oil pipeline will start in 2010. The Greek government will submit a draft law to parliament by June 2009 that will expedite construction of the pipeline.
Once completed, the pipeline will pump 35 million metric tons of oil a year, a volume that could eventually be increased to 50 million metric tons. Russia holds 51% in the project company, while Greece and Bulgaria hold 24.5% each.
Marathon Oil Corporation announces the completion of the sale of its wholly owned subsidiary, Marathon Oil Ireland Limited (MOIL) to PSE Ireland Limited, a subsidiary of Petroliam Nasional Berhad (Petronas). The transaction has a total value of $180 million with an effective date of Dec. 31, 2007. This sale does not include Marathon's 18.5 percent interest in the Corrib natural gas development.
Including this transaction, Marathon has completed approximately $1.3 billion of the anticipated $2 to $4 billion in asset sales announced in March 2008. The Company expects further announcements related to this asset review and disposal program by mid-year 2009.
Under the terms of the sale, PSE Ireland Limited acquired Marathon's 100 percent operated interest in the Kinsale Head Area comprising Kinsale Head, South West Kinsale and the Ballycotton gas fields, as well as an 86.5 percent interest in the gas producing Seven Heads field which is tied back to Kinsale, and a 100 percent interest in the Company's gas storage business with current capacity of 7 billion cubic feet. As part of the transaction PSE Ireland Limited retains the 61 MOIL employees in Ireland.
Net production from these operations averaged approximately 30 million cubic feet of natural gas per day for the first quarter of 2009. Marathon's total net risked resource associated with these assets as of year-end 2007 was 62 billion cubic feet (bcf) of which 46.2 bcf (7.7 million barrels of oil equivalent) were net proved reserves.
Northern Petroleum (UK) has received the preliminary award of offshore Italian license d351C.R-.NP, covering 100 sq km (39 sq mi). Northern has begun work on an environmental impact study for the license area.
The award is adjacent to offshore license C.R146.NP, close to the Maltese maritime boundary. The license includes an extension to an existing mapped prospect within C.R146.NP.
Po Valley Energy Ltd has recorded positive gas flows during initial clean up and testing of the deepest level in its Bezzecca 1 appraisal gas well in northern Italy, its fourth Italian gas field development within its wholly-owned Cascina San Pietro permit area east of Milan.
Initial flows were tested at 2.2 million cu/ft per day on a quarter inch choke at 1760psi during initial clean up and testing of the deepest Miocene level from 1925m to 1945m.
Po Valley chief executive Michael Masterman says testing of the deepest Miocene level will continue with short tests to follow over the Pliocene and shallower Miocene levels.
Aker Solutions has announced that it has been awarded an engineering, procurement and construction contract by Dong E&P Norge to deliver a complete subsea production system to the operator's Trym field. Contract value is approximately NOK400 million.
According to the company, scope of work includes engineering, procurement and construction (EPC) of two subsea well sets, including trees, controls, wellheads and tie-in system, a four, slot template with manifold, 6km of steel tube umbilicals, a high pressure riser, tools and lifecycle services.
The subsea well sets for the Trym field will be from Aker Solutions's Rapid Solution program, which is a pre-configured system with a stocking program that aims to provide a well set within a fraction of the traditional system lead times.
It said that, the Trym field is located in the Norwegian sector just north of the Norwegian-Danish North Sea border, approximately 300km southwest of Kristiansand, Norway. The field's water depth is approximately 65m. The subsea production system will be tied back to the Maersk-operated Harald platform in the Danish sector, 6km south of the subsea field.
The project will be managed out of Aker Solutions's headquarters in Oslo. The majority of the subsea equipment will be manufactured at Aker Solutions's Norwegian facilities such as Tranby (subsea trees), Moss (umbilicals) and Egersund (template and manifold), said the company.
Orange County, CA-based geophysical surveying industry joint venture partner and service provider eField Exploration LLP has completed its first Offshore Airborne Survey for the oil and gas exploration industry.
Contracted by a Norwegian JV, the survey in the Nordland area of the Norwegian Sea was used to rapidly assess the potential of multiple blocks for the Norwegian Petroleum Directorate's 20th Licensing Round.
Flying over 100 miles offshore and over water up to 1000 feet deep, Passive Electromagnetic and High Resolution Magnetic data acquisition was completed in less than one week with a specially designed sensor package.
"Conventional methods such as Marine Seismic or CSEM would have taken months and costs would have been prohibitive" says Ed Johnson, president of eField. "Our Offshore Airborne System can cover up to 500 line miles per day at a fraction of the cost of a marine survey."
Johnson further noted that "eField's platform incorporates multiple sensors including high resolution magnetics and electromagnetics recording data from the air-ocean interface to sub-floor penetration. Satellite data is then added to provide valuable natural seep mapping."
