I just finished reading a book called “The Frackers” by Gregory Zuckerman about shale oil drilling and fracking in the US. The amount of oil and gas in those rocks is insane and would have to be cheaper than paying a drillship $450,000 a day for drilling operations. Read the book and you will find why they built the LNG export facility in Freeport which was initially built to import gas. They built an offshore facility off Massachusetts to import gas into the Northeast but instead the frackers have found tons of gas in western NY and Ohio and W Virginia and the Northeast gas port is not used now. Thankfully oil prices are still high enough to keep most folks working in the Gulf. Those wildcatters have given the US energy independence by innovation and sheer brass ball land grabs.
Now they just need to allow oil to be exported!
The LNG facility in Freeport has already applied for the permits to export. Meanwhile it sits there mostly idle.
[QUOTE=Too bad steam is gone;130153]I just finished reading a book called “The Frackers” by Gregory Zuckerman about shale oil drilling and fracking in the US. The amount of oil and gas in those rocks is insane and would have to be cheaper than paying a drillship $450,000 a day for drilling operations. Read the book and you will find why they built the LNG export facility in Freeport which was initially built to import gas. They built an offshore facility off Massachusetts to import gas into the Northeast but instead the frackers have found tons of gas in western NY and Ohio and W Virginia and the Northeast gas port is not used now. Thankfully oil prices are still high enough to keep most folks working in the Gulf. Those wildcatters have given the US energy independence by innovation and sheer brass ball land grabs.[/QUOTE]
The US will be the number 1 exporter of natural gas, but it will take 20 years before natural gas can surpass our thirst for oil. It is going to happen.
I don’t care what I’m hauling, keep my boat running though! (and keep a good day rate haha)
[QUOTE=Too bad steam is gone;130153]I just finished reading a book called “The Frackers” by Gregory Zuckerman about shale oil drilling and fracking in the US. The amount of oil and gas in those rocks is insane and would have to be cheaper than paying a drillship $450,000 a day for drilling operations. Read the book and you will find why they built the LNG export facility in Freeport which was initially built to import gas. They built an offshore facility off Massachusetts to import gas into the Northeast but instead the frackers have found tons of gas in western NY and Ohio and W Virginia and the Northeast gas port is not used now. Thankfully oil prices are still high enough to keep most folks working in the Gulf. Those wildcatters have given the US energy independence by innovation and sheer brass ball land grabs.[/QUOTE]
Great book! Just finished reading it, based on your recommendation.
Wow, if they are really pulling that much more oil and gas out of the ground, how will it impact the GOM? Haven’t seem much discussion on that.
[QUOTE=Ea$y Money;130157]Now they just need to allow oil to be exported![/QUOTE]
it makes sense to allow LNG exports because there is so much more of it than the US needs.
However the US is still importing about half the oil it consumes, so it makes no sense to export oil. We need it here.
This is good news for those of us working in the oil patch.
“Despite increasing production and the possible export of oil and gas from shales, interest in the development of the Gulf of Mexico (GOM) remains high.”
Yet we still import LNG and propane. What gives? Lets see jones act gas tonnage first to serve those markets before exporting.
[QUOTE=z-drive;133439]Yet we still import LNG and propane. What gives? Lets see jones act gas tonnage first to serve those markets before exporting.[/QUOTE]
A gas pipeline was built 20 years ago to bring Sable Island gas to Massachusetts. They are building a second pipeline now. This got underway long before the fracking boom in the US. As far as I know, we do not import gas from any place except Canada. We still import it because the pipeline is already there, and there is a shortage of pipeline capacity from elsewhere in the US. The only reason that gas has not replaced oil for heat in the northeast is the lack of gas distribution pipelines.
Something to think about is that as gas via pipeline slowly replaces heating oil, the volume of oil barge shipments in the Northeast will drop off.
[QUOTE=tugsailor;133451]A gas pipeline was built 20 years ago to bring Sable Island gas to Massachusetts. They are building a second pipeline now. This got underway long before the fracking boom in the US. As far as I know, we do not import gas from any place except Canada. We still import it because the pipeline is already there, and there is a shortage of pipeline capacity from elsewhere in the US. The only reason that gas has not replaced oil for heat in the northeast is the lack of gas distribution pipelines.
