The U.S. Energy Information Administration (EIA) estimated that in 2017 about 4.67 MMbbl/ d of crude oil was produced directly from tight oil resources in the U.S. “This was equal to about 50% of total U.S. crude oil production in 2017,” according to the EIA’s website. In addition, the EIA estimated that in 2017 about 16.86 Tcf of dry natural gas was produced from shale resources in the U.S., which was about 62% of total U.S. dry natural gas production that year.
The EIA later reported in November 2018 a total of 5,372 bbl/d of new well oil production and 42,042 Mcf/d of gas production in the Anadarko, Appalachia, Bakken, Eagle Ford, Haynesville, Niobrara and Permian regions.
Looking ahead, the EIA predicts that U.S. crude oil production will average 12.1 MMbbl/d in 2019, according to its November “Short-term Energy Outlook.”
The Permian, Eagle Ford, Bakken/Niobrara, Marcellus- Utica and Midcontinent regions feature the most robust and soaring production numbers. In the following section, Hart Energy profiles some of the most active operators in these five unconventional U.S shale plays, highlighting their first-half 2018 results.
Editor’s Note: These profiles were written based on second- and third-quarter 2018 reports.
Anadarko Petroleum Corp.
Anadarko’s U.S. onshore operations are located in Colorado, Texas, Utah and Wyoming. The company’s second-quarter 2018 sales volumes of oil, natural gas and NGL totaled 58 MMboe, or an average of 637,000 boe/d, according to Anadarko’s second-quarter results news release. In the Delaware Basin of West Texas, the company’s oil production averaged 62,000 bbl/d of oil for the second quarter, which was an 88% increase over the second quarter of 2017. During this quarter the company also announced a successful startup of the Reeves Regional Oil Treating Facility (ROTF) in May as well as a record number of wells turned to sales. The company also advanced its first full pad development at the Silvertip-A location in Loving County, Texas, where it completed 12 extended-reach lateral wells targeting multiple intervals in the Wolfcamp-A Formation. These wells were expected to begin producing in the second half of the year and will flow to the recently commissioned North Loving ROTF, according to the release. In the Denver-Julesburg (D-J) Basin of northeast Colorado, Anadarko continues its horizontal drilling campaign featuring natural-gas-powered rigs and noise-reduction technology. During the second quarter, the D-J Basin averaged net production of 261,000 boe/d, the release stated. Anadarko also is looking at other onshore opportunities in Wyoming’s Powder River Basin, where the company said it has made about $100 million worth of leasehold acquisitions and amassed more than 300,000 acres for less than $2,500 per acre, according to Anadarko CEO Al Walker on an Aug. 1 earnings call. The company is focused on the Turner Formation, having already drilled wells in the play with rates exceeding 2,000 boe/d and oil cuts above 80%, according to Walker.
Antero Resources Corp.
Antero operates in the Marcellus and Utica shales. In the Marcellus Antero has more than 486,000 net acres of leasehold located in northern West Virginia and southwestern Pennsylvania, and the company is operating five drilling rigs in West Virginia, according to Antero’s website. During the second quarter of the year, Antero placed 25 horizontal Marcellus wells to sales and drilled 22 wells in the Marcellus with an average lateral length of 9,600 ft in approximately 12 total days from spud to final rig release on average, according to the company’s second-quarter 2018 results report. Antero also set a state of West Virginia record for the longest lateral drilled to date at 15,100 ft during the second quarter. As of Aug. 1, Antero expected to place 50 to 60 Marcellus wells to sales during the third quarter of the year, including the company’s largest pad to date, a 14-well pad that commenced production in July, the report stated. Antero expected an average of four crews operating during the second half of the year, compared to six crews in the first half. Antero has more than 137,000 net acres of leasehold in eastern Ohio in the Utica Shale, where the company operated one drilling rig during the first half of the year, according to its website. Antero placed five horizontal Ohio Utica wells to sales during the second quarter and expected to place 15 wells to sales in the Utica during the third quarter, according to its second-quarter report. The company’s five-year plan does include the resumption of drilling and completion activity in the Ohio Utica Shale in 2019. As of Aug. 1, the company stated in the report that it “does not plan to operate any drilling rigs or completion crews during the remainder of 2018 as the second-half 2018 development plan shifts to liquids-rich locations in the Marcellus due to the continued strength in liquids pricing.”
