If oil is $90 per barrel by 2040
Oil production by EOR could be 740,000 barrels per day
10 percent of U.S. oil production
If oil falls to $73 per barrel by 2040:
Oil production by EOR would drop to 480,000 barrels per day
8 percent of U.S. oil production
Denbury did not immediately respond to calls for comment. The company has 468.3 million barrels of oil equivalent per day in proven reserves, according to its website. Of that, 83 percent is oil.
Denbury operates in Texas, Louisiana, Mississippi, Alabama, Wyoming, Montana and North Dakota. Denbury will release its second quarter earnings on Aug. 6.
Under pressure: How will oil prices affect companies like Denbury Resources?
by Nicholas Sakelaris - Staff Writer - Dallas Business Journal
Injecting carbon dioxide to bring older oil fields back to life is Denbury Resources’ bread and butter.
Pressure goes down in an oil field after decades of drilling, making it harder to produce oil out of the reservoir by traditional means. Plano-based Denbury (DNR) pipes in carbon dioxide from manmade and natural sources that it shoots into the oilfield to restore the pressure and produce the oil again.
The same carbon dioxide causes a can of pop to shoot like a geyser after shaking.
But this so-called enhanced oil recovery is also more costly than traditional drilling, adding potentially $20 to $30 to the cost of every barrel produced for the carbon dioxide alone, according to the a new report by the Energy Information Administration.
Special equipment is needed to separate the crude oil from the carbon dioxide. Pressurizing the oilfield also takes time, which also increases the cost, according to the EIA.
“Oil prices thus play an important role in determining whether the additional production resulting from applying CO2 EOR to old oil fields is sufficient to make this process commercially viable and economically feasible,” the EIA wrote in its report.
The EIA uses three different projections for the future price of oil by 2040.
If oil reaches $202 a barrel by 2040:
Oil production by EOR could be 960,000 barrels per day
12 percent of U.S. oil production
WEC deal not expected to close until mid 2015. you have regulatory risk in seeking approval.... if deal falls TEG price will go down.
long TEG here, had WEC years ago but bailed since at time was not a good investment.... my feeling is I'd rather own TEG then WEC so will let deal play out......if get WEC shares from the buyout it will be okay, also will receive cash to reinvest .....the TEG is in IRA account so don't have to deal with gain/loss issue...
the sale of the coal mines has me wondering what is up....makes a merger with another utility a bit easier (will be simpler to merge a typical gas/electric utility to gain efficiencies from scale)...
the coal business made money for VVC until Obama came in and decided to take the entire industry out.....
for VVC stock price, the downside risk is interest rate risk to utils if Fed starts raising rates.....
not sure if VVC's territory will draw a lot of interest for potential buyers, and VVC might not have the size to go after another util somewhat close.... while I don't own or follow it all that close NiSource has a bunch of debt and appears to be trying to build-out a pipeline network.....
i like VVC as a nice long-term hold
Expanding the capacity of existing pipeline is the most logical way to go, Spectra argues, because — among other things — it would minimize the environmental impact.
The other major pipeline company into the region, Kinder Morgan, has proposed a 250-mile expansion of its Tennessee Gas Pipeline from New York toward Dracut and Pepperell, Mass., with lateral lines stretching into Nashua and Hollis and the main line stretching into Merrimack.
Kinder Morgan’s Northeast Expansion Project, however, has already run into tough local opposition in the Massachusetts and New Hampshire communities where new rights of way for the pipeline would have to be acquired.
Spectra is proposing expanding its Algonquin system in five regional zones that connect to 40 percent of the region’s power plants, while increasing capacity on the Maritimes line to support another 20 percent.
The company already has an expansion project underway along the Algonquin line that is being funded by long-term commitments from local gas distribution companies like Liberty Utilities, called the Algonquin Incremental Market expansion (AIM).
“The AIM project will begin to de-bottleneck the pipeline system by the winter of 2016, helping to enhance reliability and soften prices in New England,” according to Yardley. “Forward price estimates support this. Current market indications for the winter of 2016-17 reflect a 28-percent decrease in price as compared to this coming winter.”
While utility-funded projects like AIM will increase capacity, they will not solve the electric reliability issue, according to Yardley, who called for a more ambitious pipeline expansion to meet the governors’ objective. The proposed in-service date for that larger expansion would be November of 2018.
NH gas pipeline expansion pushed
By DAVE SOLOMON
New Hampshire Union Leader
One of the largest operators of natural gas pipelines from western Pennsylvania into New England says expansion of its existing routes is the best way to meet the objectives of the six governors in the region, who’ve launched an initiative to open the pipeline bottleneck and lower electricity prices.
