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Expo/Industry events for the next few months

Utica Upstream
April 6, 2016
Pro Football Hall of Fame
Canton, OH

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

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

PIOGA’s 2016 Spring Meeting
April 7, 2016
Rivers Casino

OOGA Winter Meeting
March 16 – March 18
Hilton Columbus at Easton
Columbus, OH

Latest facts and a rumor from the Marcellus and Utica Shale

  • Possible Late 2016 Recovery for Marcellus/Utica Shale.  (Thank you, World Oil)  Unseasonably warm temperatures throughout the U.S. northeast in late December underscored the bearish near-term forecasts for the Marcellus-Utica shale play, where gas prices continue to languish amid a delayed winter drawdown that has kept stockpiles bulging.

    Nevertheless, in what would have been a major head scratcher just over a year ago, a number of players are pulling what remains out of the liquids-rich Ohio fairway of the comingled Utica-Point Pleasant shale, in favor of its dry gas horizons, including expansion into the Marcellus core of neighboring Pennsylvania and West Virginia. Over the past year, some of the operators still active in the combo play there, which stretches some 95,000  square miles across the Appalachian basin, have taken a closer look at the dry gas window of the deeper Utica source rock and, particularly, its stacked pay potential with the overlying and comparably low-cost Marcellus.

    “This market has certainly rendered many Appalachian areas uneconomic and has forced most producers to shift development to other areas or, in the case of producers who have no economic acreage at current prices, suspend their development altogether,” said Daniel J. Rice IV, CEO of Rice Energy. “As a result, there has been a noticeable shift in producer activity away from liquids-rich and non-core dry gas Marcellus and Utica areas, and into the Marcellus and Utica’s dry gas cores.”

    That said, the distressingly perfect storm of mid-January wellhead prices, which topped out at around $2.38/MMbtu, and aggregate inventories at a reported five-year high are starting to take a toll on production from the nation’s most prolific gas play. The latest, best guesstimate of the U.S. Energy Information Administration (EIA) shows a reversal in the annual upward trajectory of the Marcellus, with production expected to drop some 225 MMcfgd between January and February to 15.222 Bcfgd, Fig. 1.

    Fig. 1. Marcellus January-to-February gas production (left) is expected to drop 225 MMcfd, while the Utica is expected to see a 43- MMcfd month-over-month increase (right). Source: U.S. Energy Information Administration (EIA)

    Conversely, month-over-month gas production in the Utica is forecast to climb 43 MMcfd to 3.249 Bcfd, although much of the increased production in 2015 and the early part of this year is attributed to previously drilled, but uncompleted (DUC) wells coming on line. The EIA also expects January to February Utica oil production to increase by a modest 1,000 bpd to 70,000 bpd.

    In the meantime, operators throughout the infrastructure-challenged Appalachian basin are biding their time, awaiting the start-up of what Range Resources Corp. tabulated as no less than 37 pipeline systems, planned to begin deliveries between 2016 and 2018 into the prodigious gas markets of the upper U.S. northeast, Canada and elsewhere. Together, with the seven pipelines that were slated to go into service between 2014 and 2015, the new networks, as designed, would collectively add incremental takeaway capacity of up to 33.5 Bcfgd.

    “We’re really more focused on timing our drilling and completions to fill the pipeline capacity we have from Northern Access 2015 now, and then Northern Access 2016, by the end of 2016. So, that’s really what drives our activity level, rather than current pricing,” says Matt Cabell, president of Seneca Resources Corp., the E&P arm of Houston’s National Fuel Gas Company (NFG). Cabell was referring to NFGS’s two-pronged pipeline network, designed to transport an estimated 0.5 Bcfd of Marcellus gas into the northeastern U.S. and Canada.


    Despite a crippling blizzard in late January that temporarily shot prices up to around $5.00/MMbtu in parts of the Northeast, what should have been the start of the winter-heating season was met with freakishly mild temperatures for the second consecutive year. This delayed the typical, seasonal withdrawals and accompanying price spikes. In its pre-blizzard weekly gas storage report, the EIA, on Jan. 8, had the eastern region holding 802 Bcfg, up nearly 16% from the 692 Bcfg held in stockpile during the like period of 2015.

    According to Baker Hughes, for the week of Jan. 24, the Marcellus Pennsylvania and West Virginia fairways had 35 active rigs, down three from the prior week. The Utica, meanwhile, was up one, to 14 active rigs.

    Rystad Energy believes that gas may be on the verge of lifting out of its persistent funk, citing reduced well costs, a forecasted 2-Bcfd decline in U.S. gas production, and upcoming additional regional takeaway capacity. The Norwegian consultancy expects gas prices to recover by the end of 2016 to around $3.20/Mcf, and $3.50/Mcf in 2017. “Activity is expected to continue to decrease in early 2016, but pick up by the second half as the prices recover,” according to Rystad. “Due to some production curtailment from operators in 2015 as a reaction of the low in-basin prices, the production in 2016 is expected to increase slightly compared to 2015.”