Apache’s U.S. operations are in the Permian Basin, with more than 2.8 million gross acres, and in the Midcontinent/Gulf Coast region, which includes more than 1.8 million gross acres. Apache reported year-end 2017 Permian production of 681 MMboe estimated proved reserves. In 2017 the Permian region averaged 16 rigs and drilled or participated in 215 wells, 158 of which were horizontal, with a 97% success rate, according to the company’s website. Apache stated it had “plans to continue an elevated level of activity in the Permian region during 2018, while continuing to balance capital investments between its larger development project at Alpine High and focused exploration and development programs on other core assets in its Permian region.” During 2018 the company expected “to average approximately 14 drilling rigs, which includes six to seven rigs at Alpine High focused on a combination of retention, development and delineation drilling. Approximately $1.6 billion, or roughly two-thirds, of the company’s 2018 capital upstream budget will be allocated to the Permian region.” Second-quarter 2018 Permian highlights included 89,928 bbl/d oil production, 134,621 bbl/d total liquids production and 201,832 boe/d. The company’s Midcontinent/Gulf Coast region includes primarily western Oklahoma, the Texas Panhandle and the Eagle Ford Shale in East Texas. Apache has more than 3,100 producing wells in the region. “In 2018 Apache plans to run a targeted program, drilling additional wells in the Woodford-Scoop play. In addition, the region will continue its focus on high grading acreage and building its inventory of future drilling locations,” the company stated on its website. Second-quarter 2018 Midcontinent/Gulf Coast highlights included 11,492 bbl/d oil production, 25,542 bbl/d total liquids production and 48,147 boe/d.
In the third quarter, BHP Billiton sold its onshore U.S. assets to BP. The $10.5 billion sale of BHP’s interests in the Eagle Ford, Haynesville and Permian- Delaware oil and gas assets to BP America Production Co., a subsidiary of BP Plc, closed Oct. 31. These acquired assets produce 190,000 boe/d, of which about 45% are liquid hydrocarbons, according to BP’s website. BHP’s “operated rig count remained unchanged at five, with two rigs at Eagle Ford, two rigs at Permian and one at Haynesville,” according to BHP’s third-quarter 2018 results report. In Wyoming’s Wamsutter Field, BP is the largest operator with about 2,000 wells. Moreover, the company “recently [as of Oct. 18] launched a separate pilot project in which it teamed up with a Silicon Valley firm and applied a mathematical model to optimize production at 180 onshore wells in Wyoming,” according to BP’s “U.S. Economic Impact Report 2018.” “This led to a 75% reduction in venting emissions events, a 20% increase in production and a 20% reduction in costs,” the report stated. The company expected the project to expand to more than 2,000 onshore wells by the end of the year. BP also operates about 800 oil and gas wells in the East Texas Basin and about 1,200 wells in the Texas Panhandle. The company has an interest in another 1,500 wells in the South Texas Eagle Ford Shale through its joint venture with Lewis Energy, according to information on BP’s website. In addition, BP is the largest operator in Colorado and operates 1,350 wells in the area. The company also has about 2,600 operated and 5,100 nonoperated wells in the New Mexico portion of the San Juan Basin, and it brought five Mancos Shale horizontal wells online in New Mexico this year.
Cabot Oil & Gas Corp.
Cabot’s E&P and development operations are focused in the Marcellus Shale in northeastern Pennsylvania, with about 172,000 net acres, primarily in Susquehanna County. “Cabot’s 2018 capital budget is approximately $950 million with approximately 84% of spending focused on the Marcellus Shale and up to $75 million of exploratory leasing/testing capital,” the company stated on its website. “For the full year 2018, the company plans to drill approximately 85 net wells and complete 95 net wells.” As of Oct. 22, the company was operating three rigs and two completion crews in the Marcellus Shale. “Daily equivalent production for the sixmonth period ending June 30, 2018, was 1,890 MMcfe/d (99% natural gas),” according to Cabot’s second-quarter 2018 results report. The company expected to place 37 net wells on production in the third quarter. In addition, in February Cabot sold its operated and nonoperated Eagle Ford Shale assets to an affiliate of Venado Oil & Gas LLC for $765 million, according to a press release. The divestiture included about 74,500 net acres (about 65,100 operated and about 9,400 nonoperated) of Eagle Ford Shale leasehold primarily located in Frio and Atascosa counties in Texas.
Centennial Resource Development Inc.