This approach is significantly different than technologies that rely on spectral imaging, gravity, or magnetic measurements. These and other indirect measurement systems, like seismic, require time consuming data gathering and interpretation methodologies that identify anomalies or prospects which may or may not contain oil or gas.
Norway's Ministry of Petroleum and Energy has awarded nine production licenses in the Barents Sea and 12 new production licenses in the Norwegian Sea as part of the 20th licensing round.
The 20th Licensing Round is an important contribution to new industrial activity and jobs at a time when Norway is in the middle of a serious economic situation. The licensing round is also part of the effort to increase petroleum activities in the northern areas of Norway, the Ministry said in a statement.
"The awards will contribute to a steady level of activity on the Norwegian Continental Shelf and counteract future production decline, thereby maintaining the important role of Norway as a reliable and predictable supplier of energy," said Minister of Petroleum and Energy Terje Riis-Johansen.
The decision process on the 20th licensing round has run parallel to the work with the new management plan for the Norwegian Sea. The management plan will be put forward soon and the awards are in line with the new management plan.
"It is important to impose strict conditions relating to environmental and fisheries concerns to the companies receiving awards in the 20th licensing round. Block-specific conditions with among others time restrictions on exploration wells and seismic surveys will balance environmental, fisheries and petroleum concerns in a good way," says Riis-Johansen.
Thirty-four companies have been offered participating interests in production licenses, and 15 companies are offered operator-ships in the 20th licensing round. One company, North Energy AS, has been offered its first operatorship on the Norwegian continental shelf.
In line with the government policy of openness, an announcement proposal for the 20th licensing round was for the first time sent on a public consultation. For the first time also, after the deadline for applications the blocks applied for was also made available for the public.
Forty-six companies have applied for production licenses in the 20th licensing round by the application deadline on Nov. 7, 2008. The announcement of the 20th licensing round was June 27, 2008 and comprised 79 blocks in the Barents and Norwegian Sea.
Companies being offered operatorships include: AS Norske Shell; BG Norge AS; Chevron Norge AS; E.ON Ruhrgas Norge; Eni Norge AS; ExxonMobil E&P Norge AS; GDF SUEZ E&P Norge AS; Hess Norge AS; Lundin Norway AS; Marathon Petroleum Norge AS; North Energy AS; OMV Norge AS; Petro-Canada Norge AS; StatoilHydro ASA; and Total E&P Norge AS.
Chevron was awarded exploration rights in nine blocks in the licensing round. The blocks are located in the Outer Voring Basin in the Norwegian Sea, approximately 155 miles (250 km) west of the coast of Kristiansund, in 3,000 feet (1,000 m) of water. Chevron has been appointed as the operator with a 40 percent equity interest in the blocks 6703/7, 8, 9, 10, 11 & 12 and 6704/7, 8 and 10.
The other participants in the blocks are StatoilHydro with 20 percent interest, Shell with 20 percent interest and SD0E with 20 percent interest. The license was applied for jointly with StatoilHydro and Shell under an Area of Mutual Interest (AMI) agreement.
Guy Hollingsworth, president of Chevron Europe, Eurasia and Middle East, said, "We view the Outer Voring as an area of significant resource potential and this acquisition advances our strategy of pursuing attractive and high-impact growth opportunities. It's Chevron's first in the deep water of the Norwegian Sea and as operator, we look forward to working with our partners and bringing our technical expertise and capabilities to this high-potential area."
The license was applied for jointly with StatoilHydro and Shell under an Area of Mutual Interest (AMI) agreement.
The newly built Midia Marine Terminal, owned by the Rompetrol Group, has unloaded its first consignment of petroleum. The marine terminal is located 8.8km offshore Romania in the Black Sea.
The annual transfer capacity of the new Romanian terminal is 24 million tons of petroleum and is expected to allow for the reduction of at least $4 per ton to $5 per ton of the petroleum supply costs, by decreasing the distance by approximately 33km compared to the lay-out through the Constanta Harbor.
The terminal can receive ships with a capacity of up to 165,000dwt, with the loading/unloading operations being made through a floating docking system that connects to the petroleum tank park of the refinery through an underwater and land pipeline.
The construction works at the marine terminal have been completed at the end of 2008, with the total value of the investment being over $100m.
Tudorel Dumitrascu, general manager of the project developed by Midia Marine Terminal, said: "It is the first step that confirms both the functioning of the new investment in optimal parameters, as well as the group's intention to become a key player in providing petroleum to the Central and Western Europe refineries. The transfer of the petroleum to the refinery's tank park has been done with no problems and has also benefited from excellent weather conditions."
Capture and storage of carbon dioxide from power stations has moved a step closer to reality with plans to use gas pipelines in Scotland to transport it into the North Sea.
Under the proposals, a 300km network of existing pipeline from the St Fergus gas terminal in Aberdeenshire would be used from 2013 to transport carbon dioxide to be stored in depleted oilfields and gasfields.