In a June 27 letter to the New England States Committee on Electricity, William T. Yardley, president of U.S. Transmission and Storage for Spectra Energy, points out that Spectra’s two pipelines into New England, the Algonquin and Maritimes Northeast, are already servicing 60 percent of the region’s natural gas-fired power plants.
“Any pipeline infrastructure solution that meets (the governors’) objectives will ultimately require the expansion of Algonquin and Maritimes,” he wrote. “Spectra Energy is eager to submit its regional solution and strategic investment recommendations.”
Much of the investment Yardley alludes to would come from a tariff on New England ratepayers, based on the notion that a small increase in electric bills to pay for pipeline will yield huge savings in electric prices down the road.
Spectra’s letter gives some insight into the behind-the-scenes jockeying by stakeholders in the wholesale energy market as the governors dangle the proposition of a “socialized” expansion of energy infrastructure in the six-state region.
Yardley suggests that Spectra should help NESCOE craft the request for proposals that will be issued on behalf of the governors’ initiative, writing, “We now seek to help define the RFP scope to ensure recognition of the importance of direct interconnects with power generators.”
connects to more than half the natural gas power plants in the region.
Any Request for Proposals that favors existing interconnections would clearly tilt toward Spectra, which connects to more than half the natural gas power plants in the region.
This is a new article on inversions and companies fleeing U.S. corporate tax rate.....
If interested in reading I have listed publication, title and author to Google search
From NY Times DealBook & Business section
At Walgreen, Renouncing Corporate Citizenship by Andrew Ross Sorkin
Q: Why has the build out of natural gas capturing infrastructure lagged oil production?
Gov. Dalrymple: "We have been madly building processing plants and pipelines. One incredible statistic is that we have already invested $6 billion in infrastructure over the last six years. We've got almost another $2 billion over the next two years…The investment is happening. The incentive is very strong to capture this gas. It's full of very valuable liquids [such as propane and butane] and they are going [as] fast [as possible]. The only problem is the rate of [oil] production is growing faster. Some of these wells are just out of position for the plants that are in place at the moment."
Q: What is different now in terms of regulatory requirements for oil producers in North Dakota?
Gov. Dalrymple: "The basic change from the state's standpoint is that we are going to require any new well [applicant] provide us with a gas-gathering plan and they are going to have to show us a specific plan to gather the gas from a new well within one year, or the company will not receive a permit to drill."
Q: Will the state enforce those gas-capture plan commitments from industry?
Gov. Dalrymple: "That's part of the assumption—we expect the gas-gathering plan to be feasible and we will make that judgment [accordingly]. We do expect [the gas gathering infrastructure] to be there one year after they drill the wells. So this is not some kind of a target, we expect that it will be carried out."
Q: Why has North Dakota been slow to grapple with the issue of flaring when it's not a problem in other oil-producing states?
Gov. Dalrymple: "You have to take into account a couple of things. One is that the Bakken formation is essentially an oil play. Companies that are out here are drilling for oil, not gas. Even though that's the case, they are finding a lot of gas as well…Even though [prices for natural] gas went down in value substantially in the last couple of years that has not done anything to slow down the drilling because it's basically the great oil production that they're after. You also have to understand that…the trick is to have the [natural gas] processing capacity in the right location…The four counties [in North Dakota] that have most of the production have had no prior infrastructure to speak of from the days of vertical [oil well] drilling. So this is essentially a build out from scratch, which is much different from what you find in Texas or Oklahoma where they have a lot of existing infrastructure, much of which was actually underutilized."
Q&A: Inside North Dakota's Effort to Cool Its Flaring Problems
Gov. Dalrymple on Regulatory Push to Reduce Burn-Off by Bakken Oil Producers
By Chester Dawson
North Dakota is at the epicenter of the Bakken Shale oil-production boom that has lifted U.S. crude production to multiyear highs. While that development has brought investment and jobs to the once hard-pressed state, the pace of growth has posed a challenge in terms of infrastructure capacity and regulatory oversight. One of the most obvious issues is the widespread burning off, or flaring, of surplus natural gas at oil wells at levels much higher than in other oil-producing states such as Oklahoma and Texas. North Dakota's Republican Gov. Jack Dalrymple, a member of the state's powerful industrial commission, spoke to The Wall Street Journal's Chester Dawson recently about new regulatory initiatives designed to reduce flaring by Bakken oil producers.
Q: Will new regulations result in meaningful cuts in the amount of natural gas flared in North Dakota?
Gov. Dalrymple: "I am confident it's going to have a real impact. We—and when I say that I mean our oil-and-gas division of the North Dakota Industrial Commission—worked directly with the industry people developing [natural gas] gathering plans as part of an overall strategy to reduce flaring. I think the fact that industry has participated in this and that they are buying into this plan is critical. They have actually come up with something better than what I was hoping for. They are not backing down from our stated goals, which is to capture 85% within two years and capture 90% of the gas within six years—by 2020."
