Much of the Permian Basin’s oil boom eluded the world’s supermajor oil companies like Chevron, who took their corporate offices and large management teams from the area in the 1990s as common perception held the region was slowly dying.
But during this downturn, the supermajors see opportunity again in the Permian Basin. Chevron, and to a lesser extent Exxon Mobil, plan to pursue aggressive drilling and completion programs this year.
In the short-term, that offers some relief for the oil service companies and rig crews hammered by oil prices hovering below $50 per barrel. But it also reflects a long-term belief in the promise of the Permian Basin by some of the biggest companies in the world.
Executives of Chevron, which has a market capitalization of nearly $200 billion, see the region as a “Top 5 asset” in the world.
And so Chevron, like Exxon, plans to not scale back drilling this year even as many of the independents who cut capital budgets in a range of about 25 to about 60 percent.
“It’s true in the Permian Basin, that’s probably the No. 1 focus for both of them in 2015,” said Ben Shattuck, an analyst with the firm Wood Mackenzie in Houston. “They are not dropping rigs like everybody else, and at the same time for them, there is a lot of optionality. The reality is that it is not a huge component of their portfolios, but it is something they would like to take advantage of and wrap their minds around.”
Chevron has about 25 rigs running in the region and expects to keep about that many going throughout the year. Executives plan fewer wells, about 375 compared to the 550 last year. But more of these wells will be horizontal, more expensive and higher producing.
The goal set by executives is to boost Permian Basin production to 250,000 barrels per day by 2020 from about 100,000 barrels per day last year.
During the boom, Chevron also scooped up more property, including about 246,000 net leasehold acres acquired from Chesapeake Energy in 2012. By the middle of last year, less than half of Chevron’s acreage was developed.
Fields: Alger (Mountrail), Parshall (Mountrail), North Fork (McKenzie), Van Hook (Mountrail)
Comments:
Wells coming off the confidential list Tuesday:
26388, drl, BR, CCU North Coast 31-25TFH, Corral Creek, no production data,
27520, 6,002, Whiting, Flatland Federal 11-4TFH, TF1, Twin Valley, up to 9,900 gas units; 97 stages; 4.2 million lbs sand/ceramic; t10/14; cum 264K 2/15;
27521, 5,002, Whiting, Flatland Federal 11-4HR, Twin Valley, MB about 42 feet thick; 94 stages; 4 million lbs sand/ceramic; t10/14; cum 232K 2/15;
27522, 4,207, Whiting, Flatland Federal 11-4TFHU, 4 sections, TF2, in excess of 9,500 gas units, Twin Valley, t10/14; cum 193K 2/15;
28436, drl, Zavanna, Arrowhead 10-3 3H, East Fork, no production data,
In a comment, the reader noted this from Whiting's 3Q14 presentation,
in which Whiting said its Tarpon pad demonstrated that "Whiting
controls the sweet spot of the Williston Basin" and presented this as
evidence (back on confidential status); two of these three wells broke
the fracking record):
27520, 7,824 boe, Whiting, Flatland Federal 11-4TFH, upper Three Forks Cycle 1, Twin Valley, gas ranged from 150 unit so 9,274 units.
27521, 7,120 boe, Whiting, Flatland Federal 11-4HR, middle Bakken, target zone about 42 feet thick;
27522, 5,930 boe,
Whiting, Flatland Federal 11-4TFHU, a lower Three Forks well; the Middle
Bakken was about 42 feet thick; it looks like the TF Cycle 1 might have
been about 74 feet thick; background gas for target zone, the TF Cycle
2, ranged from17 to 8,500 units, in excess of 9,500 units during trips;
in application referred to as Three Forks B1;
These three wells are on a single pad about 1,000 feet to the west of a
Tarpon Federal pad in the northwest corner of section 4-152-97, Twin
Valley oil field.
Two of the three wells had been noted before; this offers an opportunity
to take another look at the wells. The Whiting Flatland wells, noted a
little bit farther below, are the two wells that broke the fracking
record with 94- and 102-stage NCS coiled tube fracking.
NextEra Energy Resources LLC, the biggest renewable-energy power
company in North America, is spending another $640 million on two
massive new wind farms in eastern Colorado.
That’s on top of the
“roughly $2 billion” the company has already invested in Colorado via
seven existing wind farms that collectively generate 1,175 megawatts
worth of power.
It's unclear whether this means an increase in the original capacity of 1,175 megawatts or whether it's additional money to develop this power.
$2,000,000,000 / 1,175 megawatts = $1.7 million / MW which is well below the "usual" $2.5 million/MW. It should be noted that the exact numbers (MW) and the exact dollar amounts are not provided.
$2,640,000,000 / 1,175 megawatts = $2.2 million / MW -- which is a lot closer to the "usual" $2.5 million / MW.
