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Expo/Industry events for the next few months

Upstream PA 2016
April 19, 2016
Penn Stater Inn
State College, PA

www.upstreampa.com

Ohio Valley Regional Oil & Gas Expo
April 26-27, 2016
Belmont County Carnes Center
St. Clairsville, OH

http://www.ohiovalleyoilgasexpo.com/

Latest facts and a rumor from the Marcellus and Utica Shale

  • Antero Adding Rigs in WV.  Antero has a good hedging position and because of it, it will be adding two rigs in WV.  (RUMOR)
     
  • Utica Upstream Seminar Highlights.  We want to thank all of our speakers, sponsors and attendees.  The seminar was very informative.  Here are a few of the highlights:
     
    • Breakeven for the Marcellus drillers is $2.
    • Breakeven for the Utica drillers is $3.
    • When the price of oil is in the $50-$60 range, it will help Utica NGLs.
    • The REX (Rockies Express Pipeline) and Rover may not have enough production capacity.
    • The Nexus Pipeline may be delayed.
    • EdgeMarc is operating 1 rig and it just moved it to Monroe County, OH
    • JobsOhio is speaking with companies in Japan about investing in the Utica.  
    • According to Wood McKenzie, the Marcellus has 15 rigs drilling in the wet gas area and 8 rigs in the dry gas area.  In the Utica, there are 3 rigs in the wet gas area and 7 rigs in the dry area.
       
  • Utica Producers Focusing on DUCs.  Producers in eastern Ohio’s Utica Shale play will focus during 2016 on getting their “DUCs,” drilled but uncompleted wells, into production, rather than spud new wells, a Wood Mackenzie analyst said Wednesday.

    “There are 150 to 250 drilled but uncompleted [DUCs] wells in the Utica,” according to Maria Cortez, a Wood Mac analyst focused on Upstream activity in the Lower 48 States. “Those wells will be completed before new wells are drilled.”

    Cortez kicked off the day-long Utica Upstream Conference, held at the Pro Football Hall of Fame in Canton, Ohio, produced by the Canton Regional Chamber of Commerce and ShaleDirectories.com. Kallanish Energy was in attendance

    Low prices for oil and natural gas, brought on by the shale-drilling boom, have made it less economical to drill new wells.

    As of last week, only 12 rigs were drilling Ohio’s Utica Shale, according to state statistics.

    Cortez said the Utica needs 11 rigs drilling to keep production at current levels, adding the rig count will likely hit bottom at 11 this summer.

    The total cost of Utica wells has been rising to roughly $9 million per well in southeastern Ohio, but the wells are longer, produce more natural gas and liquids and actually cost less per foot, Cortez said.

    While the well count falls, drilling efficiencies and overall familiarity with the Utica rock has led to less expensive wells, according to Cortez.

    “In 2011, the average well cost 8.9 million, or $1.8 million per 1,000 feet drilled,” Cortez said. In 2014, the average well cost in the Utica was $8.8 million, or $1.2 million per 1,000 feet drilled.

    “Now, the average is $1 million per 1,000 feet drilled,” according to Cortez. “To be able to drill down 13,000 feet, and then 10,000 feet out for $9 million is simply incredible.”
     
  • LNGs Going to Kuwait.  Kuwait’s state oil company has signed deals to import 2.5 million tons of liquefied natural gas (LNG) annually to help fuel power plants during the country’s scorching summer, Kallanish Energy finds.

    The state-run Kuwait News Agency reported Thursday the deals involve BP, Royal Dutch Shell and Qatargas. It offered no financial terms for the deal, though the state-run Qatar News Agency said Qatargas’ agreement called for it to offer a half-million tons a year for four years.
     
  • DOJ Sues Halliburton.  The U.S. Department of Justice (DOJ) on Wednesday sued oilfield services firm Halliburton to stop its proposed acquisition of smaller rival Baker Hughes, citing antitrust concerns, Kallanish Energy reports.

    The firms, the second- and third-largest in the industry behind Schlumberger, saw their stock prices soar with the U.S. fracking boom of the past decade. But the share prices were crippled in the last 18 months by slumping oil prices.

    The $35 billion deal, announced in November 2014, was scheduled to close last year, but it’s been delayed by U.S. antitrust regulators. In the meantime, the value of the deal has shrunk to roughly $25 billion, again due to slumping share prices.

    “The proposed deal between Halliburton and Baker Hughes would eliminate vital competition, skew energy markets and harm American consumers,” Attorney General Loretta Lynch said, in a statement. “Our action makes clear that the Justice Department is committed to vigorously enforcing our antitrust laws.”