    Compared to their oily brethren, gas producers are veteran hands at adjusting to a low-price environment, with Rystad saying the average breakeven price for Marcellus production now stands at roughly $2.70/Mcf, and below $2.00/Mcf in its core.

    Pending the wholesale release of year-end earnings and 2016 guidance, it is apparent that most operators are in no hurry to put rigs back to work, or production on the market.


    Cabot Oil & Gas Corp. is among those closing the faucet on a significant volume of its Marcellus production, as it awaits the planned start-up of the Constitution and Atlantic Sunrise pipelines in fourth-quarter 2016, and the second half of 2017, respectively. The two networks are designed to deliver an aggregate 2.4 Bcfgd into the northeastern U.S. and, in the case of the Williams-operated Atlantic Sunrise, the Mid-Atlantic and southeastern U.S. market.

    “We’re cautiously optimistic for an improvement in price realizations in 2016, due to the impact of new takeaway capacity coming online over the next few quarters on the demand side, and the impact of significant reduction in industry activity on the supply side,” President and CEO Dan Dinges told investors in October.

    Cabot exited 2015 with two rigs running in its tightly concentrated 200,000-net-acre Marcellus leasehold in Pennsylvania’s prolific Susquehanna County. The Houston-based independent drilled some 80 net wells in 2015, with around 60 completed, and expected to end the year with a 55-well DBU inventory. As of press time, 2016 guidance calls for the drilling and completion of 50 to 65 net wells, respectively. Pointing to additional service cost reductions, improved operating efficiencies and longer lateral lengths, Cabot says its Marcellus assets generate a roughly 70% internal rate of return (IRR) at a realized price of $2.00 MMbtu.

    Chesapeake Energy suggests that whatever level of activity it maintains in 2016, will be directed largely to the commanding 1 million net acres it controls in eastern Ohio’s Utica, which President and CEO Robert Douglas Lawler described as “a powerhouse asset within our portfolio.” The Oklahoma City independent closed 2015 with two rigs active in the Utica, averaging a third-quarter production of 106,000 boed, down 15% sequentially, as an estimated 20,000 boed was withheld from production.

    Chesapeake says its completed well costs, with average 7,900-ft laterals and 40 frac stages, came in at $7.7 million in 2015, up from the average $7.2 million/well in 2014, with 6,200-ft laterals and 29 frac stages. In the third quarter, Chesapeake said it completed a Utica well with a record 12,976-ft horizontal section.

    Moreover, beginning in January, Chesapeake moved to a fixed-fee agreement with Williams Companies that includes the dedication of 50,000 net acres, with a minimum volume commitment of 250 MMbtu/day, which, the operator says, can meet with one rig per year.

    Elsewhere, with its $4.98-billion sale of 413,000 acres in northern West Virginia to Southwestern Energy, in October 2014, Chesapeake still holds 230,000 net acres in the Pennsylvania Marcellus core, most of which is held by production (HBP). At year-end, the company was operating one rig in the Marcellus (Fig. 2), where third-quarter production averaged 820 MMcfgd. During that quarter, Chesapeake tested two Upper Marcellus wells in Bradford County, Pa., with peak production rates averaging 18 MMcfgd.

    In November, Lawler said that until prices improve, roughly 500 MMcf of Marcellus gas will remain behind the choke. “We have pulled off all of our activity, or largely all of our activity,” he told analysts. “We’re excited about the resource. Obviously, we highlight the Upper Marcellus. We anticipate bringing some of that gas online in the fourth quarter, but it’s going to require higher gas prices. We anticipate that will happen, but we’re not going to bring gas on just to hit a production number.”

    Southwestern Energy—which, in February 2015, finalized a $394-million purchase and sale agreement with Statoil, that increased its working interest in 30,000 net acres in West Virginia and southwestern Pennsylvania—entered 2016 with a suspension of all drilling activity. Southwestern was averaging around seven rigs as of Oct. 23, and planned to finish 2015 by drilling 88 to 92 operated Marcellus wells.

    Marcellus first-mover Range Resources holds more than 900,000 net acres across Pennsylvania, where it expected to exit 2015 with 133 new wells hooked up to production. The Fort Worth, Texas, independent says most of its holdings offer stacked play potential for the Marcellus, Utica and Upper Devonian, which it plans to exploit with 1,000-ft and, later, 500-ft spacing.

    Cumulative Pennsylvania production included two Utica dry gas wells, the second of which delivered choke-controlled production of 13 MMcfd. A third Utica well was set for completion early this year in southwest Pennsylvania, where Range holds 400,000 net acres. “The best part of the dry core of the Utica, we believe, will be down in southwest Pennsylvania,” said Range President and CEO Jeffrey Ventura.