"It's assumed they will sell the gas if it's connected," said Alison Ritter, a spokeswoman for the state Department of Mineral Resources, "but sometimes there's insufficient infrastructure to do that."
Flared gas is still subject to royalty. But XTO and Continental haven't paid either for gas flared at the Wolff or Palmer wells, according to Mr. Kelly, the landowners' lawyer.
XTO said it doesn't comment on specific contracts but is working to reduce flaring. Continental declined to comment.
Rancher Ms. Best said the community appreciates the economic boost from drilling. "It's not all bad, it's just poorly managed," she said. "It's the drilling that's to come in the future that weighs heaviest on our minds."
Oil producer Hess Corp in May opened an expanded gas facility in Tioga, N.D., that nearly triples the plant's gas-processing capacity to keep up with Bakken production.
"There was no alternative gas processing available within the state," said Gerbert Schoonman, Hess's vice president for the Bakken. "We're a big international company operating in many countries and we know that it's not sustainable to have a lot of flaring with your operations."
Twelve-story-tall drilling rigs, powder-blue fracking water hoses and well pads ringed by barbed wire dominate the land where Ms. Best's cattle used to roam freely. Like many homeowners in rural Western North Dakota, the fifth-generation resident of McKenzie County doesn't own subsurface mineral rights and as a result can't prevent drilling on her land.
She fought plans for a well to be drilled closer than where it is now, at the end of her half-mile long driveway. "At first, they wanted to build one 200 feet from our back deck," Ms. Best said. Two other wells, also with persistent flares, also are visible from the edge of her property.
Those older wells were drilled three years ago, one by Exxon Mobil Corp unit XTO Energy Inc. and the other by Continental Resources Ltd according to public filings. XTO flared its Wolff well as recently as April and in all but four months since August of 2011, according to state production records. Continental has flared its Palmer well for as many months as not since September of 2011, including as recently as April.
The state bars operators from flaring after the first year a well is drilled, unless companies get extensions on the grounds that the restrictions are economically unfeasible or the well is connected to a gas line.
Yet two-thirds of the wells that flared gas in April were connected to a system with more gas than it could ship or process.
The rules require producers to identify gas-processing plants and proposed connection points for gas lines but don't affect permits that already had been issued.
The commission, which promotes as well as regulates the drilling industry, on Tuesday is expected to announce measures to limit flaring of existing wells. The federal government also is considering new limits on flaring.
In the past five years, North Dakota has climbed from the country's sixth-largest oil producer to the only state after Texas to produce more than a million barrels of oil a day. That has brought investment and job growth to a state economy once largely dependent on agriculture.
But while Texas captures all but 1% of the natural gas produced, North Dakota burns 30% of its output. Oil companies can ship crude, which fetches 20 times more than gas per barrel of oil equivalent, in tanker trucks to pipelines or rail terminals. Transporting natural gas requires a pipeline connection at the source, however, and North Dakota has far fewer of such pipes and less processing capacity than other oil-producing states.
Government and industry officials say they have moved as fast as possible to limit gas burn offs.
"The only problem is the rate of [oil] production is growing faster" than companies' ability to capture gas, North Dakota Gov. Jack Dalrymple said in an interview. "We have been madly building processing plants and pipelines," he said.
The industry has said it can cut back flaring to 5% of production volume over the next six years as gas infrastructure is built, responding to public pressure and the prospect of perhaps tougher rules from the state or federal governments.
"It's not that easy to measure yet, but we're truly making progress," said Lynn Helms, the North Dakota Industrial Commission's director of natural resources. "This has been a really huge sea change in the industry in terms of taking flaring seriously," he said.
North Dakota's Latest Fracking Problem
Bakken Shale Oil Drillers Are Forced to Burn Off Excess Gas
By Chester Dawson
WATFORD CITY, N.D.—For cattle rancher Vawnita Best, the struggle by North Dakota regulators to keep up with the oil boom strikes close to home: She can see the natural-gas flares of an oil well from her front porch.
"It's been flaring for nearly a year," she said amid the rolling hills of her Elkhorn Creek Ranch. "It's absolutely ridiculous to be so wasteful," she said. "They're flaring gas and using diesel to fuel the pumps—it's like something Homer Simpson would do."
The well is one of thousands dotting the landscape and producing gas as a byproduct of hydraulic fracturing and horizontal drilling for oil in the Bakken Shale. Because North Dakota lacks adequate infrastructure, drillers are forced to burn off whatever they can't capture and ship to market. In April alone, such wells burned 10.3 billion cubic feet of natural gas, according to the state, valued at nearly $50 million.
As flaring wells spread like a prairie fire, North Dakota's regulations have struggled to keep pace. Beyond being an eyesore, burning off natural gas degrades air quality. Critics also say producers aren't paying all the royalties and taxes owed on the gas that is flared. Energy companies lose out on gas revenue, too, but that is offset by what they generate from Bakken crude oil.