    Halliburton’s purchase of Baker Hughes was seen not merely as a move to bulk up, but to acquire the company’s research arm, proprietary technologies and patents.

    “By combining two great companies that have delivered cutting-edge solutions to customers in the worldwide oil and gas industry for more than a century, we will create a new world of opportunities to advance the development of technologies for our customers,” Baker Hughes CEO Martin Craigshead said when the deal was announced.

    Halliburton contractually must pay Baker Hughes $3.5 billion if the deal goes sour.
     
  • Is the ET – Williams Deal in Trouble?  Williams on Wednesday said it’s suing its acquirer, Energy Transfer Equity, and its CEO, Kelcy Warren, in two different legal venues, “to unwind the private offering of Series A Convertible Preferred Units [by Energy Transfer],” and for merger interference.

    The two pipeline giants signed a $38 billion deal seven months ago, but the off-the-table drop in oil and gas prices has caused tension between the two.

    So is the $6 billion in cash Energy Transfer is to pay Williams as part of the deal.

    Williams is suing Energy Transfer in the Delaware Court of Chancery to unwind the private offering, and suing Warren in U.S. District Court in Dallas, for wrongfully interfering with the merger.

    “Williams has commenced litigation to protect the interests of its stockholders,” the company said, in a statement. “The litigation is intended to ensure that Williams’s stockholders will receive the consideration to which they are entitled under the merger agreement.”

    Warren was among a group of Energy Transfer’s so-called accredited investors invited to participate in purchasing the convertible preferred units via private offering, according to a Securities and Exchange Commission filing, reviewed by Kallanish Energy.

    In its own SEC filing, Energy Transfer said it “believes that it has complied, and it intends to continue to comply, with its obligations under the merger agreement with Williams and intends to vigorously defend against the claims made by Williams.”

    Dallas, Texas-based Energy Transfer would take on billions in debt to finance the acquisition, and has been looking for a way out of the deal.

    However, the deal is structured so that Tulsa, Oklahoma-based Williams is the only party that can terminate the deal — by paying a $1.5 billion breakup fee.

    Despite the lawsuits, the Williams board said Wednesday it’s committed to the merger as it was signed in September. Shareholders still have to approve it.

    Energy Transfer, however, has changed its outlook. In an amended filing last month, the company sharply reduced its estimate for how much the merger would increase its earnings, slashing it to $170 million from the original $2 billion projection.

    Energy Transfer said it was also consolidating offices in Dallas, meaning potentially thousands of job cuts for Williams employees. The initial agreement said Williams’s presence in Oklahoma would be maintained.
     
  • Schlumberger Completes Cameron Deal. U.S. oilfield services giant Schlumberger has completed the $14.8 billion takeover of flow equipment provider Cameron International, in one of the largest mergers in the energy services sector.

    “The transaction combines two complementary technology portfolios into a pore-to-pipeline products and services offering to the global oil and gas industry. This will result in the industry’s first complete drilling and production systems,” said Schlumberger.

    After the merger, former Cameron stockholders now own roughly 10% of Schlumberger’s outstanding shares of common stock, while former CEO Scott Rowe has become president of the Schlumberger Cameron Group, Kallanish Energy learns.
     
  • Marathon Begins Work on Cornerstone Pipeline.  Marathon will soon start digging trenches for a pipeline to connect the Utica Shale region with its Canton refinery.

    The Cornerstone pipeline will carry natural gasoline and condensate from processing plants in Cadiz, Scio and Hopedale, a move that could decrease the amount of flammable liquids shipped on tanker trucks and railcars.

    Cornerstone is being built by Marathon Pipe Line, which is owned and managed by Findlay-based Marathon Petroleum Corp. Marathon Pipe Line operates about 6,000 miles of pipeline and ships 130 million gallons of petroleum products a day.

    The pipeline will carry natural gasoline and condensate. Right now, producers have to ship those petroleum liquids by road or rail.

    "This is the first pipeline solution for the Utica for these liquids," said Jason Stechschulte, who does business development for Marathon Pipe Line.

    Natural gasoline is a low-octane liquid that can be blended with higher-octane gasoline at a refinery. It's also used to dilute heavy oil, such as that from Canada’s tar sands, so it flows more easily through a pipeline.

    Condensate is a mix of liquids separated from the gasses that flow from Utica and Marcellus shale wells. The Canton refinery uses condensate to make gasoline and diesel fuel.

    Cornerstone will carry natural gasoline and condensate through a 16-inch-diameter, 42-mile-long pipeline from Cadiz to storage tanks near East Sparta. That section of the pipeline will be able to ship 180,000 barrels of liquid a day.