So called "carbon capture and storage" (CCS) technology would allow power stations to produce up to 90 percent fewer emissions, helping to meet greenhouse gas targets.
However, the technology has not yet been used on a commercial scale. Scotland is thought to have some of the best opportunities in Europe for CCS, because of the wide availability of depleted oil and gasfields in the North Sea.
The proposals, by National Grid, are out for consultation.
Subsea 7's newbuild pipelay and construction vessel, Seven Pacific, is on schedule for delivery in the fourth quarter of 2010. The vessel, to be fitted with a 260-ton vertical lay system (VLS) tower, will further enhance Subsea 7's pipelay capabilities, particularly in deep water.
First steel for the Seven Pacific was cut on March 16, and the first units are currently being fabricated at IHC Krimpen Shipyard, near Rotterdam.
The VLS, to be built by Schiedam-based Huisman, will be complete with a 260-ton abandonment and recovery winch with 3,000 meters (9,843 ft) of A&R wire. The vessel will have an overall length of 133 meters (436 ft) and a beam of 24 meters (79 ft). In addition to the new VLS, Seven Pacific will be equipped with a pipelay suite for installing flexible flowlines and umbilicals, two 1,2500 ton underdeck carousels and twin deepwater-rated ROVs.
The investment in the vessel is part of an ongoing capital investment program of over US$1 billion dollars in new assets and equipment which will see eight new vessels joining the existing Subsea 7 fleet between 2007 and 2010.
Subsea 7 CEO Mel Fitzgerald said, "We are investing in excess of $1 billion in a number of new vessels and equipment that will enable Subsea 7 to offer its clients the capability they need to deliver on their investments, more efficiently and cost effectively. Our new vessels have enhanced Subsea 7's overall capacity, but are also equipped with new technology and the operational capability to service deepwater and ultra-deepwater markets globally. This investment demonstrates our long term commitment to building for the future and becoming the Subsea Partner of Choice in our sector."
In the first quarter, Subsea 7 was awarded new contracts, including commitments under frame agreements, of an aggregate amount of US$300 million. The company's worldwide order book as of March 31 was approximately US$2.9 billion, comprised of approximately US$1.9 billion of day-rate contracts and US$1 billion of lump-sum contracts.
In March, Subsea 7 reported that it had been awarded a contract by Petrobras for the Tambau Urugua and P-56 developments in the Santos and Campos basins, offshore Brazil. The contract is valued at approximately US$200 million, with the offshore pipeline installation campaign scheduled to take place during 2010.
A consortium made up of oil and gas major Eni and Turkish Çalık Energy expects to start building a pipeline that will carry Caspian oil to the Mediterranean by 2010. Eni is expected to finance 100% of the pipeline, which is expected to cost US$4 billion. The company will use its oil in its Kazakh Kashagan and Karachaganak fields to start the pipeline throughput.
The line will run from the Black Sea port of Samsun to the Mediterranean energy hub of Ceyhan, bypassing Turkey's increasingly congested İstanbul and Çanakkale Straits. The pipeline is expected to have a capacity of 1 million barrels per day.
The consortium is in talks with stakeholders of the Caspian Pipeline Consortium, which includes US Chevron, Russia's Transneft, ExxonMobil, Royal Dutch Shell, BP and Lukoil.
Following the submission of its planning application, Centrica, the parent company of British Gas, will lay out to interested parties and members of the public its plans to convert the Bains gas field in the East Irish Sea, into a dedicated seasonal storage facility nearly one-fifth the size of Rough, UK's largest gas storage site.
If the proposed development progresses, the facility could be available to come online for gas production and injection in the winter of 2012, with a storage capacity of up to 20 billion cubic feet, said Centrica.
The Bains project proposes to convert the existing partly depleted Bains field, five miles north east of Centrica's South Morecambe field, to a storage facility with a 20-mile pipeline to the Barrow onshore terminal.
According to the company, a new unmanned platform and additional gas processing facilities within the existing South Morecambe Terminal would be required. Reservoir characteristics of the existing Bains field indicate a storage facility could offer flexibility to inject and produce gas at short notice.
John Woodings, Bains's onshore project manager for Centrica, said: "We believe Bains has potential as a gas storage facility, being close to existing gas production infrastructure and having the right reservoir characteristics.
"As the UK becomes reliant on imported gas and flexibility from North Sea fields declines in the coming years, investing in storage facilities, which will boost this country's security of supply, forms part of Centrica's long term program of investing in a range of gas, power and renewable projects to supply our British Gas customers."
Repsol has made a new gas find in Algeria, adding to those announced in January in an area considered of strategic importance for the company. The find in the Ahnet basin, to the east of the prolific Reggane basin, confirms the potential of the area and offers new development possibilities.
Repsol operates the consortium with a 33.75% stake. Algeria’s state-owned Sonatrach controls 25%; Germany’s RWE Dea owns 22.5% and Italy’s Edison has 18.75%. Repsol and its partners won exploration licenses for the Reggane and M’Sari Akabli blocks in bidding rounds held in 2002 and 2003 by the Algerian government.