Centennial Resource Development has about 80,100 net acres (100% operated) and 2,400 drilling locations (60% oil) in the Delaware Basin. The independent oil producer recently made a shift from one-well operations to multiwell pad developments and reported the following IP results in its second-quarter 2018 results report. The Red Rock A Unit T09H well achieved a 30-day IP rate of 1,578 boe/d, with 1,143 bbl/d of oil. The Red Rock A Unit U04H well reported a 30-day IP rate of 1,268 boe/d, with 940 bbl/d of oil. The CWI Long A U31H, B U40H and C U49H wells achieved 30-day IP rates of 2,158 boe/d (78% oil), 2,899 boe/d (78% oil) and 2,278 boe/d (78% oil), respectively. The three-well pad delivered an average 30-day oil IP rate of 194 bbl/d per 1,000 ft of lateral per well. The Ninja 4-50 49 2H, 3H, 4H and 5H wells delivered an average 30-day IP rate of 1,878 boe/d (58% oil) per well. During its 60-day IP period, the pad produced more than 225,000 bbl of oil. In addition, the Balmorhea State G 8H, H 9H and I 10H wells each began production at an average 30-day IP rate of 1,337 boe/d (77% oil) per well, or 166 bbl/d of oil per 1,000 ft of lateral per well.
Chesapeake Energy Corp.
Chesapeake Energy has operations in Louisiana, Ohio, Oklahoma, Pennsylvania, Texas and Wyoming. Chesapeake’s average production for the second quarter was about 530,000 boe/d, compared to about 528,000 boe/d a year earlier, according to the company’s second-quarter 2018 results report. “The Powder River Basin in Wyoming is quickly establishing itself as the growth engine of the company, as recently demonstrated by a 78% increase in net production compared to the average fourth-quarter 2017 rate,” the company stated in the report. “On July 22, 2018, total net production hit a new record of approximately 32,000 net boe per day (42% oil, 41% natural gas and 17% natural gas liquids), compared to an average fourth-quarter 2017 rate of 18,000 boe per day.” The company expected Powder River Basin net production to reach about 38,000 boe/d by the end of the year and total net annual production to more than double in 2019. In the Eagle Ford Shale, Chesapeake was utilizing four rigs (as of Aug. 1). The company placed 48 wells on production during the second quarter and expected to place 38 wells on production during the third quarter and 47 wells during the fourth quarter, according to the report. In the Marcellus Shale, the company has 400,000 acres and is one of the largest producers of natural gas in Pennsylvania, according to a company fact sheet. As of Aug. 1, Chesapeake was utilizing three rigs in the Marcellus and placed 10 wells on production during the second quarter. In addition, the company expected to place 14 wells on production during the third quarter and 18 wells during the fourth quarter, according to the company’s second- quarter report. In July “Chesapeake successfully drilled its longest lateral to date in the Lower Marcellus Shale at approximately 13,380 ft, only to be surpassed by an even longer planned lateral of approximately 14,500 ft currently being drilled,” the report stated. “Both wells are expected to be placed on production before year-end 2018.” Chesapeake announced in July that it entered into an agreement to sell its interests in the Utica Shale for about $2 billion to Encino Acquisition Partners. The transaction was expected to close by the end of the year. On Oct. 30, Chesapeake announced its intent to acquire WildHorse Resource Development Corp. The transaction is expected to close in the first half of 2019.
Chevron is one of the largest producers of oil and natural gas in the Permian Basin as well as one of the largest net acreage holders in the area with about 2.2 million net acres. The company holds about 500,000 total acres in the Midland Basin and has about 1 million total acres in the Delaware Basin, according to a company fact sheet. The company reported production of 119,000 net bbl/d of crude oil, 383 MMcf/d of natural gas and 45,000 bbl/d of NGL in 2017. “Production increases from shale and tight properties in the Permian Basin in Texas and New Mexico were partially offset by the impact of asset sales of 54,000 bbl/d,” the company stated in its second-quarter 2018 results report. “The net liquids component of oil-equivalent production in second-quarter 2018 increased 8% to 575,000 bbl/d, while net natural gas production decreased 5% to 980 MMcf/d.”
Cimarex Energy Co.