    The East Sparta tanks already store diesel and gasoline, but Marathon is converting one tank to hold natural gasoline and is building another tank for condensate.

    From East Sparta, an 8-inch-diameter pipeline will carry 45,000 barrels of condensate a day to the Canton refinery 8 miles away.

    Roughly 100 condensate tankers pull into the Canton refinery a day.

    Tankers probably still will deliver condensate from wells in parts of Carroll, Columbiana and Stark counties, for efficiency reasons, but producers farther south likely would use the pipeline, Stechschulte said.

    Marathon estimates the Cornerstone pipeline and East Sparta tank project will cost $250 million.

    The Cornerstone pipeline is expected to be in service by the end of the year.

    Marathon has secured rights-of-way for the pipeline, said Jake Chenevey, project manager.

    The pipeline impacts 200 landowners, and up to 85 percent of the route follows existing pipeline corridors, he said.

    Houston-based Price Gregory will build the pipeline, and the project could employ 500 workers at its peak. The company uses union workers, Chenevey said.

    Workers will start digging trenches by late April or May. Construction will begin in Harrison County and should reach Stark County by June or July, with the work nearing Canton in August.
     
  • Can 90 Rigs Do It?  Anyone currently in the energy business has to deal with the effects of low oil and natural gas prices. It’s not pretty. Companies are reporting dreadful results or going bankrupt. People are losing their jobs in staggering numbers, and banks are oddly silent even though the whole world can see what’s happened to the value of their energy portfolios. Even green energy companies are suffering as the comparative economics of renewable energy melt like ice caps.

    It’s easy to catch the pessimism swirling around in the media. The phrase “resilient production” has become as common as dirt. The consensus view is that shale producers have become so efficient at extracting oil and natural gas that we need only a few rigs to keep production up, and that no end is in sight to the low price misery. But as is often the case, that sort of thinking is a result of complacency, lazy analysis, and group-think.

    Take natural gas as an example. The US currently produces about 80 billion cubic feet per day (bcf/d). Shale gas is estimated at about half of US production, or 40 bcf/d (and probably more now as that statistic is a few years old). There are currently 90 rigs looking for gas in the US, which is the lowest since I have no idea when, but Baker Hughes’ rig count shows it being the lowest number by far since at least 1987. In 2013 and 2014, there were an average of over 350 rigs drilling for gas, most of which were chasing highly prolific shale gas plays. During this period, US natural gas production rose by 4.5 bcf/d per year.

    However, contributing to this glut was the large amount of solution gas coming from oil wells being drilled. For example the Bakken oil formation in North Dakota alone added 0.6 bcf/d, and in 2014 added another 0.8 bcf/d. And that was from a single oil-dominant formation; many US shale oil fields produced significant additional solution gas. The same held true for natural gas liquids; liquids-rich shale gas production took off because producers could, a few years ago, make good money selling the liquids even if the gas was dumped as a waste product. So natural gas production increases also include gas as a byproduct, which means that pure shale gas production didn’t really add much more than offsetting natural declines.

    While that’s an ugly barrage of statistics, it’s useful to look at those numbers to see if there is any reason to believe 90 gas rigs can maintain production, particularly with few oil rigs adding new solution gas.

    The answer is: highly unlikely. Oil companies can’t make money drilling for oil or liquids, so that source of gas growth has been cut off. It is true that natural gas production has remained high, however that can be largely attributed to the completion of wells that had been previously drilled. This phenomenon massively distorts production statistics, because what is reported is drilling rig activity and production. Even if only one rig was in operation all year, a significant amount of production would be brought on stream by completing this inventory. Energy-illiterate news publications would completely miss the point, marveling at the unbelievable productivity gains that must be occurring from that single rig.

    At some point though, the various factors will catch up. The uncompleted inventory is being drawn down, solution gas production is dwindling along with oil well drilling, and so few rigs are drilling for gas that we don’t even hear about flaming faucets anymore. It is true that well productivity has increased due to much longer laterals and more frack stages; however this is a very short term solution that maximizes initial production at the expense of long term recoveries. At some point in the near future, natural gas production could very well fall off a cliff.

    And maybe we won’t even know that it happened until it’s truly upon us. Most current production data is not actual data at all; it’s built on sophisticated models that estimate new production based on a number of factors that rely in large part on historical consistency. Rapid, large changes sometimes surprise the models, so the news could happen quickly.

    There is also an embedded expectation that the shale resource is so great and so immediately accessible that any uptick in prices will lead to a new drilling frenzy. Higher prices will definitely lead to more drilling, but there is no certainty that a flood of gas will quickly materialize. It took vast amounts of capital, and extensive drilling of sweet spots, to get production up that quickly. We will soon see how big those sweet spots truly are.