Gas was found in a well drilled to a depth of 2,135 meters in the M’Sari Akabli permit. Initial tests show production at the TGFO-1 well to be 363,000 cubic meters per day in the Emsian Layer with a 32/64” choke and wellhead pressure of 2,114 psi.
The latest discoveries consolidate the importance of Algeria for Repsol. The company has quadrupled its contingent resources of hydrocarbons in the last two years through its significant exploratory success, demonstrated by its participation in three of the world’s ten largest discoveries in 2008 and the start-up of new production in Libya and Gulf of Mexico. During the first quarter of 2009 Repsol found oil and gas in the five key areas identified in its 2008-2012 Strategic Plan.
Repsol plans to drill 35 exploration wells in 2009, keeping up the momentum of 2008, when a record 40 wells were drilled.
Hyperdynamics Corporation announced April 28 that it has teamed with Houston-based Zeus Development Corporation to help secure potential partners that are believed to have a broader range of interest associated with the potential success of discovering Guinea’s hydrocarbon resources.
On September 3, 2008, Hyperdynamics’ Chief Executive, Kent Watts, was a speaker at Zeus Developments’ Sub-Saharan Africa’s Natural Gas Monetization Symposium. At this event Mr. Watts gave a presentation entitled Guinea: Will Guinea Become the Dubai of West Africa? In the presentation it was emphasized that the development of Guinea’s petroleum reserves had the potential to change Guinea from one of the poorest West African nations to a strong and rapidly growing industrial powerhouse. Mr. Watts discussed the vibrant Guinea culture and their immense resources including the fact that Guinea is believed to hold as much as a third to one-half the world’s bauxite reserves, the raw material needed to manufacture aluminum. It was noted that in addition to an oil discovery, a significant natural gas discovery could provide the catalyst for Guinea’s economy to boom.
Earlier this month, Zeus’ executives, Mr. Robert Nimocks, CEO, and Mr. Patrick LaStrapes, President, contacted Mr. Watts with the idea of presenting Hyperdynamics Joint Venture opportunities to their clients. Mr. Nimocks and Mr. LaStrapes explained that because the concession had multiple plays, including the potential for significant natural gas reserves, in addition to oil, that many of their clients may be interested in the opportunity, not only for the investment to discover and produce Guinea’s petroleum resources, but also for the opportunity to invest in building up Guinea’s infrastructure including such things as power plants, mining operations, and building factories. The two companies reached agreement April 24 on their mutually beneficial relationship.
When asked to comment, Zeus’s President, Mr. Patrick LaStrapes, stated, “The Republic of Guinea offers an exciting opportunity for diversified investors interested not only in extraction and export of oil but also in (1) monetizing natural gas locally, (2) developing an industrial corridor around bauxite/alumina and iron ore, and (3) electrifying first through self generation and subsequently through grid development.”
Repsol has reported an oil discovery in Libya. The company has drilled A1-NC202 New Field Wildcat well in Offshore Sirte Basin, approximately 15 km west from the shore and 40 Km southwest of Benghazi City. The well drilled to a total depth of about 15,815 feet in water depth of about 50 meters
The initial production testing established a flow of 1,264 b/d of 26-degree API oil and 580,000 cf/d of natural gas through a half-inch choke. The Dernah formation was tested at an interval between 4,484 feet (1,367 m) and 4,442 feet.
This well represents the first discovery in block NC202, which was awarded by NOC in November 2003.
Repsol Exploration Murzuq drilled the well as an operator under an EPSA agreement with NOC of the Great Socialist Libyan Arab Jamahiriya with interests distributed as follows:
First Party Interest (NOC Libya), 65%
Second Party Members share Interests as follows:
Repsol Exploration Murzuq S.A., 21% (Operator)
OMV Oil and Gas Exploration GmbH, 14%
Libya's top oil official said April 29 his country is keen to invest in oil-and-gas exploration off Cyprus' southern coast.
Shukri Ghanem said Libya is "very much interested in looking at different possibilities of investment" in a search for oil and gas deposits inside the island's exclusive economic zone.
Ghanem, who is the chairman of Libya's National Oil Corporation, did not elaborate.
Cyprus launched an initial licensing round in 2007 for 11 blocks covering 51,000 square kilometers (17,000 sq. miles) of seabed. Officials said a second licensing round will be launched, but have not said exactly when.
Ghanem said Libya is also looking into supplying the crude-reliant island with natural gas and investing in its energy sector.
The Libyan official made the remarks after talks with Cypriot Commerce Minister Antonis Paschalides.
Transnet Limited of Johannesburg, the owner and operator of South Africa's strategic petroleum and gas pipeline infrastructure, has selected GE Oil & Gas to supply electric motor-driven pump packages for a new, multi-product pipeline that will play a key role in supporting the country's economic growth.