Something to think about is that as gas via pipeline slowly replaces heating oil, the volume of oil barge shipments in the Northeast will drop off.[/QUOTE]
I’m not totally familiar with the LNG pipeline scheme of the United States but I would think that if there are places that pipelines either do not or cannot reach from major distribution centers then that would be an opportunity for barge traffic, both inland and coastwise. Obviously you still need distribution pipelines, or some sort of distribution service, but at least we still might be involved in moving it from major centers to smaller areas of consumption, not unlike what we do with the home heating oil that we move today.
Gas is still imported from Trinidad and Yemen by ship.
[QUOTE=z-drive;133459]Gas is still imported from Trinidad and Yemen by ship.[/QUOTE]
I was not aware of that. It must be because there are long term contracts in place that predate the US gas fracking bonanza.
Yes long term contract as well as political/regulatory concerns as once shipments stop it could be an uphill battle to get them rolling again: at least how it’s been explained to me. There also is allegedly pipeline bottleneck preventing much volume going east of NY. Also demand for liquid product in New England where a liquefaction plant will unlikely be built.
The maritimes and northeast pipeline runs on the edge of my neighborhood. They have expressed plans to double or but I haven’t heard anything from spectra on the details.
[QUOTE=z-drive;133474]…
The maritimes and northeast pipeline runs on the edge of my neighborhood. They have expressed plans to double or but I haven’t heard anything from spectra on the details.[/QUOTE]
That’s funny, the same pipeline runs a couple miles from my house, I can hike out there via an abandoned road.
They may have dropped the idea of running a second pipe. I understand that the Sable Island gas field have been declining more quickly then expected. Designed for 400 mmcf per day it’s putting out 200.
A friend is tending rigs at Sable Island. His company bought four more 2nd hand boats (from Norway) last fall. They are expecting a big expansion at Sable Island.
I heard, don’t know if its true, that they started running the new pipeline next to the old one through Maine last year.
I hear they are also doing some on shore gas drilling and fracking in Ontario, Quebec, and New Brunswick.
[QUOTE=tugsailor;133479]A friend is tending rigs at Sable Island. His company bought four more 2nd hand boats (from Norway) last fall. They are expecting a big expansion at Sable Island.
I heard, don’t know if its true, that they started running the new pipeline next to the old one through Maine last year.
I hear they are also doing some on shore gas drilling and fracking in Ontario, Quebec, and New Brunswick.[/QUOTE]
My info about the decline at the Sable field might be dated. It makes sense about the fracking but I thought that some of the new wells were coming up dry.
They were planning a second pipe a while back, .Nothing heard lately.
I was in Halifax last year, two or three new boats there.
From Feb 2014!
By Whit Richardson, BDN Staff
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The owner of the Maritimes and Northeast Pipeline has announced plans to retrofit its pipeline to allow it to carry natural gas from southern New England into Maine, the opposite direction of the pipeline’s original purpose.
Houston-based Spectra Energy, which is majority owner of the Maritimes and Northeast Pipeline, is willing to make the needed investments to make the pipeline “bi-directional” if it can secure the customers to make it economically feasible, Richard Kruse, Spectra’s vice president of regulatory affairs, told the Bangor Daily News on Wednesday.
The Maritimes and Northeast Pipeline was built in 1999 to carry natural gas from drilling rigs off the coast of Nova Scotia through Maine and into southern New England. It crosses the border in Baileyville, passing through Brewer, Searsmont and Portland before heading south to the Boston area.
It originally was built to carry 800 million cubic feet of gas per day south, but it has been operating on average at half that capacity or less for the last few years because the offshore projects are not yielding as much gas as anticipated, Kruse said. That, coupled with national shifts in the market for natural gas, makes the prospect of reversing the flow of the Maritimes and Northeast Pipeline an attractive option for the company.