    Recognized as one of the lowest-cost producers in the play, with a reported average break-even cost of $2.62/Mcf, Range had not yet released its tentative rig count for this year. Despite the early performance of the Utica wells,

    Ventura said the 2016 focus will be on the Marcellus, where production averaged 1,277 MMcfgd in the third quarter, a 27% jump over the previous quarter. “We think, with those three [Utica] wells, coupled with the activity in and around us, it’ll give us a really good handle on what the Utica ultimately is,” he said. “But in the short run, you’re going to see our focus be totally on the Marcellus.”

    Elsewhere, after cutting its capital budget from $1.9 billion to $1 billion, Pittsburgh’s EQT Corp. says its 2016 plans call for drilling 72 Marcellus wells, down from around 122 drilled in 2015, and split 51-21 between its core southwest Pennsylvania and West Virginia properties. The operator also plans to drill five deep Utica wells on its combined one-million-acre leasehold in the two states.


    Despite the southwestern Pennsylvania Utica having rock characteristics and productive potential nearly identical to its “world class” fairway in and around Belmont County, Ohio, homegrown Rice Energy says it is not yet ready to jump in full bore. Rice controls 86,000 net acres in southwestern Pennsylvania and some 55,000 net acres in southeastern Ohio, where it targets the Utica..

    “The only discernible difference between the two is the more favorable pressures and depths in Pennsylvania, which are approximately 3,500 feet deeper,” says the Rice CEO, who added a caveat. “Getting up the learning curve with $20-million to $30-million wells is an expensive proposition. We think Pennsylvania Utica has the potential to eventually compete with our Marcellus and Ohio Utica returns, but this isn’t the right market to really begin its development.”

    In a more favorable price environment, the Pennsylvania Utica could become a go-to dry gas play, he suggested, pointing to a comparative pilot well that the Canonsburg, Pa., operator completed last year. The Greene County Utica prospect was designed to mimic Rice’s Bigfoot 9H crown jewel in Belmont County, including an identical 5,800-ft lateral. Even though the Bigfoot well ranks among Ohio’s most productive wells, the Rice CEO said its Pennsylvania counterpart “is shaping up to be the strongest well Rice has ever drilled, and we’re highly encouraged for what this resource could mean for Rice and our midstream business.”

    Meanwhile, Rice expected to complete the fourth quarter of 2015 with average net production of 515 MMcfgd to 540 MMcfgd, down from the 580 MMcfgd put to sales in the prior quarter. For the year, Rice expected to bring 46 net wells on-stream. The company, which plans to release its New Year guidance in February, said in late December that an unidentified energy infrastructure fund is expected to invest up to $500 million in the Rice Midstream Partners LP entity, which would help fund the independent’s 2016 capital plans.

    Last year, CONSOL Energy Inc. drilled and completed its first Utica Pennsylvania dry gas well (Gaut 41H), which tested at initial flowrates of 61.4 MMcfd. For the time being, however, CONSOL says it will concentrate on cutting down its DUC backlog.

    Also based in Canonsburg, Pa., the coal and gas producer halted new drilling in late 2015, but, in January, announced plans to drill a deep Utica test well on one of its Marcellus gas pads on Pittsburgh International Airport (PIT) property this year. The proposed well, which would replace one of the 12 Marcellus wells on CONSOL’s Pad 4 in Findley, is intended to help delineate the productive range of the Pennsylvania Utica. “We have no plans yet as to when we will test the dry Utica at PIT,” a CONSOL spokesman said. “We do have all necessary approvals in hand, however, from the local and federal authorities.”

    He added that CONSOL’s Pad 2 at PIT is scheduled to initiate production in the second quarter, while one well on nearby Pad 1 also is scheduled to be completed and turned in line during the quarter.

    CONSOL further reduced its 2016 drilling and completion expenditures by $180 million, most of which will be earmarked for a 37% reduction in its aggregate 94-well DUC inventory, including 83 uncompleted Marcellus wells. As of early January, the company planned 25 Marcellus and 10 Utica completions, spread across the estimated 614,000 net acres it controls across Pennsylvania, West Virginia and Ohio.

    Some 413,639 of those net acres are included in two 50/50 JVs with Noble Energy, which targets the Marcellus in southwest Pennsylvania and northwestern West Virginia, and Hess, which covers 68,488 acres in the more liquids-rich portion of the eastern Ohio Utica. Noble has suspended drilling, while Hess says it will lay down its single rig after the drilling of five planned wells. “It’s not economic really to want to drill wet wells today,” CONSOL CEO Nicholas Deluliis said.

    Denver’s Antero Resources has shifted its focus of late to West Virginia, where it closed 2015 with seven rigs running, which includes drilling the company’s first Utica dry gas well in the Mountain State. At 18,029 ft, MD, including a 6,620-ft lateral, the Tyler County Utica well was completed in the third quarter and flowed 20 MMcfgd on a restricted choke. Outside of West Virginia, Antero, which holds 569,000 net acres prospective for the Marcellus and Utica, spread across the three core states, also ended 2015 operating three rigs targeting the Ohio Utica.