Later, 2:38 p.m. CT: a reader provides a bit of insight regarding the fact that "all" new Zavanna wells coming off the confidential list are going to DRL status. First, re-read this post from last fall: a new Zavanna natural gas processing plant seven miles northeast of Williston. Second, the reader sent me a scanned copy of a letter from Zavanna suggesting that Zavanna plans to frack a number of wells in Stockyard Creek (one of the best spots in the Bakken). These data points suggest to me that Zavanna is taking the new NDIC flaring rules seriously and is doing what it can to meet the requirements. The natural gas processing plant is near Springbrook, North Dakota, about 7 miles northeast of Williston; the website link is here. I don't know where the plant is located but most likely somewhere along County Highway 6 east of US Highway 85, north of Williston. Google maps indicate a lot of activity in this area. Be sure to note that the Flatirons site mentions "gas lift" -- be sure to check that out at wiki if you are unfamiliar with gas lift.
Original Post
During the slow-down in drilling and the severe slump in oil prices, a couple of observations with regard to "new wells coming off the confidential list":
most wells are going to DRL status
Zavanna wells consistently go to DRL status
it appears most Hess wells go to DRL status
toss-up among CLR wells; some completed; some DRL status
Whiting and QEP tend to complete their wells
Statoil tends to go to DRL status, but in the old days they were completed relatively quickly
Enerplus wells generally go to SI/IA status
One can look at wells that came off the confidential list in the 1Q15 at this link; this page has not been updated (as of April 6, 2015) so it will show the status of the wells when they came off the confidential list; these 1Q15 wells will be updated in the next calendar quarter.
This is just idle chatter; no statistical analysis. It's just my impression, and my impression could be way off. Don't make any decisions based on my impressions; if this information is important to you, go to the source.
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Reminder: this is not an investment site. Do not make any investment or financial decisions based on anything you read here or think you may have read here.
I think there was a story over the weekend, which I did not post, suggesting that oil production from Texas was steady or increasing despite laying down of rigs. Today, from Yahoo!In-Play:
Matador Resources provides operational update; achieved record quarterly production of approximately 2.1 million BOE for the first quarter of 2015: Production for the first quarter of 2015 was almost double the 1.1 million BOE produced in the first quarter of 2014 and up about 10% sequentially from 1.9 million BOE produced in the fourth quarter of 2014. First quarter 2015 production was ahead of the Company's estimates by about 10% as a result of better-than-expected performance from newly completed wells in both the Delaware Basin and the Eagle Ford shale, as well as earlier completion dates on several Eagle Ford wells leading to less shut-in production during the first quarter.
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Today's EIA Blurb
On refining and light tight oil:
With the growth in U.S. production of light tight oil (LTO) in recent years, petroleum refiners in the United States have been processing greater volumes of LTO. To date, increased volumes of domestic LTO have mainly been accommodated with no- and low-cost options such as reducing light crude oil imports, increasing refinery utilization rates, making incremental efficiency improvements (crude unit debottlenecking), and displacing medium crude oil imports. A new EIA report (http://www.eia.gov/analysis/studies/petroleum/lto/) reviews a range of additional options that U.S. refiners may consider to expand LTO processing capacity. --- EIA
And another blurb from the EIA today:
The top 100 oil fields as of December 31, 2013, accounted for 20.6 billion barrels of crude oil and lease condensate proved reserves, which was 56% of the U.S. total (36.5 billion barrels) in 2013…The top 100 gas fields as of December 31, 2013, accounted for 239.7 trillion cubic feet of total natural gas proved reserves, about 68% of the U.S. total natural gas proved reserves in 2013 --- EIA
A fairly useless statistic. And it's more than a year old; it's 2013 data. Auto manufacturers get their monthly sales data out the first day of the next month. There's trivia, and then there's EIA trivia.
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Counter-Intuitive
This one caught me by surprise -- at least until I got into the article. The WSJ is reporting that low oil prices may curb domestic demand. Yes, it will take a fairly long article to explain that one.
This is an old, old story for long-time readers, but I'm not sure if newbies are aware of this issue: the Mideast consumes a lot of their own oil; they are consuming more; local consumption puts exports at risk.
The article begins:
The sharp drop in oil prices hasn’t been kind to the world’s petro-states, but it has provided an opening to address one of their most pressing economic problems: runaway domestic energy demand.
In the Middle East, the growth in demand is driven in part by expanding populations, as well as a deliberate move into energy-intensive industries such as aluminum and petrochemical production. But a big part stems from the region’s ubiquitous energy subsidies.
Voracious energy use in countries such as Saudi Arabia and Iran is threatening exports from the most oil-rich region in the world. Failing to restrain this galloping demand could leave global markets more volatile, pressure domestic budgets and eventually nudge prices back up.