The new pipeline will stretch from Durban Harbor to Johannesburg and will supply diesel, petrol and jet fuel for inland markets that currently have limited refining capacity. To meet the country's immediate and future demands, this will be a fast-track project; commissioning of the first sections of the pipeline is scheduled to begin in mid 2010.
“The new multi-product pipeline project will increase both the capacity and flexibility of Transnet's existing pipeline network to the Gauteng Province. By investing in this asset, Transnet will fulfill its strategic role of ensuring the security of critical energy supplies (in the form of refined petroleum products) to the Gauteng Province,” said Carlos Galego, NMPP project director of Transnet.
Marking its largest project in South Africa to date, GE Oil & Gas will supply 19 pumps with variable frequency drives, chillers and lube oil systems to be installed at five stations along the route of the pipeline. GE will utilize a consolidated high efficiency pump design to maximize reliability. In addition, only two types of hydraulic systems will be used for the 19 pumps, for greater interchangeability of spare parts.
“This is a significant project for both Transnet and the government of South Africa, supporting Transnet's strategy to revitalize and extend the country's infrastructure,” said Joe Mastrangelo, vice president -- turbomachinery for GE Oil & Gas."GE's experience with pipeline projects around the world and strong synergies with key sub-vendors has enabled us to build a proven track record when it comes to supplying complete pump package solutions for some of the world's largest pipelines."
“We were able to secure this contract by committing to meet the project's key challenges: tight delivery deadlines, energy efficiency and cost constraints,” said Daniele Scenarelli, GE Oil & Gas region sales executive for Sub Saharan Africa, based in Cape Town.
The pumps for the Transnet project will be centrifugal pumps designed for high efficiency and a high degree of fluid dynamic optimization. They will be capable of meeting a broad range of operating requirements for the pipeline over the estimated next 20- to 30-year operating life of the pipeline.
More than 17,000 GE centrifugal pumps are installed around the world for process, refinery, water injection, oil pipeline, boiler feed and water cooling applications. These pumps are fully compliant with API 610-ISO 13709 industry standards and meet the most severe service requirements, including continuous service with high mean time before failure (MTBF).
GE Oil & Gas high efficiency pumps are produced in Bari, Italy, using advanced design criteria and manufacturing technologies. They have been installed with virtually every type of industrial driver including electric motors, gas and steam turbines and diesel and gas engines; and have reached significant performance milestones such as 14,500 KW/stage and 7,500 rpm.
Transnet Pipelines, the pipeline operating division of Transnet Limited, owns and operates 3,000 kilometers of strategic petroleum and gas pipelines in South Africa, traversing five provinces. Pipelines play an important role in ensuring the secure supply of refined petroleum products to the inland industrial hub of South Africa, which has limited refining capacity.
With its acquisition of VetcoGray and Hydril Pressure Control, GE Oil & Gas now offers additional products, systems and services for drilling, completion and production within onshore, offshore and subsea applications.
CNPC, parent of PetroChina, said on its website that the Russian segment of the Sino-Russian crude oil pipeline has entered construction.
The Russian segment, stretching 70 kilometers, will divert oil from the East Siberia Pacific Ocean (ESPO) oil pipeline to China, and will pump 15 million tons every year.
The Sino-Russian oil pipeline is planned to enter full stream in October 2010, which will ensure oil supplies to China for what the two countries signed in their "loan-for-oil" agreement.
The first phase of the ESPO oil pipeline, 2,694 kilometers long and running from Thaishet to Skovorodino, is designed to annually pump 30 million tons of crude oil.
The Ministry of Mines in Afghanistan announced it has taken the necessary steps to prepare for the bidding process to explore northern oil and gas reserves.
The Oil and Gas Journal quotes the ministry saying it "has initiated the process that will lead to the bidding round for the award of exploration and production-sharing contracts for hydrocarbon operations."
The northern Kashkari oil block holds an estimated 64.4 million barrels of crude, while the Juma-Bashikurd and Jangalikalan gas blocks hold 1.8 trillion cubic feet of natural gas collectively.
Most of the oil and gas fields in Afghanistan were discovered in the northern parts of the country in the 1970s prior to the Soviet invasion.
Western markets are looking at the northern parts of the country as a possible host of the Turkmenistan-Afghanistan-Pakistan-India pipeline, which would bring modest revenue to the embattled nation.
The U.S. Energy Information Administration notes the total proven oil reserves in Afghanistan are negligible. Gas reserves are quoted at 1.75 trillion cubic feet, which is 53rd in the world.
Sasol, Uzbekneftegaz (the National Oil and Gas Company of Uzbekistan), with Petronas from Malaysia, has marked a significant milestone with the signing of a Heads of Agreement for the development and implementation of a Gas to Liquids (GTL) project, as well as a Memorandum of Understanding for mutual cooperation in the oil and gas industry, in the Republic of Uzbekistan.