    Antero placed 14 newly completed Marcellus wells on production in the fourth quarter, at average lateral lengths of around 7,777 ft. Elsewhere, during the fourth quarter, Antero completed and placed 16 Utica wells on production at average laterals of roughly 8,883 ft.

    Production in the Marcellus shale has averaged 1,051 MMcfed in the fourth quarter of 2015, while the Utica averaged 446 MMcfed. Antero said it curtailed about 45 MMcfd of Utica production in the fourth quarter.

    Meanwhile, after a one-year drilling hiatus, Denver’s PDC Energy says it will resume drilling in 2016, on the estimated 67,000 net acres it holds in the Utica. In December, PDC said it would spend around $34 million to drill and complete five Utica wells this year.
  • Shell’s Walkaway Budget.  As you know, Shell has been extremely busy on the cracker plant in Monaca, Beaver County, PA.  In fact, the barge facilities may be built in the near future.  

    I’ve been told that the number that’s been kicked around as the walk away budget is a $1 billion, but another source said that it’s more than that.  In other words, Shell would spend more than $1 billion and still walk away from this project.  (RUMOR)
  • Sunoco Logistics’ First Ethane Shipment.  Sunoco Logistics said the first major pipeline flowing ethane between Southwest Pennsylvania and a Philadelphia distribution center is close to full operations, one day after the first shipment of Marcellus Shale ethane left the dock for Europe.

    Mariner East 1 began flowing 70,000 barrels per day (BPD) of propane in December 2014, and ethane last month. The first large shipment to Europe, aboard the Ineos Intrepid ship, left the Marcus Hook facility Wednesday bound for Norway.

    Mariner East 2, an expansion of the Mariner East system with origin points in Ohio, West Virginia and Western Pennsylvania, will add additional off-take points for propane shippers in Central and Eastern Pennsylvania.

    The pipeline is projected to be completed in the first half of 2017 and will add an additional 275,000 BPD capacity of natural gas liquids, primarily propane and butane, from both the Marcellus and Utica shales, Kallanish Energy understands.

    Mariner East 2 will provide both interstate service and intrastate service within Pennsylvania and has the potential to expand to 450,000 BPD.
  • Hillary’s an Anti-Fracker.  In her effort to be the ultimate socialist, she’s came out during the debate to say that she’s going to stop fracking.  Let’s hope the FBI does its job with her emails.
  • Shale Oil Production Steady in the Bakken and Eagle Ford.  Production from shale oil plays in North Dakota and Texas dropped slightly in January from December, according to Platts Bentek, an analytics and forecasting unit of Platts.

    Oil production from the Eagle Ford in South Texas was relatively unchanged in January, falling roughly 11,000 barrels per day (BPD), or less than 1%, vs. the previous month’s output, Kallanish Energy learns.

    February’s results mark the sixth month since June 2015, the Eagle Ford play has trended down.

    Similarly, crude oil production in the North Dakota section of the Bakken formation of the Williston Basin dipped slightly, down 12,000 BPD, or just over 1%, on a month-over-month basis.

    Average crude production from the Eagle Ford in January was 1.4 million barrels per day (MMBPD), according to Platts Bentek.

    On a year-over-year basis, that was down about 200,000 BPD, or roughly 13%, from January 2015, according to Platts Bentek energy analyst Sami Yahya.

    Average crude production from the North Dakota section of the Bakken in January was 1.2 MMBPD, about 3% lower than year ago levels, he said.

    “Current internal rates of return in both the Eagle Ford and Bakken shales are weak, under 10%,” Yahya said. “Producers need to continue generating cash flow for their operations. The number of active rigs in those basins has gotten so low it’s almost a certainty producers are dipping into their inventory of drilled but uncompleted wells. Those wells are cheaper to complete since the drilling costs are already sunk.”

    Yahya pointed to Platts/Bentek analysis on drilled but uncompleted (DUC) wells for many of the major shale basins. According to the results, current DUC inventories total 831 wells in the Williston Basin, while in the Eagle Ford, there are roughly 1,022 wells awaiting completion.

    These figures refer to wells drilled between early 2014, and roughly last October.

    “A number of major producers [outside the Northeast] have stated they will reduce capital spending and cut their drilling programs significantly in some instances,” Yahya said. “Those producers will have to complete their DUCs in order to sustain their production levels. Efficiency gains are not enough anymore to help keep production volumes afloat.”
  • MPLX’s Cornerstone Pipeline Update and More.  The right of way is clear and construction is set to begin in March on MPLX’s Cornerstone Pipeline to make the projected late 2016 in-service date.

    MPLX’s Cornerstone Pipeline

    The batched pipeline system stretches 50 miles from the MarkWest Energy Partners condensate stabilization facility near Cadiz, Ohio, and the Utica East Ohio fractionation facility and condensate stabilization facility near Scio, Ohio, to a Marathon Pipe Line LLC (MPL) operated tank farm in East Sparta, Ohio and to Marathon Petroleum Company LP’s (MPC) refinery in Canton, Ohio.