As a group, OPEC members—mostly countries in the Middle East and Africa, plus Venezuela and Ecuador—now consume almost as much energy as China, with less than half its population. The Middle East, especially, is expected to account for a major chunk of future global demand growth. Saudi energy use is expected to grow at a 3.8% rate through 2020, according to the International Energy Agency. That’s slower than the country’s 5.7% annual average over the past six years, but well above the expected global average of 1.2%.
Consumption is “out of control,” said Steve Griffiths, an executive director at the Masdar Institute, an energy think tank in Abu Dhabi.
Nearly every country in the Middle East long ago embraced the notion that cheap fuel was essentially a birthright. As a result, energy is all but free in some places, such as Saudi Arabia, where a gallon of gasoline costs 45 cents. Governments pick up the rest of the tab, either paying for imports or forgoing income that could be earned by exporting domestic oil or gas rather than selling it for rock-bottom prices at home.
Most countries have realized that’s not sustainable. Some countries, such as Iran, Nigeria and Venezuela, have already hit that wall: They are unable to maintain their spending on imports to meet demand or balance their budgets without the export revenue they are forgoing to satiate consumers’ growing energy appetite. Iran has made some halting progress in raising prices closer to market levels; Nigeria and Venezuela haven’t.
Much more at the link. This graphic is from the linked article above:
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I've Been Everywhere -- Greek Prime Minister
Last week the Greek prime minister was in France to visit the IMF. This week he travels to Moscow.
It's all for show. Russia has no money. The Greeks even said that -- it's not for money; it's for show.
From the print edition:
Greek officials said Mr Tsipras isn't looking for money from [Putin]. Russia's weak finances and limited interest in Greece mean it isn't a viable source of funding anyway.
Instead, they said the visit is aimed at pleasing Greek voters with a show of defiance toward European creditors.
It may take awhile, but I eventually get around to most things. One of the "Big Stories" (linked at the sidebar at the right), I follow "natural gas and coal in the post-nuclear world." That was the big story that came out after the Fukushima debacle in Japan (tsunami / nuclear reactor). Everyone thought nuclear was dead. Not so fast.
1. Japan is massively dependent on imported energy. Japan is the world’s largest LNG importer, second largest importer of coal, and third largest importer of crude oil. If Japan managed to ramp up nuclear power to 20 percent of its electricity, it would be able to slash its purchases of fossil fuels dramatically.
2. Weaker economics for energy exporters. Japan’s sharp increase of fossil fuel consumption for power generation after Fukushima raised international prices, particularly for LNG. Spot LNG cargoes in Asia – the so-called JKM marker – spiked, selling for more than three times the price of natural gas found in the United States. The JKM marker has since come down both because more LNG supplies have come online and due to the collapse in oil prices. A return to nuclear power will obviate the need for elevated imports of LNG, keeping JKM prices from returning to their highs of 2011-2013. That will cap the market for LNG exporters around the world, pushing many LNG export projects into the red – from Western Canada, to the U.S. Gulf Coast, to Australia. LNG will be a major loser of Japan’s nuclear restart.
3. Trade deficit and electricity rates down. In the three years following Fukushima, Japan spent $270 billion on coal, oil, and LNG imports, a 58 percent increase over what it otherwise would have spent had its nuclear fleet remained online. That forced Japan to run a trade deficit for the first time in 30 years. Japan’s trade balance went from a $65 billion surplus in 2010 to a $112 billion deficit three years later, owing mostly to higher fossil fuel imports. That also translated into higher electricity prices. Japan’s electricity rates increased by 30 percent for industry and 20 percent for residential homes, respectively. Nuclear power can help reverse the ballooning trade deficit and rising electricity costs.
4. Greenhouse Gases. The loss of nuclear power has taken a toll on Japan’s climate posture, as Japan’s greenhouse gases hit a record in 2013. In the absence of nuclear power, Japan is planning on building a lot more coal plants. It has backtracked on its commitment to reduce greenhouse gas emissions. That could change if nuclear power plays a larger role in the future.
The "greenhouse gas" issue will be the banner to sell this to the Japanese, but at the end of the day, it's all about money.
During normal years, the state should replenish reservoirs. However, environmental regulations require that about 4.4 million acre-feet of water—enough to sustain 4.4 million families and irrigate one million acres of farmland—be diverted to ecological purposes.
Even in dry years, hundreds of thousands of acre feet of runoff are flushed into San Francisco Bay to protect fish in the Sacramento-San Joaquin River Delta.
During the last two winters amid the drought, regulators let more than 2.6 million acre-feet out into the bay.
The reason: California lacked storage capacity north of the delta, and environmental rules restrict water pumping to reservoirs south. After heavy rains doused northern California this February, the State Water Resources Control Board dissipated tens of thousands of more acre-feet. Every smelt matters.