Cimarex has operations in Texas, Oklahoma and New Mexico with focuses on the Midcontinent and Permian Basin. The company invested $1.28 billion for exploration and development activities in the Permian and Midcontinent regions in 2017 and expected to invest $1.6 billion to $1.7 billion in these areas during 2018, according to Cimarex’s website. In the Permian region, production averaged 121,744 boe/d, and oil volumes averaged 48,797 bbl/d, according to Cimarex’s second-quarter 2018 results report. Cimarex completed 32 gross (13 net) wells in the Permian region during the second quarter, and there were 45 gross (32 net) wells waiting on completion as of June 30. Cimarex was operating 10 drilling rigs and five completion crews in the region as of Aug. 7. In addition, Cimarex closed on the sale of assets in Ward County, Texas, on Aug. 31 for $544.5 million. In the Midcontinent region, production averaged 88,864 boe/d for the second quarter, according to the report. Also during the second quarter, Cimarex completed 57 gross (10 net) wells in the region. At the end of the quarter, 96 gross (25 net) wells were waiting on completion. Cimarex was operating three drilling rigs and one completion crew in the region as of Aug. 7. Moreover, the company expected overall third-quarter production volumes to average 206,000 boe/d to 215,000 boe/d with oil volumes estimated to average 61,500 bbl/d to 64,500 bbl/d, according to the report. The total 2018 production volumes are expected to average 214,000 boe/d to 221,000 boe/d with annual oil volumes estimated to average 66,000 bbl/d to 68,000 bbl/d.
CNX Resources Corp.
CNX Resources’ operations are in the Appalachian Basin. In the second quarter, the company operated three horizontal rigs and deployed a fourth in late June, and those horizontal rigs drilled 16 wells. CNX also utilized three fracturing crews to complete 18 wells, and it set a company record of completing 78,877 ft, or 394 stages, in May, according to the company’s second-quarter 2018 results report. Three Marcellus Shale wells were turned in-line in Washington County, Pa., in the second quarter, and CNX expected to turn in-line about 30 wells in the third quarter. Marcellus Shale volumes, including liquids, in the second quarter were 64.7 Bcfe. In addition, water disposal costs improved during the second quarter, compared to the previous quarter, as the company reused more produced water for fractures, avoiding the need to send that water to disposal, the company stated in the report. Utica Shale volumes, including liquids, in the second quarter were 42.6 Bcfe, approximately 209% higher than the 13.8 Bcfe the same period a year earlier, driven primarily from Monroe County, Ohio, volumes. CNX Resources sold substantially all its Ohio Utica joint venture assets to Ascent Resources-Utica LLC on Aug. 31 for approximately $400 million, a press release stated.
Concho operations are focused on the Permian Basin. The company reported production of 21 MMboe and 515 MMcf/d natural gas and averaged 21 rigs in the second quarter, according to Concho’s second-quarter 2018 results report. In July Concho acquired RSP Permian Inc., making Concho the largest unconventional shale producer in the Permian Basin, according to a company press release. In the Northern Delaware Basin, Concho added 16 wells with at least 60 days of production (as of the end of June). The average 30-day and 60-day peak rates for these wells were 1,987 boe/d (73% oil) and 1,859 boe/d (72% oil), respectively, according to the second-quarter report. Drilling activity in this area is focused on largescale development of the company’s assets, with nine out of 16 rigs working on multiwell projects. “The largest project underway is the Dominator, which consists of 23 wells targeting five distinct landings within a single section. Concho is currently [as of Aug. 1] running six rigs on this project,” the report stated. In the Southern Delaware Basin, Concho added five wells with at least 60 days of production (as of the end June). The average 30-day and 60-day peak rates for these wells were 1,463 boe/d (80% oil) and 1,297 boe/d (80% oil), respectively, according to the report. In the Midland Basin, Concho added 21 wells with at least 60 days of production (as of the end of June). The average 30-day and 60-day peak rates for these wells were 1,294 boe/d (86% oil) and 1,137 boe/d (86% oil), respectively, the report stated. As of Aug. 1, Concho expected third-quarter production to average 280,000 boe/d to 285,000 boe/d (65% oil) and full-year 2018 production to average 260,000 boe/d to 263,000 boe/d (64% oil), according to the report.