    First announced in 2014, the Cornerstone Pipeline is one of several pipeline systems MPLX has planned to move petroleum products throughout the burgeoning Marcellus and Utica shale plays.

    MPC formed MPLX, a master limited partnership, in 2012 to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. MPLX’s assets includes approximately 2,900 miles of pipeline across nine states and in 2015, MPLX acquired MarkWest Energy Partners.

    “The Cornerstone Pipeline, like other pipeline projects, has both short and long term economic impacts. During the construction phase of the project, hundreds of skilled tradesmen from around the region will not only earn income, they will spend a portion of their earnings at local businesses,” says Jason Stechschulte, senior engineer, commercial development, MPL, a subsidiary of MPLX. “Also MPL has already begun to hire additional local staff to run and maintain the daily operations of the pipeline. Furthermore, pipeline movements are more cost effective than movements by truck or rail, so adding a low-cost means for producers to move products to customers creates a long-term competitive advantage.

    That advantage could help the producers in the region justify future development resulting in employment growth and higher local tax revenues.”

    MPL is adding capacity at the East Sparta tank farm in conjunction with this project. A project is also in the works to connect the MarkWest fractionation facility, near Hopedale, Ohio, to the Cornerstone Pipeline.

    “The Cornerstone Pipeline provides the initial backbone for transportation of Utica shale condensate, natural gasoline and diluent,” Stechschulte says. “Because the Cornerstone Pipeline is a batched system, movements of each commodity type will be scheduled daily from each location.”

    MPLX can provide the same quality of service from a single, larger pipeline, versus multiple smaller pipelines.

    “The Cornerstone Pipeline has been sized as a 16-in. diameter system to provide ample capacity for Utica shale volumes,” Stechschulte says. “This provides MPL with future connectivity options within the Utica shale for the pipeline.”

    Associated with the Cornerstone Pipeline are MPLX’s proposed Utica Build-Out pipeline projects. The Utica Build-Out projects have a planned operational in-service date in 2017. From East Sparta, MPL is expanding several existing pipelines from East Sparta to Heath, Ohio, and Heath to Findlay, Ohio. A new pipeline is planned from Harpster, Ohio, to Lima, Ohio. Additionally, MPL is reversing an existing pipeline from Lima to Robinson, Illinois.

    MPLX Utica Build-Out Projects

    “These projects provide pipeline transportation to additional markets for Utica volumes,” Stechschulte says. “These projects connect many of the Midwestern refineries to the Utica shale production and additionally provide the ability to supply diluent to western Canada.”

    MPLX has refined scheduling and scoping on the Utica Build-Out projects as the company finds synergies as a result of the MarkWest acquisition.

    “Connection of the Hopedale fractionation facility to the Cornerstone Pipeline is a great example of synergistic value for MPLX,” Stechschulte says. “MarkWest is producing and marketing natural gasoline from this location every day and through the connection to the Cornerstone Pipeline, it will have a pipeline transportation option that is well connected to multiple markets.”

    He adds that MarkWest’s operations geographically complement MPC’s and MPLX’s operations particularly in the Marcellus and Utica shale plays where MarkWest has established itself as a leader in gathering and processing.

    As for other projects on the horizon, MPLX continually evaluates the market conditions and meets regularly with potential pipeline shippers. The company’s assets provide connectivity to the Enbridge, Southern Lights diluent pipeline via existing pipelines. MPLX is also exploring a potential connection to the Kinder Morgan Cochin Pipeline, for diluents.
  • Utica Shale NatGas and Oil Production Still Increasing.  Natural gas production from Ohio’s horizontal wells grew by almost 25 percent from third quarter 2015 to fourth quarter 2015 and oil production jumped by 10 percent in that time, according to new production data released on Wednesday  by the Ohio Department of Natural Resources.

    Natural gas volumes in the quarter totaled nearly 303 billion cubic feet and oil production totaled nearly 6.25 million 42-gallon barrels, said ODNR’s Division of Oil and Gas Resources Management.

    Natural gas production from 2014 to 2015 grew by 110.6 percent and oil production grew by 99.9 percent in that time, according to the new report.

    Natural gas totals jumped from 452.8 billion cubic feet in 2014 to 953 billion cubic feet in 2015, the report says.

    Oil totals increased from nearly 11 million barrels in 2014 to 21.98 million barrels in 2015.

    Quarterly production of natural gas increased by 80 percent from fourth quarter 2014 and oil production increased by more than 75 percent in that time, the data says.

    The production comes at a time when new drilling is falling off as drillers pull back because of low commodity prices.

    But the Utica Shale in eastern Ohio remains one of the more active drilling areas. The U.S. Energy Information Administration says natural gas production is likely to drop in April  in six of seven shale drilling areas in the country.