Increased surface storage would give regulators more latitude to conserve water during heavy storm-flows and would have allowed the state to stockpile larger reserves during the 15 years that preceded the last drought. Yet no major water infrastructure project has been completed in California since the 1960s.
Money is not the obstacle. Since 2000 voters have approved five bonds authorizing $22 billion in spending for water improvements. Environmental projects have been the biggest winners. In 2008 the legislature established a “Strategic Growth Council” to steer some bond proceeds to affordable housing and “sustainable land use” (e.g., reduced carbon emissions and suburban sprawl).
Have You Ever Seen The Rain, CCR
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Pricing: Sanctions? What Sanctions?
For the archives. Bloomberg says this was posted "16 minutes ago," when I posted the link, but almost the very same story was posted yesterday. In fact, I thought I had read the very same story a month ago. It turns out the stories are similar: for the second month in a row, Saudi Arabia has increased the price of its oil it sells to China. By ten cents. Yes, ten cents.
Whatever.
The Iranian "deal" will have little affect on the crude oil market.
There are bigger impacts:
Despite the sanctions,
China's imports from [Iran] are set to rise from August as a
Chinese state trader has signed a deal with the National Iranian Oil
Company to buy more condensate.
Concerns
over fighting in Yemen also supported prices, as fighting between a
Saudi-backed coalition and Shi'ite Houthi forces continued in the port
city of Aden, which overlooks a major shipping lane between Europe and
the Arab Gulf.
Later, 1:56 p.m. CT: a reader sent a nice 30-second sound bite / several data points that puts the Marcellus into perspective. See first comment below. I brought the note up here so it is google-searchable.
A few data points conveying the size of the Marcellus and Utica resources:
Largest
producing well in the Marcellus - Cabot's T Flower 2 - has produced
over 13 billion cubic feet of gas in two years, 745 days of production
averaging 17,712 MCF/day. In oil-equivalent terms, this well, in two years, has produced over 2,200,000 boe at almost 3,000 boe/day.
The
EIA just described the Marcellus play as covering 72,000 square miles
... an area slightly larger than the entire state of North Dakota.
The underlying Utica formation is significantly larger than the Marcellus in area, with a WAY thicker payzone.
One well, producing over 2.2 million boe in two years is, to say the least, astonishing.
Natural gas processing in the Marcellus and Utica plays has quickly
become a much larger—and more complex—business as major players race to
keep up with fast-rising capacity needs and to ensure that the various
elements of their infrastructure operate as an integrated, well-oiled
“machine.” And, in a region with only minimal NGL storage capacity, one
of that machine’s most important characteristics must be an ability to
deal with all the “what-ifs” that could otherwise lead to logistical
chaos, particularly those issues dealing with ethane. Today, we continue
our in-depth review of Marcellus/Utica NGL infrastructure with a look
at MarkWest’s innovative NGL network and distributed de-ethanization
system.
In one of the most memorable TV scenes ever, Lucy Ricardo and Ethel
Mertz, working as candy-factory wrappers in an episode of “I Love Lucy”,
struggle as the conveyor belt accelerates, sending more and more
chocolates their way.
They cope (barely) through ingenuity (stuffing the candies they can’t
handle in their mouths or storing them in their hats). MarkWest Energy
Partners, which runs the largest natural gas processing and
NGL-fractionation operation in the Marcellus/Utica, has been developing a
far more elegant—and long-lasting—solution to dealing with the
ever-increasing pace of gas and NGL production in that region. Most
important, perhaps, MarkWest is building into its NGL network ways to
mitigate the risks associated with producing NGLs in a region with
next-to-no NGL storage capacity. That is particularly important for
handling ethane, which is by far the most difficult NGL to handle when
there are effectively no storage options.
As we said in Episode 1
of our series, in Mont Belvieu, TX, the center of the NGL/fractionation
world, there’s plenty of storage to absorb infrastructure disruptions
(like ethane-consuming ethylene crackers going offline or pipelines
tripping off due to mechanical problems). But when similar disruptions
hit the storage-challenged Marcellus/Utica (the January 2015 rupture of
Enterprise Products Partners’ ATEX pipeline, which carries ethane from
the Marcellus/Utica to Mont Belvieu, comes to mind) midstream companies
need other ways to deal with all the NGLs still “coming down the
conveyor belt.” In Episode 2, we described the Marcellus/Utica region in more detail; in Episode 3 we discussed the eight major pipelines that move natural gas through and out of the region; and in Episode 4 and Episode 5
we considered the gas processing plants, de-ethanizers and C3+
fractionation facilities MarkWest has been developing. (For more on what
de-ethanizers and C3+ plants do, see Episode 5.)
Today we’ll describe MarkWest’s innovative approach for integrating
this infrastructure to handle the difficult issue of high-volume ethane
production in a region with no ethane storage – and eventually to handle
the requirement of petchem companies planning to build one or more
ethane-based world-scale steam crackers in the region.