Sasol chief executive, Pat Davies, joined Chairman of the Board of Governors of Uzbekneftegaz, Deputy Prime Minister of the Republic of Uzbekistan, Mr. Ergash Shaismatov, and Petronas President and CEO Tan Sri Mohd Hassan Marican, for the signing ceremony in the country's capital of Tashkent.
The Heads of Agreement follows the positive outcome of the joint pre-feasibility study based on Sasol's proprietary technology. The technology will be deployed to produce high quality transportation fuels from Uzbekistan's abundant domestic gas reserves.
"The wealth of gas resources within Uzbekistan makes this an ideal location for a GTL facility and we are delighted to mark this important milestone with our valued partners," said Sasol group general manager, Lean Strauss.
The GTL project will enhance Uzbekistan's fuel production and will also make a significant contribution to the economy of the country through foreign direct investment and job creation.
The partners are currently in negotiations with the Uzbekistan government regarding the required project enablers and plan to proceed to the next phase of project implementation which involves the establishment of a joint venture company. Petronas and Sasol are also exploring other areas of cooperation in the Uzbekistan oil and gas industry.
Several foreign companies have voiced their willingness to participate in the development of Iranian oilfields.
National Iranian Central Oil Company's (NICOC) managing director, Alireza Zeighami, made the remark while visiting the 14th International Oil, Gas and Petrochemical Exhibition in Tehran on April 26.
Zeighami told IRNA that 10 out of 35 foreign companies, which applied for permits, have been selected to cooperate with Iran in this respect. He said these oilfields are located in Lorestan, Qom and Bushehr provinces.
"Once the oilfields are developed, 50,000 barrels of oil will be added to the NICOC's production capacity," he said.
In this respect, Tehran and Baghdad have agreed to build an oil pipeline connecting the main Iraqi oil hub of Basra to the oil-rich Iranian city of Abadan.
"The agreement was reached last week between visiting Iraqi Oil Minister Hussein Al-Shahristani and his Iranian counterpart Gholamhossein Nozari in Tehran," said Deputy Oil Minister Noureddin Shahnazizadeh.
Shahnazizadeh said Iran plans to import up to 200,000 barrels of oil per day from Iraq to feed Abadan Refinery in the southwestern province of Khuzestan.
The official added that the two countries have also signed an agreement that would allow Iranian companies to build five refineries in Iraqi cities.
IRNA quoted Shahristani on as saying that the two sides have agreed to jointly develop their oil and gas fields. Iran had earlier agreed to supply Iraq with 1.5 million tons of fuel oil and 1.5 million tons of diesel daily.
While Iran is the second-biggest oil producer in the Organization of Petroleum Exporting Countries, it spends billions of dollars on gasoline imports.
Iraq is the holder of the world's third-largest oil reserves. However, six years of conflict following the US invasion has battered the country's oil industry, negatively affecting its production ability.
Iraq has qualified nine international oil companies to take part in its second bidding round to develop 11 oil and gas fields, a statement said on April 1.
Last December, Iraq kicked off its second postwar bidding round for 11 discovered but undeveloped oil and gas fields. This followed its first postwar round to develop eight oil and gas fields.
The statement, which was issued by the Oil Ministry, said that the nine companies were selected from 38 that submitted their qualification documents early this year.
It added that the Ministry's Petroleum Contracts and Licensing Directorate will send letters soon to those that qualified to inform them of the next steps.
The companies chosen include Russia's two state-owned companies OJSC Rosneft and OAO Tatneft; UK's Cairn Energy PLC; Japan Oil, Gas and Metals National Corp.; and India's state-owned Oil India Ltd.
Others are Kazakhstan's state-owned JSC Kaz Munai Gas Exploration and Production; Vietnam's state-run Petrovietnam Exploration and Production Corp.; Angola's national oil company Sonangol, and Pakistan Petroleum Ltd.
In addition to those nine companies, the 40 oil companies qualified for the first bidding round will also have the right to take part.
The ministry plans to sign the contracts of the first round in mid-2009 and the second round by the end of the year.
Alarmed by plummeting oil prices, Iraq is struggling with poor oil infrastructure and shortage in funds to increase the daily production of about 2.4 million barrels a day to boost its budget.
Iraq, which holds the world's third-largest known oil reserves of at least 115 billion barrels, is suffering a financial squeeze as prices plummeted to more than 60 percent from a summertime peak of about $150. Oil accounts for more than 90 percent of state revenues.
Iraq's parliament passed a $58.6 billion budget earlier this month - a sharp reduction from the original $79 billion spending plan.
To increase production, the Oil Ministry has recently issued tenders to drill nearly 100 new wells and install production surface plants in a number of oil fields in the south as part of an accelerated plan to add 300,000 to 500,000 barrels per day by the end of 2010.