"It's a failure of regulation. There was an opportunity to do this the right way, but you can't unring the bell," said Matt J. Kelly, a lawyer at a Bozeman, Mont., law firm representing Bakken mineral-rights owners claiming unpaid royalties for flared gas.
Stung by criticism that it has allowed oil producers to flare wells indefinitely, the North Dakota Industrial Commission on June 1 adopted rules requiring that gas-capture plans be submitted for companies to get a new drilling permits.
If interested in reading I have listed publication, title and author to Google search
OIL & GAS MONITOR
What’s Next for America’s Biggest Oil & Gas Producing States: Oklahoma
BY Roger Soape | American Association of Professional Landmen
Energy consumption closely tracks economic growth, and electricity use in the European Union has barely budged since 2005, according to data from Eurostat, the bloc’s statistical agency.
‘‘The Western European market is on hold,’’ said François Cavan, G.E’s general managing director in Belfort.
For all the fears of French labor unrest any time mergers and consolidations take place – and the inflammatory rhetoric of the French economy minister in initially opposing the American bid – the deal has generated little opposition among Alstom’s workers. That may be largely because of General Electric’s four-decade history in France. G.E.’s power and grid business employs more people in France than Alstom’s does – about 10,000 versus 9,000.
Mr. Immelt, for his part, said in an interview that G.E. had the expertise to make the merger work.
‘‘I think we’re confident,’’ he said, ‘‘that we can put up the right mechanisms and governance structures to be successful.’’
Gas-fueled turbines are in high demand in the face of the fracking boom in the United States and in Japan, a shift away from nuclear power after the Fukushima disaster. Much of the new demand is for more efficient ‘‘combined cycle’’ power plants, in which exhaust heat generated during the gas combustion phase is recovered to power a steam generator. Through the Alstom deal, G.E. is gaining greater expertise and scale to better meet that demand.
G.E. is also putting its electrical grid assets — including high-voltage transmission equipment and power network management technology — into a 50-50 joint venture with Alstom. In that area, the French company’s business, at $5 billion annually, is more than three times the size of G.E.’s.
G.E. is also taking 50 percent of Alstom’s $2 billion-a-year renewable energy business, which ranks No.1 worldwide in hydroelectric turbines and generators and which has solid offshore wind technology. That business nicely complements G.E.’s expertise in onshore wind.
Finally, it is also taking a half share of Alstom’s $2.2 billion-a-year global nuclear and French steam-turbine business, which may help G.E. win more deals in cooperation with world-class French atomic power companies like EDF and Areva.
Analysts say that besides having complementary businesses, G.E. and Alstom are a good geographical fit. The French company is bigger than its new owner in China and India, but G.E. has a larger presence in the United States, the Middle East and Africa.
G.E.’s power generation equipment and services business last year contributed about $12 billion of the American giant’s total $146 billion in revenue.
As for Alstom, the group reported sales of 20.3 billion euros, or $27.6 billion at current exchange rates, for last year – more than two-thirds of that from energy. But Alstom has been unable to stop the decline in profit in its energy business amid a slump in the market in Western Europe.
General Electric, based in the United States, is already by far the largest player in the industrial gas turbine market, Mr. Solomon said, but will gain additional market share in Europe, as well as the existing gas turbine clients of Alstom.
‘‘They really make their money over the life of the turbines in the service contracts,’’ Mr. Solomon said. ‘‘And if European utilities end up converting to gas, and we think they will, G.E. will be there.’’
Even the name ‘‘Alstom’’ indicates a long connection between the two companies, since it is derived from the combination of the Société Alsacienne de Constructions Mécaniques and the Thomson-Houston Electric Company, a predecessor to General Electric.
‘‘We have G.E. and Alstom teams that have known each other for decades,’’ Jeffrey R. Immelt, chairman and chief executive of the American company, told reporters on a visit to the site on Tuesday. ‘‘And together we’ll build a very strong, growth-oriented, competitive business that can look at the future with great confidence.’’
Mr. Immelt, who led G.E. in a whirlwind two-month public effort to persuade the French government to accept his offer, finally succeeded on June 22.
In April, he had imagined simply separating the energy assets for G.E., leaving Alstom as a stand-alone rail and transportation business. But the French government’s opposition meant the deal went through only after Mr. Immelt agreed that Alstom would retain a 50 percent interest in three energy joint ventures and accept the French state as a 20 percent shareholder in Alstom.
G.E. still came away with the prize that it most wanted. General Electric is buying all of Alstom’s global gas and steam turbine equipment and services business, which has more than $10 billion in annual revenue and a large customer base in Europe.
But in G.E.’s view, this is about much more than consolidating European operations.