ConocoPhillips’ onshore Lower 48 segment, which covers the Gulf Coast, Midcontinent and Rockies, holds 10.4 million net acres (mostly HBP). The company’s major focus areas are the Eagle Ford, Bakken and Permian Basin. By year-end 2017, the company had completed asset sales for its San Juan Basin, Panhandle and Gomez assets, with a sale pending for its Howard Glasscock asset. In addition, the company reported year-end 2017 Lower 48 production of 322,000 boe/d (17% NGL, 28% natural gas and 55% crude oil) and 1.4 Bboe proved reserves, according to ConocoPhillips’ Lower 48 fact sheet (released in March 2018). According to the company’s second-quarter 2018 results report, “year-over-year production from the Lower 48 Big 3 unconventional plays [Eagle Ford, Bakken and Permian Basin] grew by 37%” and “achieved a Big 3 production milestone of 300,000 boe/d significantly ahead of schedule.” In the Eagle Ford, the company reported yearend 2017 production of 133,000 boe/d, holding about 210,000 net leasehold and mineral acres, primarily in DeWitt, Karnes and Live Oak counties. The company had more than 1,000 total wells online by year-end 2017, according to the fact sheet. ConocoPhillips also reported year-end 2017 production of 83,000 boe/d in the Midcontinent region. In the Permian Basin, the company holds about 1 million net acres and 2017 net production was 60,000 boe/d, the fact sheet stated. In the Anadarko Basin, the company holds about 290,000 net acres and 2017 net production was 13,000 boe/d. In August 2018 ConocoPhillips entered into an agreement to sell its interests in the Barnett Shale to Lime Rock Resources for about $230 million, a press release stated. The transaction closed on Nov. 1. In the Rockies region, which includes the Bakken, Wind River Basin, Uinta and Niobrara, the company reported year-end 2017 production of 82,000 boe/d. The company holds about 98,000 net acres in the Niobrara play and 2017 net production averaged 3,000 boe/d. In addition, the company’s Bakken development area comprises about 630,000 net acres and 2017 net production averaged 65,000 boe/d. The company had more than 694 operated wells online by year-end 2017, according to the fact sheet.
Continental Resources’ operations are in the Bakken and Scoop/Stack plays. The independent oil producer reported second-quarter 2018 production of 25.8 MMboe, or 284,059 boe/d. Total production for the second quarter included 157,116 bbl/d of oil and 761.7 MMcf/d of natural gas, according to the company’s second-quarter 2018 results report. In the Bakken the company expected to average five completion crews and six rigs in the second half of the year, ramping up to seven rigs by year-end 2018, the company stated in the report. The company also expected to complete about 125 additional Bakken wells with first production by the end of the year. Continental’s Bakken production averaged 158,119 boe/d in the second quarter, and the company completed 35 gross (19 net) operated wells flowing at an average initial 24-hour rate of 2,282 boe/d. Continental’s second-quarter Scoop production averaged 64,786 boe/d, and the company completed 16 gross (13 net) operated wells with first production during the same quarter. The company’s second-quarter Stack production was 51,722 boe/d, and it completed 26 gross (13 net) operated wells with first production during the same quarter. Continental is projected to average four completion crews and 18 rigs in Oklahoma in the second half of the year, ramping up to 19 rigs at year-end 2018, according to the report.
Devon’s operations focus on the Delaware Basin, Stack, Eagle Ford and Rockies with 4.3 million net acres and about 23,100 gross producing wells. The company reported 2017 net production of 543,000 boe/d (63% liquids) and reserves of 2.2 Bboe (54% liquids). In the second quarter of 2018, Devon reported total companywide production averaging 541,000 boe/d, according to the company’s second- quarter 2018 results report. In the Delaware Basin, where the company has 670,000 net acres, it reported 2017 net production of 56,000 boe/d and 184 MMboe reserves. Second- quarter 2018 total volumes in the Delaware Basin were 79,000 boe/d. “Growth in the Delaware was driven by prolific well productivity, where the top 10 wells in the quarter averaged initial 30-day rates of approximately 3,000 boe/d,” the company stated in the report. In August 2018 Devon announced it entered into a definitive agreement to sell 9,600 net acres of noncore Delaware Basin acreage in Ward and Reeves counties to Carrizo Oil & Gas for $215 million, according to a press release. In the Stack, where the company has more than 600,000 net acres, it reported 2017 net production of 107,000 boe/d and 456 MMboe reserves. In the Eagle Ford, the company reported 2017 net production of 62,000 boe/d and 60 MMboe reserves. In the Rockies region, Devon reported 2017 net production of 17,000 boe/d and 30 MMboe reserves.
Diamondback’s operations are primarily focused on the Wolfcamp, Spraberry, Clearfork, Bone Spring and Cline formations in the Permian Basin. Second-quarter production of 112,600 boe/d (73% oil) was up 10% over the first quarter and 46% year-over-year, according to the company’s second- quarter 2018 results report. During the second quarter, Diamondback drilled 53 gross horizontal wells and turned 50 operated horizontal wells to production. Operated completions during the second quarter consisted of 29 Wolfcamp A wells, 18 Lower Spraberry wells and three Wolfcamp B wells. Diamondback operated 11 drilling rigs and five dedicated fracturing spreads during the second quarter and expected to add its 12th and 13th operating rigs to development during the third quarter, the report stated. The company also expected to turn between 170 and 190 gross operated horizontal wells to production for full-year 2018. In August Diamondback announced its intent to acquire Energen Corp. for about $9.2 billion, further increasing its presence in the Permian, a press release stated. The transaction was expected to close by the end of the year. Additionally, Diamondback acquired Ajax Resources LLC for $900 million on Oct. 31. “The Ajax acquisition will bring Diamondback’s total leasehold interests to approximately 230,000 net surface acres in the Permian Basin,” a company press release stated.