Iraq's target over the next four to six years is to reach a production level of 4 million to 4.5 million barrels a day.
When the U.S. invaded Iraq, many assumed a large part of the reason was for the oiI. It’s many years later, the country is still in shambles and the oil industry is as bad as ever. And, it doesn’t look like we are any closer to getting the oil program in decent shape.
An oil exec who was dealing with Iraq's state run oil company called the situation "a crisis in the making" according to the publication MEED. Nawar Alsaadi who lived in Iraq until 1990, laid out a thorough explanation of why it's a crisis in the making. Here it is broken down into a truncated explanation:
1. Endemic Corruption: As of last year and according to the corruption ranking of Transparency International, Iraq ranked 2nd worst in the world, slightly higher than Somalia and in line with Myanmar.
2. Oil Reserves: While the nation is reported to have 112.5 billion barrels of oil reserves, the actual number is closer to 60 billion barrels.
3. Bad Managment: The lack of oil industry experience by appointed council members, combined with the surging levels of corruption has conspired to limit the growth in the Iraqi oil production since 2003. This failure is amplified by the ministry’s failure to bring production back to 2002 levels six years after the regime change. Oil production could slip below 2 million barrels a day, which is less than pre-war levels.
4. Political Rivalry and Foreign Oil Company Stalemates: The greed and the competition for power has lead to a multi-year stalemate in the passage of the key hydrocarbon law introduced in 2006 and revised four times so far. And it does not seem that a passage is near.
...The Iraq oil ministry led by Mr. Hussain al-Shahristani was determined to sign deals with foreign oil companies. It went ahead and signed a gas deal in September 2008 with Shell Petroleum to exploit Iraqi gas, which is estimated to be burned at a rate of $7 billion per year for lack of gas processing facilities. However the $4 billion deal has faced opposition almost from the start, and as of April 17th 2009, Mr. Jabir Khalifa Jabir, secretary of the Iraqi parliament's oil and gas committee announced the following:
"We are going to do everything we can to revoke this deal and to push Shell out," Jabir told Reuters. "Both these deals are illegal because they didn't go through parliament”.
“The companies and their lawyers knew the old Iraqi oil law very well," he added, saying that any new deals Baghdad signs in bidding rounds under way with BP and others would also be subject to revocation.”
5. Political Instability: 2008 was a good year for Iraq, but 2009 is shaping up to be much worse. Part of the reason is that the government funded its actions and fostered a welfare state on the back of $150 barrels of oil. Now that it's gone, the government can no longer fund these projects, which means the short lived tranquility could be out the window.
Expectations that foreign companies will cash in on Iraqi oil riches were called into question April 17 after a key parliamentary body in Baghdad pledged to "push Shell out" and halt a forthcoming licensing round.
The warning from Jabir Khalifa Jabir, secretary of the Iraqi parliament's oil and gas committee, was seen by financial analysts as a serious threat to western investment opportunities in a country that holds the second-largest oil reserves in the world.
Shell has been considered a frontrunner in the race to seize control of the Iraqi energy sector after signing a $4bn deal to process and market gas from the south of the country and ship it, possibly to Britain as liquefied natural gas.
But the preliminary agreement and a subsequent one with China National Petroleum Corporation were unconstitutional and detrimental to Iraq's economic interests, said Jabir, who worked for more than 15 years at Iraq's state-run Southern Gas Company.
"We are going to do everything we can to revoke this deal and to push Shell out," Jabir told Reuters. "Both these deals are illegal because they didn't go through parliament. The companies and their lawyers knew the old Iraqi oil law very well," he added, saying that any new deals Baghdad signs in bidding rounds under way with BP and others would also be subject to revocation.
The oil ministry has said it does not need parliament's approval to sign new deals, but Jabir argues Iraqi law 97 clearly states all arrangements of this nature must be passed by parliament. The committee had studied the preliminary Shell deal for the past six months and all members have concluded that it is illegal, he said.
The arrangement with Shell and the wider oil licensing round have been highly controversial already because many critics believed they were unduly influenced by the US and British, who occupied the country after toppling Saddam Hussein in 2003. Critics saw the invasion as a "war for oil" and believed it would open the way for US and UK oil companies to regain assets seized from them decades earlier through nationalisation.
Analysts at IHS Global Insight, the economic forecasting group, said the latest developments were alarming, especially given Shell was expected to formalize its southern gas deal within the next few weeks. "The Shell deal looks increasingly like a litmus test for progress on all Iraq's oil and gas projects, with any potential failure likely to remove most of the political legitimacy from the oil ministry's interpretation of Iraq's constitution and oil law," they argued.
Shell declined to comment on Jabir's remarks with a spokesman at head office in the Hague saying they were a "matter for the ministry of oil" in Baghdad. But he added: "We believe our experience in large-scale integrated gas projects and knowledge of Iraq has contributed to the decision to work with Shell."