    Only the Utica Shale is expected to increase. Oil production in the Utica Shale and the Marcellus Shale in Pennsylvania and West Virginia are expected to stay level. The rest will be declining in April, the federal agency says.

    The latest Ohio report covers data from 1,265 Utica Shale wells, of which 1,230 reported production. A total of 35 wells reported no production.

    To date, Ohio has approved 2,140 Utica Shale permits. Of that total, 1,693 Utica wells have been drilled and 1,240 Utica wells are producing.

    The average Ohio horizontal well produced 5,081 barrels of oil and 245.9 million cubic feet of natural gas in the fourth quarter 2015. The average well was in production for 83 days.

    The Top 5 Ohio counties for natural gas in the fourth quarter were Belmont with 85.8 billion cubic feet, Carroll with 59.4 billion, Monroe with 49.3 billion, Harrison with 44.8 billion and Noble with 33.9 billion.

    The Top 5 Ohio counties for oil were Harrison with 2.4 million barrels, Guernsey (1.5 million), Carroll (1.4 million), Noble (628,100) and Belmont (92,679).

    The Top 3 natural gas wells in the fourth quarter were three Mohawk Warrior wells owned by Rice Drilling LLC in Belmont County. No. 1 was Mohawk Warrior 12H with 16.2 billion cubic feet of natural gas in the quarter.

    The Top 3 oil producers in the quarter were Red Hill Farms wells owned by Ascent Resources in Guernsey County. No. 1 was the well with 59,502 barrels of oil in the quarter.

    The Top 5 Ohio drillers are: Chesapeake Energy, 588 wells; Gulfport Energy, 165 wells; Antero Resources, 120 wells; Ascent Resources, 83 wells.; and Eclipse Resources, 54 wells.

    Ohio does not require a separate reporting of natural gas liquids like ethane, butane and propane or condensate, a type of oil.

    The NGLs are part of the natural gas total. The condensate is part of the oil total.
  • Chevron Focusing on Shale in the Permian; Increasing Rig Count.  Chevron plans to focus on shorter-cycle investments in West Texas shale plays after its larger, long-term investments come into production this year.

    By the end of the decade, Chevron believes it can nearly triple its oil production in the Permian Basin by increasing its rig count from seven to 14.

    “Don’t be surprised if by the middle of the next decade 20 to 25 percent of our production is in this short-cycle shale and tight activity,” Chairman and CEO John Watson said in an annual investors update.

    The San Ramon-based oil company said it plans on doubling its spending in West Texas. Chevron has 1,300 drilling locations in the Permian that can turn a profit if oil reaches $40 per barrel. At $50, Chevron has 4,000 profitable locations. Chevron also has 5,500 profitable locations if oil sells at $60.

    Officials said the company will drill 175 wells this year with seven operated rigs and nine non-operated rigs. The company projects an output of 350,000 barrels a day by 2020 from the Permian Basin. Chevron currently produces 125,000 barrels a day from Permian shale.

    Increased efficiency has helped Chevron weather low oil prices. In the past year, Chevron said its cost to drill a horizontal well dropped to $7.1 million, a 40 percent drop. It now takes 20 days to drill a well, less than half the time it did before. Returns from the Permian Basin have increased by 30 percent.

    Though the company has become more efficient, it still plans to cut up to 25 percent of its upstream work force this year. That means about 4,000 jobs will be eliminated in 2016. Last year, Chevron slashed 3,000 jobs as oil prices neared 11-year lows.

    The San Ramon-based company expects to boost total production to nearly 3 million barrels a day in 2017.

    “We’re in a fairly unique position in the industry,” Watson said. “We’re cutting spending pretty dramatically, but we’re going to see higher volumes.”
  • Shale’s Best Days Are Yet to Come. (Some excerpts from my “Brain Trust” op-ed in today’s Investor’s Business Daily) The average cost of a gallon of gasoline in the U.S. has been below $2 most of this year — the lowest prices in almost a decade. Oil prices — hovering at $30 a barrel for the last few months — are wreaking havoc on producers around the world, but the pain has been particularly sharp here in the U.S. Many of our oil companies — the very companies that helped launch the shale revolution — are teetering on bankruptcy. Others that are somewhat better off are trying to maintain investor confidence by promising to more or less hibernate.

    Does this grim news mean that the gains of the shale revolution — increased U.S. energy security, stronger economic growth and a less powerful OPEC — will be lost? Far from it. It may be hard to see through the storm, but the U.S. shale industry’s best days are likely still ahead. Although Saudi Arabia still plays a central role in the global oil marketplace, America’s shale producers have broken OPEC’s ability to manipulate the market as it has since the 1970s.

    In 2008, U.S. crude oil production had fallen to only 5 million barrels a day, a drop of almost 50% from the peak production of 9.6 million in 1970 and down to the lowest level of domestic crude output in more than 60 years, going all the way back to 1946 (see chart above). But then the revolutionary drilling technologies of hydraulic fracturing and horizontal drilling sparked the great American shale revolution, and the abundance of domestic shale oil quickly reversed the 36-year decline in U.S. output in only seven years.