    One caveat hangs over the whole debate though, and that is what global natural decline rates really are. It is easy to clearly see declines on individual wells or projects, but this is masked by the variability in maintenance capital budgets, by new pipeline takeaway capacity that previously constrained some areas like the Marcellus, and by new projects coming on stream that were started years ago. Given how cash flows have dried up, how banks have stopped being banks, and how hard it is to raise equity, there are plenty of indicators that increasing production significantly will not be easy. We will find out soon enough.
     
  • U of T Ponders Permian Assets.  The University of Texas is looking for new ways to cash in on 2.1 million acres of prime oil assets obtained through land grants more than a century ago.

    What is now viewed as some of the richest oil land in the world was initially seen as a money maker from cattle grazing. After 1923, when petroleum was discovered in the Permian Basin, a wave of wildcatters descended on the state university seeking leases. By 2014, the annual royalties from about 200 drillers had exploded past $1 billion.

    Now, the school is taking steps to change the equation again. It’s beefed up its geological expertise and wants to adjust how payments are figured, based on cheaper ways to tap into multiple pancaked layers of oil-soaked rock underground. Success could mean as much as a tripling in land value and a new leasing model that might extend to other shale regions across the U.S.

    "In the new scheme of things, not only do we have 2 million acres of land, but if there are two to four plays based on various depths in the shale formations, we might have the equivalent of 6 to 8 million acres of land," said Scott Kelley, who oversees the University Lands office as executive vice chancellor for business affairs.

    The shale oil boom and crash brought home how much more the school could be getting from its acreage, propelling it to the vanguard of an effort to redefine the rules for how landowners get paid by U.S. oil companies.

    Negotiations hang on the unique nature of the region’s geology. Before the shale boom, most wells were drilled straight down until they punctured pools of crude deep underground. When a company leased drilling rights, those rights basically extended all the way to the center of the earth.

    Shale is different. Oil is locked into layers of rock like water in a sponge. Getting it out requires drilling sideways through those levels and cracking the rock with hydraulic fracturing to let the oil flow. In some shale fields -- and most notably in the Permian Basin -- there can be many distinct layers of oil-soaked rock pancaked together.
     
  • Will Hurricanes Help NatGas Prices.  Because of the El Nino this year, a number of weather organizations are forecasting a more active hurricane season.  Some think there will be three major hurricanes.  If they occur in the Gulf of Mexico, it could push NatGas prices up a little.  Prior to Marcellus and Utica drilling, there would have been significant spikes in NatGas prices.  
     
  • Shale Gas Driving Chemical Investments.  U.S. chemical industry investment linked to natural gas and natural gas liquids (NGLs) from shale plays has reached $164 billion for 264 projects – up 128.7% in just three years — the American Chemistry Council (ACC) reports.

    Forty percent of the investment for the 264 projects – new facilities, expansions and factory re-starts – is completed or underway, while 55% is in the planning phase, Kallanish Energy understands.

    “U.S. chemical manufacturers rely on natural gas for heat and power, and it contains ethane, an NGL that serves as our main feedstock,” Owen Kean, ACC senior director of Energy Policy, said. “Dramatic supply growth has had an equally dramatic impact on U.S. natural gas prices. It’s a stunning reversal of fortune from just a few years ago, when the chemical industry was losing market share – and jobs – to competitors abroad.”

    Kean added America enjoys a “robust supply outlook, expected to last for decades, and a price environment that’s the envy of the world. Our country has become the most attractive place in the world to make chemicals, and a historic wave of expansion and investment is underway.”

    ACC analysis shows that $164 billion in capital spending could lead to $105 billion annually in new chemical industry output, and support 738,000 permanent new jobs across the U.S. by 2023.

    The jobs breakout includes 69,000 new chemical industry jobs, 357,000 jobs in supplier industries and 312,000 jobs in communities where workers spend their wages. Much of the new investment is geared toward export markets, which can help improve the U.S. trade balance, ACC believes.

    “We need the right regulatory and policy approaches in order to fully realize the potential of shale gas as an engine of manufacturing growth,” Kean said. “Policymakers must avoid unreasonable restrictions on oil and gas production on public lands; keep oversight of production on private lands in the hands of the states; and expedite the construction and permitting of infrastructure, such as pipelines, needed to move natural gas and NGLs to market.”

    The data released this week by ACC updates the ACC report, “Shale Gas, Competitiveness, and New U.S. Chemical Industry Investment — An Analysis of Announced Projects.”