Chevron Corp. and BP Plc are withdrawing top executives from Kuwait after more than a decade of negotiations failed to open up access to the world’s fourth- largest crude oil reserves.
Hani Iskander, Chevron’s Kuwait president, may leave next month after failing to reach an accord to boost output, according to two Kuwait-based officials who declined to be identified because the decision isn’t final. BP’s vice president for Middle East exploration and production, Tim Marchant, is also departing as talks to invest in the country slow.
Kuwait risks missing its target of almost doubling oil production by 2020 from 2.1 million barrels a day now as parliamentary opposition blocks the country’s biggest expansion efforts. The delay hobbles international oil companies that already face restrictions tapping reserves in Saudi Arabia, Iran and Iraq, the three largest OPEC producers.
“Kuwait won’t reach its 4 million-barrel-a-day target without the help of established oil companies, who deal with challenging oil fields and can impose an efficient investment program,” said Raja Kiwan, a Dubai-based analyst at consultants PFC Energy. “The bulk of its production comes from fairly mature fields, so incremental output will come from difficult reserves in the northern fields and heavy oil.”
BP engineers moved out of Kuwait in 2008 after a contract to help the state oil company with management strategies ended.
“The office has downsized but our commitment to Kuwait is still there,” according to Nouf al-Abdulrazzaq, BP’s new general manager in the country. The Kuwait Investment Authority, with a 1.8 percent stake in BP, is the third-largest shareholder in the London-based company, according to data compiled by Bloomberg.
Chevron, the second-biggest U.S. oil producer, is “going through a normal demobilization of staff” after a technical agreement with Kuwait Oil Co. expired in August, Margaret Cooper, a company spokeswoman, said by e-mail. San Ramon, California- based Chevron continues to pump oil in the so-called Neutral Zone between Kuwait and Saudi Arabia.
Kuwait may revise its oil strategy at the end of the year to focus on “aggressively” exploring for natural gas, Sami al- Rushaid, chairman of Kuwait Oil, the production arm of state-run Kuwait Petroleum Corp., said in a March 31 interview.
“Our new strategic direction has shifted, so now we’re talking 2030, we’re looking beyond 2020,” he said.
Mahmoud al-Rahman, a former chairman of KPC’s international exploration unit, Kuwait Foreign Petroleum Exploration Co., said the nation should develop its fields without foreign help.
“We’ve been producing our own oil for 60 years, and we’ve been able to develop oil abroad in difficult areas, so it leads us to think there must be some financial reward involved for oil officials to insist on giving contracts to foreign companies,” he said.
Opposition to foreign participation in oil projects comes from a minority of politicians rather than government policy, said Abd al-Wahab al-Harun, a former leader of the Kuwaiti parliament’s finance and economy committee.
Kuwait nationalized its oil industry in 1975, restricting international companies to offering advice to KPC. Project Kuwait, a plan to develop northern fields with foreign companies, has been on hold for a decade because of political opposition.
The country began new negotiations about three years ago with Chevron, BP, Exxon Mobil Corp. and Royal Dutch Shell Plc to obtain foreign technology while keeping control over its oil and gas reserves. Kuwait-based officials at the companies have said they don’t expect an agreement on these so-called enhanced technical service accords this year.
The slowdown in the world economy has reduced oil demand and prompted energy companies to scrap or postpone investment plans. The industry is reviewing staffing and budgets after crude tumbled to about $50 a barrel from a record $147.27 in July. Oil traded at $48.85 a barrel at 2:05 p.m. April 28 in London.
Spending cuts may cause a “supply crunch” when the economy recovers, according to the Paris-based International Energy Agency, which has forecast a 1 percent annual increase in oil consumption over the next four years.
Exxon has been negotiating a heavy-oil project in Kuwait since 2007. The scale of the venture was reduced to a potential 450,000 barrels a day by 2020, from 750,000 barrels, Kuwait Oil said last month.
“We’re still talking, we’re still interested,” Richard Vierbuchen, Exxon’s vice president for the Caspian and Middle East, said in an interview in Kuwait on March 31.
International companies have also been discouraged by Kuwait’s cancellation of two multibillion-dollar contracts, overturned after lawmakers said they were overpriced.
Kuwait scrapped a deal to buy 50 percent of Dow Chemical Co.’s plastics unit in December and terminated agreements last month to build a $15 billion refinery.
“After the Dow deal falling apart and the stalled refinery project, people will think twice before wanting to invest,” said Alex Munton, an analyst at Edinburgh-based Wood Mackenzie Consultants Ltd. “These mega-projects are the symptom of underlying political issues between the royal family and local opposition groups about how the country is governed.”
Kuwait’s emir dissolved parliament on March 18, the second time in a year and the sixth time since the country introduced parliamentary democracy in 1962. The nation’s fifth permanent oil minister in three years, Sheikh Ahmed al-Abdullah al-Sabah, was appointed Feb. 9.
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