    Thanks to the bonanza of shale resources in states like Texas and North Dakota, U.S. crude oil output last year surged to a near-record 9.34 million barrels a day as “Saudi America” re-emerged as a world energy superpower. In response, the International Energy Agency recently said, “In 2016, we are living in perhaps the first truly free oil market we have seen since the pioneering days of the industry.”

    Producers here and overseas are pumping out as much oil as they can to maintain market share. As the Saudis have slowly recognized, any attempt to cut production and prop up prices would only allow rivals — namely shale producers — to pump more, fill the void in the market and then push prices back down. This is, at least in the short term, fantastic news for consumers. Oil will likely stay cheap, and motorists are going to continue to benefit from significant savings at the pump.

    For shale producers, today’s dirt-cheap oil prices are transforming the business into a leaner, more nimble and more resilient industry. Many companies that ramped up operations and built business models around $100-per-barrel oil are now remaking themselves into operators capable of not only surviving but growing with oil at $50 a barrel or even less.

    America’s shale oil industry, though down for now, has a pretty good model for recovery — domestic shale-gas production. After natural gas prices collapsed in 2008 by more than 75%, shale-gas drillers adopted more efficient methods of drilling and extracting shale gas. Since then, natural gas production has increased and drilling rig productivity has grown by leaps and bounds. New gas wells in the Marcellus shale are a case in point. A newly drilled well in February

    2014 produced, on average, 6.3 million cubic feet of natural gas per day. In February of this year, productivity for newly drilled gas wells rose to more than 9 million cubic feet of gas per day.

    Gas drillers have learned how to produce more with less. They get more gas out of each rig, drill faster and smarter, and have become competitive even in a low-price environment. Oil producers are now following in their footsteps. Make no mistake, the shale revolution is here to stay. The vast shale resources unlocked over the past decade aren’t going to disappear, no matter how much the Saudis wish they would. American shale producers have proven capable of rapid and often unexpected technological innovation and problem-solving.

    As OPEC has already found out, it’s a fool’s errand to bet against America’s petropreneurs.
  • NatGas Surpasses Coal in Electricity Generation.  Natural gas is projected to fuel 33% of U.S. power generation in 2016 – one percentage point higher than coal, and the first time gas provides more electricity generation on an annual average basis, the latest Short-Term Energy Outlook states.

    In 2017, natural gas and coal are both forecast to fuel 32% of electricity generation, according to the March STEO, a U.S. Energy Information Administration (EIA) publication.

    For renewables, the forecast share of total electricity generation supplied by hydropower rises from 6% in 2016, to 7% in 2017, and the forecast share for other renewables increases from 8% in 2016, to 9% in 2017.

    EIA’s forecast of U.S. total natural gas consumption averages 76.8 billion cubic feet per day (Bcf/d) in 2016, and 77.3 Bcf/d in 2017, compared with 75.3 Bcf/d in 2015, Kallanish Energy reports.

    Total consumption for 2016 in this month’s STEO was revised upward by 0.5%, driven by increasing expectations of natural gas use in the electric power sector (see above).

    “Forecast electric power sector use of natural gas increases by 3.0% in 2016, then declines by 1.7% in 2017, as natural gas prices rise,” STEO states.

    “Forecast industrial sector consumption of natural gas increases by 2.9% in 2016, and by 2.2% in 2017, as new projects in the fertilizer and chemicals sectors come online.”

    In December, total marketed production of natural gas averaged 78.7 Bcf/d, a 0.4% decline from the November level. Production in the Marcellus Shale play states (Pennsylvania, Ohio, and West Virginia) increased from the previous months, partially offsetting declines in Texas, Louisiana, and western states.

    EIA survey data found natural gas production averaged 78.9 Bcf/d in 2015, an increase of 4.0 Bcf/d (5.4%) from 2014. STEO projects growth will slow to 0.9% in 2016, as low natural gas prices and declining rig activity begin to affect production.

    In 2017, however, forecast production growth increases to 2.1%, as forecast prices rise, industrial demand grows, and liquefied natural gas (LNG) exports increase. EIA expects U.S. natural gas production growth in the forecast period will reduce demand for natural gas imports from Canada and will support growth in exports to Mexico.

    EIA expects natural gas exports via pipeline to Mexico to increase because of growing demand from Mexico’s electric power sector coupled with flat natural gas production in Mexico. EIA projects LNG gross exports will increase to an average of 0.5 Bcf/d in 2016, with the startup of Cheniere’s Sabine Pass LNG liquefaction plant in Louisiana, which sent out its first cargo in February. EIA projects gross LNG exports will average 1.3 Bcf/d in 2017, as Sabine Pass ramps up its capacity.