While other areas of the country are benefiting from historically low prices for natural gas because of abundant amounts coming from the areas around the Marcellus Formation, Maine has missed out because the existing pipeline infrastructure needed to bring natural gas into New England is not sufficient to meet demand. As a result, industrial users of natural gas — such as paper mills — face rocketing costs, especially during the winter months when demand peaks.
Spectra’s multimillion-dollar effort to bring more natural gas into New England, which it’s calling the Atlantic Bridge project, would contribute to increasing that capacity and hopefully lowering costs of natural gas in Maine.
The company has announced what’s called an “open season,” which means it’s soliciting interest from potential customers who are willing to enter into contracts for gas that the Maritimes and Northeast Pipeline and the Algonquin pipeline would bring north from the Marcellus Shale and other sources of natural gas in Pennsylvania, Ohio, New York and West Virginia. Besides its Maritimes and Northeast Pipeline, the project also involves the Algonquin Gas Transmission Co., Spectra’s pipeline in southern New England.
Kruse said the company has secured an “anchor” customer: Unitil, which is Maine’s largest provider of natural gas. Even if no additional customers are secured, Unitil’s commitment to buy 100 million cubic feet of gas per day would be enough to go ahead with the project, Kruse said.
Though it’s too early to tell, if other customers sign on, that additional capacity could increase to 600 million cubic feet of gas per day.
Pipeline companies are required by the Federal Energy Regulatory Commission to have contracts secured before building new pipelines or expanding existing ones. Spectra would need to receive a certificate from FERC to move forward with the infrastructure improvements required by the Atlantic Bridge project.
The “open season” to recruit additional customers will run until the end of March.
Spectra’s announcement was welcomed by Patrick Woodcock, director of the governor’s energy office, who has worked with colleagues in other New England states to find a way to increase pipeline capacity into the region.
“I think it really is the first step in a realignment of our natural gas infrastructure to increase utilization of affordable and stable natural gas supplies from domestic resources,” Woodcock said Wednesday.
Gov. Paul LePage’s administration announced in early December a joint initiative with governors from the other New England states to work together to increase the natural gas pipeline capacity into the region.
Woodcock said Spectra’s plans, while good news, wouldn’t alone solve Maine’s energy problems when it comes to natural gas prices. The plan would expand the amount of natural gas entering New England by at least 100 million cubic feet of gas a day, but Woodcock said his office estimates it would take an increase of at least 1 billion cubic feet a day to significantly reduce natural gas prices in the region.
Beyond the fact that every little bit helps, Woodcock said Spectra’s plan is good news because it gets the ball rolling on the regulatory process.
“What is really critical about this decision is it starts the regulatory process and allows the New England states to examine if we can participate in getting the volume up and the capacity to a degree where we really are supplying Maine and New England with low-cost natural gas,” said Woodcock.
It’s too early to tell, but if there’s strong response from customers, the Atlantic Bridge project may require the replacement of portions of the Algonquin pipeline with larger diameter pipe to accommodate the flow into New England. However, Kruse said that would not be necessary in Maine, where the Maritimes and Northeast Pipeline is already a larger-diameter pipe. He said the only infrastructure improvements necessary in Maine would be additional compressor stations, but where and how many are questions that won’t be able to be answered until they know where the gas is going.
The Atlantic Bridge project would not be completed until 2017.
It’s something when their patrol plane buzzes the tower a few times a week 500’ off the deck. They’re not going slow. I’d like to think I’m in the “oh shit” range of the pipeline and not in the instantly dead range but who knows.
well the articles in the trade press are coming furious and fast now about how the majors are going to demand lower costs
[Musings: It’s Official - Oil Industry Enters The New Era Of Austerity](URL: Musings: It's Official - Oil Industry Enters The New Era Of Austerity | Rigzone)
PPHB LLC 3/20/2014
This opinion piece presents the opinions of the author.
It does not necessarily reflect the views of Rigzone.