    Published three years ago, it examined nearly 100 chemical and plastics projects totaling $71.7 billion in potential investment announced as of March 2013. The figures are growing as new projects are announced.
     
  • Ethane Production Is Up.  Ethane production is expected to increase from 1.1 million barrels per day (MMBPD) in 2015, to 1.4 MMBPD in 2017, accounting for 67% of total U.S. hydrocarbon gas liquid production growth, the Energy Information Administration reports.

    Ethane is separated from raw natural gas at processing plants, Kallanish Energy states, and is also known as a natural gas liquid (NGL).

    Over the last half decade, the amount of ethane contained in domestically produced raw natural gas has exceeded the capacity to consume and export it.

    “The oversupply kept ethane prices relatively low, hovering at or below the price of natural gas, leading producers to reject the ethane stream by leaving it mixed with the stream that is marketed as pipeline natural gas, which is mostly methane,” EIA said.

    Beginning four years ago, the availability of relatively inexpensive ethane encouraged a wave of investment in ethane-consuming petrochemical plants and export facilities.

    Many projects, including de-ethanization facilities, ethane pipelines, petrochemical plants, and ethane export facilities, have either recently been completed or are currently under construction and will come online in the next few years.

    “These projects increase takeaway capacity for ethane, especially in the Marcellus and Utica Shale plays, mainly in Pennsylvania, Ohio, and West Virginia, where market outlets for rapidly growing natural gas supply were previously limited to pipeline natural gas,” according to EIA.

    As new ethane-consuming petrochemical and export capacity reduces the ethane oversupply in 2016 and 2017, ethane prices are expected to generally remain above natural gas prices, leading to a rise in ethane recovery to meet demand and export growth.

    U.S. ethane consumption, which totaled 1.05 MMBPD in 2015, is forecast to increase 50,000 BPD in 2016, as expansion projects at ethylene-producing petrochemical plants increase feedstock demand for ethane.

    In 2017, ethane consumption is projected to increase another 80,000 BPD as capacity begins to ramp up at five new petrochemical plants and at a previously deactivated plant.
     
  • Consol Sell Coal.  Natural gas/coal producer Consol Energy said Friday it’s closed on its previously announced deal to sell the Buchanan Mine in southwestern Virginia and certain other metallurgical coal reserves to Coronado IV for $420 million.

    Of the total consideration, $402.8 million in cash was paid at closing, Kallanish Energy learns.

    “This is another significant event in the execution of Consol Energy’s strategy, as well as a meaningful step in continuing to strengthen our balance sheet,” Nicholas J. DeIuliis, Consol CEO, said when the deal was announced Feb. 29.

    “The Buchanan Mine fits into Coronado’s portfolio as a pure play metallurgical coal producer, and, in the end, this transaction bolsters the strategic position of both companies.”

    Also included in the transaction are Consol’s idled Amonate Mine in southern West Virginia and southwestern Virginia, its greenfield Russell County coal reserves in southwestern Virginia and its greenfield Pangburn-Shaner-Fallowfield coal reserves in southwestern Pennsylvania.

    The transaction includes roughly 400 million tons of proved coal reserves, which includes approximately 88 million tons associated with the Buchanan Mine.

    The transaction does not include any gas rights, and Consol retains the right to extract and sell gas at the mines and other properties.

Visit our Blog for daily updates on what’s happening in the oil & gas industry.

http://www.shaledirectories.com/blog/

Rig Count

  • Baker Hughes Rig Count the week of April 8, 2016
     
  • PA     
    • Marcellus 17 unchanged
  • Ohio
    • Utica 12 up 2
  • WV
    • Marcellus 12 unchanged
  • TX
    • Eagle Ford – 43 up 1
  • TX & NM
    • Permian Basin – 142 down 3
  • ND
    • Williston – 27 down 2
  • CO
    • Niobrara – 15 unchanged
       
  • TOTAL U.S. Land Rig Count 414 down 6

PA Permits for February March 31, to April 7, 2016

        County        Township        E&P Companies

1.    Clinton        Gallagher          Range
2.    Greene        Washington      EQT
3.    Lycoming    Gamble            Seneca
4.    Lycoming    Gamble            Seneca
5.    McKean        Sergeant         Seneca
6.    Washington    Buffalo            Range
7.    Westmoreland    Donegal       WPX

OH Permits for weeks ending March 19, and 26 2016

        County      Township  E&P Companies

1.    Monroe        Perry        E M Energy OH

Joe Barone jbarone@shaledirectories.com 610.764.1232
Vera Anderson vera@shaledirectories.com 570.337.7149

Northeast Supply Enhancement