    Natural gas working inventories totaled 2.54 trillion cubic feet (Tcf) on Feb. 26, 46% higher than during the same week last year, and 36% higher than the previous five-year average (2011–15) for that week, STEO said.

    “EIA forecasts that inventories will end the winter heating season [March 31] at 2.29 Tcf, which would be 54% above the level at the same time last year,” the STEO projects. “Henry Hub spot prices are forecast to average $2.25/million British thermal units [MMBtu] in 2016, and $3.02/MMBtu in 2017, compared with an average of $2.63/MMBtu in 2015,” according to STEO.
  • Halliburton’s EU Decision Date Has Been Set.  The European Union (EU) antitrust arm, the European Commission (EC), has resumed its investigation into U.S. oilfield services company Halliburton’s proposed takeover of smaller rival Baker Hughes, Kallanish Energy learns.

    The EC said Tuesday it received further information from both companies and a competition decision will be made by July 11. The previous deadline for the investigation outcome was June 23, but the clock on a review was stopped due to missing “important information.”

    Reuters reported Halliburton is likely to submit a package of concessions shortly to address regulatory concerns about possible price hikes and less innovation following the merger.

    Halliburton agreed to buy Baker Hughes in November 2014 in a cash-and-stock deal that at the time was valued at about $35 billion. The transaction was scheduled to close last year, but has been delayed as the companies seek to resolve antitrust concerns in the U.S. and Europe.

    The deal has received clearance from antitrust regulators in Canada, Colombia, Ecuador, Kazakhstan, South Africa and Turkey.

    U.S. crude oil production averaged an estimated 9.4 million barrels per day (MMBPD) in 2015, and is forecast to average 8.7 MMBPD in 2016, and 8.2 MMBPD in 2017, the March Short-Term Energy Outlook (STEO), produced by the U.S. Energy Information Administration.
  • EIA Projects Decline in Oil Production.  STEO/EIA estimates crude oil production in February averaged 9.1 MMBPD, 80,000 BPD below the January level, the March STEO reveals.

    Forecast U.S. consumption increases by 0.1 MMBPD in 2016, and by 0.2 MMBPD in 2017, Kallanish Energy reports.

    “With WTI prices currently below $40 per barrel (Bbl) and projected to remain below that level through the first half of 2017, EIA expects oil production to decline in most Lower 48 onshore oil production regions,” the STEO reports.

    The expectation of reduced cash flows in 2016 and 2017 has prompted many companies to scale back investment programs, deferring major new projects until a sustained price recovery occurs, according to STEO.

    Lower onshore investment is anticipated to reduce the count of oil-directed rigs and well completions in 2016 and 2017. The focus of drilling and production activities will be on the core areas of major tight oil plays.

    In these areas, falling costs and ongoing technological and process improvements in rig, labor, and well productivity are anticipated to lead to faster rates of well completions and less-rapid production declines relative to other Lower 48 onshore areas.

    Production is expected to begin increasing modestly in the fourth quarter of 2017, as productivity improvements, lower breakeven costs, and anticipated oil price increases are expected to end more than two years of declines in the Lower 48 States.

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Rig Count

  • Baker Hughes Rig Count the week of March 11, 2016
  • PA
    • Marcellus 19 up 3
  • Ohio
    • Utica 11 down 1
  • WV
    • Marcellus 12 unchanged
  • TX
    • Eagle Ford – 43 down 3
  • TX & NM
    • Permian Basin – 152 down 6
  • ND
    • Williston – 32 down 1
  • CO
    • Niobrara – 17 unchanged
  • TOTAL U.S. Land Rig Count 450 down 13

PA Permits for February March 3, to March 10,  2016

        County               Township         E&P Companies

1.    Armstrong            South Buffalo     MDS Energy
2.    Armstrong            South Buffalo     MDS Energy
3.    Armstrong            South Buffalo     MDS Energy
4.    Armstrong            South Buffalo     MDS Energy
5.    Butler                   Donegal            XTO
6.    Greene                 Franklin            Vantage
7.    Sullivan                Fox                  Chief
8.    Sullivan                Fox                  Chief
9.    Susquehanna       Auburn              Cabot
10.    Susquehanna     Auburn              Cabot
11.    Susquehanna      Harford             Chief
12.    Washington        Independence    Range
13.    Washington        Independence    Range
14.    Westmoreland    Sewickley         Chevron
15.    Westmoreland    Sewickley         Chevron

OH Permits for week ending March 3, 2016

       County        Township  E&P Companies

1.    Belmont        York        Gulfport
2.    Belmont        York        Gulfport
3.    Belmont        York        Gulfport
4.    Belmont        York        Gulfport
5.    Belmont        York        Gulfport
6.    Belmont        York        Gulfport
7.    Monroe        Wayne      Gulfport
8.    Monroe        Wayne      Gulfport

Joe Barone 610.764.1232
Vera Anderson 570.337.7149

Northeast Supply Enhancement