Last week, Chevron (CVX-NYSE), the second largest oil company, held its annual analyst meeting at which time the company’s management laid out its plans for the next five years, including projections for capital spending and oil and gas production growth. The meeting followed on a presentation at the IHS CERA Week conference in Houston by Chevron CEO John Watson in which he proclaimed that today’s $100 a barrel oil is the equivalent of the past’s $20 a barrel oil. By that he meant that the oil industry must now figure its budget outlooks based on the need for oil prices to stay around the $100 a barrel level in order for the company to generate the necessary cash flow to support spending plans and for projects to offer future returns to meet or exceed required investment hurdles. Mr. Watson has talked about the impact on his business of rapidly escalating costs for finding and developing new oil reserves, which is why he says the company now needs that $100 a barrel price. Chevron is the latest major oil company to implicitly declare that the oil industry has entered a new era – one marked by higher costs and more disciplined capital investment programs that will require higher oil prices. Capital discipline forces companies to sacrifice production growth targets on the altar of increased profitability in order to boost returns to shareholders. What does this new era mean for the oil and gas business? Equally important, what does it mean for energy markets?
Chevron now projects it will produce 3.1 million barrels a day of oil equivalent (boe/d) in 2017, down from a target of 3.3 million boe/d that the company established in 2010 and reiterated to the analysts last year. If Chevron attains its target, it will have increased production in the interim by 19%, a not inconsequential gain. Mr. Watson attributed the reduction in the company’s output target to lower spending for shale wells due to the fall in North American natural gas prices, higher volumes of oil going to the host countries where the company operates under production-sharing arrangements, and “project slippage.” Mr. Watson also indicated that the company would raise $10 billion from the sale of assets, up from its previous target of $7 billion. The company plans to sell oil and gas fields and acreage to raise the funds.
The Chevron outlook mirrors that presented earlier by the industry’s largest company, Exxon Mobil (XOM-NYSE), at its annual analyst meeting. There, not only did ExxonMobil CEO Rex Tillerson announce a reduced production target, but he also said that the company would cut back its capital investment program. While neither the world’s number one nor number two oil companies signaled that the changes in their targets were the result of the industry entering a new era, their actions and similar ones by several of its smaller sisters do suggest that reality.
BP Ltd. (BP-NYSE) announced it was going to split off its shale operations into a separate company, still wholly-owned by BP, in an attempt to transform the operation into a more nimble explorer and developer of shale properties. If mimicking the organizational structure of larger independent oil and gas operators was BP’s goal, one has to wonder what structural impediments necessitated the total separation of the unit. Maybe the move made it easier for BP’s
senior management to highlight the drag of its shale business and establish the entity as a stand-alone business. It may also be advertising the unit’s potential in order to attract a joint venture partner or another energy company’s investment.
The strategic moves by ExxonMobil, Chevron and BP fit with the efforts that Shell (RDS.A-NYSE) is making to improve its financial performance. The company is constraining its capital spending and reassessing the economic attractiveness of every exploration and development project. Another large oil company that recently made a strategic move was Occidental Petroleum (OXY-NYSE). The company is planning to spin off its California oil and gas assets and operations into a new company for its shareholders, while the remaining corporation is picking up stakes and moving its headquarters from Los Angeles to Houston where it maintains significant operations. While this move may say more about the desire of OXY’s management to exit the unfriendly confines of California’s regulations and costs, it also says something about the future direction of the company’s exploration and development focus.
We have seen similar statements about revisions to strategic plans by the large, European-based oil and gas companies – ENI (ENI-NYSE), Total (TOT-NYSE) and Statoil (STA-NYSE). These moves are being undertaken by the management teams in response to flagging performance from their huge shale investments and other challenges similar to those outlined by Mr. Watson.
We were intrigued by the decision by Chevron to boost its oil price outlook from $79 a barrel for Brent crude oil to $110 per barrel. This move is designed to help the financial outlook for the company’s earnings and to offset the reduction in the production target. The oil price assumption is consistent with the average Brent price for the past three years, but it is at odds with the trajectory for prices derived from the futures market, which call for lower levels in the future. We wonder whether this price-target revision will rank with their statement about the future course for natural gas prices a few years ago when the major oil companies jumped on the shale gas bandwagon. Their timing essentially marked the top for gas prices as North American gas prices collapsed due to the surge in gas output. This would not be the first time major oil company planning departments incorrectly projected the course of global oil prices.
Strategy adjustments by major oil companies are seldom quickly reversed even when near-term industry trends suggest an adjustment should be made. If the newly defined financial discipline mantra demanded by investors is followed and industry capital spending is restrained, and possibly falls, there will be ramifications in the energy market. If Mr. Watson’s declaration, as echoed by other oil company CEOs, is true, then the cost of finding and developing new reserves is too high and the pressure to drive down oilfield service costs will grow more intense. We may now be witnessing the fallout from that discipline in the offshore drilling business where the expansion of the global rig fleet with more sophisticated and expensive rigs, necessitating higher day rates, is leading to near-term “producer indigestion.” Could the offshore drilling industry be on the precipice of a significant wave of older rig retirements in order to sustain demand for its new, expensive drilling rigs currently being delivered without contracts?
Another question for the industry is who will supply the risk capital for exploratory drilling, both on and offshore, if the majors pull back their spending? Onshore, for the past few years, a chunk of that capital has been supplied by private equity investors who have supported exploration and production teams in start-up ventures. They have also provided additional capital to existing companies allowing them to purchase acreage or companies to improve their prospect inventory. Unfortunately, the results of the shale revolution have been disappointing, leading to significant asset impairment charges and negative cash flows as the spending to drill new wells in order to gain and hold leases has exceeded production revenues, given the drop in domestic natural gas prices. Will that capital continue to be available, or will it, too, begin demanding profits rather than reserve additions and production growth?
The amount of capital flowing into the oil and gas business is extremely important for the future growth of the nation’s oil and gas output since shale wells experience sharp production declines in the early years of their production. A series of questions flow from that production profile: What will happen to oil and gas prices in the medium-term if drilling slows and production rapidly declines? Will manufacturers who currently are building billions of dollars-worth of new plants designed to capitalize on cheap American energy find their investment returns not what they anticipated? How will they react? Will first-mover advantages in this manufacturing renaissance become a disadvantage? What about the billions of dollars targeting new liquefied natural gas (LNG) export terminals? Will we actually have the volumes of natural gas to export, and especially at the low prices projected that are anticipated to give American gas a competitive advantage in European and Pacific gas markets?
These questions should be raised at the same time the national debate about exporting domestic crude oil is commencing. There are various subtleties in that debate that are often lost in the broad debate themes. For example, how quickly can the U.S. refining industry build new refineries or expand existing ones in order to use more of the light, sweet crude oil coming from the tight shale oil formations? If the refining expansion doesn’t keep pace with the growth of light oil, then there could be a cutback in drilling for shale oil that will certainly result in a sharp reduction in the current bullish outlook for U.S. oil production as shown by the significant increase in future output estimated by the Energy Information Administration in its 2014 outlook versus its 2013 projection.
A cutback in oil drilling would also reduce the volume of associated natural gas being produced, which could result in an unexpected spike in gas prices. For some time, U.S. oil producers have been able to secure export licenses to send oil out of the country, primarily to Canada, but will that avenue continue to exist and can it be expanded to prevent a shutdown in shale oil drilling? The political debate over exporting domestic crude oil is being described as 310 million American consumers versus a handful of oil company CEOs with fat pay packages. We doubt the industry can win that battle.
Those are only some of the critical questions that must be asked and answered as the oil and gas industry transitions into the next era of its existence. Much like the performance of the United States economy, the oil and gas business has internal momentum that will keep it going as managements reassess its future. We have been watching the industry over the past couple of years with one historical perspective in mind – the generational change underway in the executive suites of energy companies. While we are not denigrating the experience levels or intellect of the new CEOs, we are merely reflecting on the past periods when industry leadership changes occurred. Those transitions often resulted in the new leaders having to make their own “learning mistakes” like their predecessors did. That may be an important aspect of the industry transition currently underway.