Encana’s core U.S. assets are in the Permian and Eagle Ford. The company reported Permian production of 88,200 boe/d, including 55,200 bbl/d of oil, in the second quarter, and it stated that production was up 43% year-over-year with production of more than 90,000 boe/d, according to Encana’s second- quarter 2018 result report. The company also brought 11 net wells onto production in the Eagle Ford in the second quarter. In October Encana’s wholly owned subsidiary, Encana Oil & Gas (USA) Inc., announced its intent to sell its San Juan Basin assets in New Mexico for $480 million to DJR Energy LLC, a press release stated. The transaction was expected to close by the end of the year. On Nov. 1, Encana announced its intent to acquire Newfield Exploration Co. for $5.5 billion. The transaction includes approximately 360,000 net acres in the Scoop/Stack in the Anadarko Basin and is expected to close in the first quarter of 2019, according to a press release.
EOG Resources Inc.
EOG Resources is one of the largest independent (non-integrated) crude oil and natural gas companies in the U.S. At year-end 2017, EOG’s total estimated net proved reserves were 2,527 MMboe (52% crude oil and condensate, 20% NGL and 28% natural gas). About 97% of these reserves were located in the U.S., according to a company fact sheet released in March 2018. In the Eagle Ford, EOG has 520,000 net acres and its inventory in this area stands at 2,300 net undrilled premium locations, according to EOG’s second- quarter 2018 results report. The company completed 270 net wells since the last premium inventory assessment in 2017. EOG also continued delineation of the South Texas Austin Chalk, completing five wells in the second quarter of 2018. In the Delaware Basin, EOG holds 416,000 net acres. “EOG has identified an additional 375 net undrilled premium locations in the Delaware Basin, raising the total to 4,815 locations and more than replacing the 250 locations drilled since the last premium inventory assessment in 2017,” the company stated in the report. In addition, EOG’s third largest asset, the Powder River Basin in Wyoming, consists of 400,000 net acres, and the company has identified more than 1,600 net premium drilling locations in the area, according to the report. EOG has identified 141,000 prospective net acres for the Mowry Shale, 89,000 prospective net acres in the Niobrara Shale and 169,000 prospective net acres in the Turner Formation. The company completed two Mowry wells and seven Turner wells in the second quarter. In the Williston Basin in North Dakota, EOG drilled nine wells and began production from two wells in the second quarter, according to the report. EOG also began production from eight wells in the Denver-Julesburg Basin during the second quarter.
EQT has approximately 3.6 million gross acres in the Appalachian Basin, including about 790,000 gross acres in the Marcellus play, more than 13,600 gross productive natural gas wells, 97 Tcfe of total resource potential and 13.5 Tcfe of proved reserves. In June EQT sold its Permian assets for $64 million, according to the company’s second-quarter 2018 results report. No other details were provided.
Equinor has more than 2,200 onshore U.S. producing wells, and its U.S. operations are in the Bakken, Marcellus and Eagle Ford. In the Marcellus Shale, Equinor has 344,000 net acres and is “evaluating the application of a number of new technologies within [its] operations,” the company said on its website. Equinor is “assessing methods that aim to enhance recovery by enabling more effective completions optimization and well spacing.” Equinor is one of the largest producers in the Bakken area. The company has 249,000 net acres in the Bakken (as of 2015). In addition, “Equinor has reduced its flaring in the Bakken below 10%, surpassing current regulatory requirements,” the company stated on its website. In the Eagle Ford, the company has reduced the number of days it takes to safely drill a well from more than 50 days down to as few as 12. The company has 82,000 net acres in the Eagle Ford (as of 2015).
Exxon Mobil / XTO Energy Inc.
In its second-quarter 2018 report, Exxon Mobil reported that its Permian and Bakken production of 250,000 boe/d was up 30% in the second quarter compared to the same quarter last year. In addition, XTO Energy, a subsidiary of Exxon Mobil, is one of the most active operators in the Permian Basin with 3.9 million acres in Texas. “Since 2014, we have grown our Permian portfolio to a high-quality resource base of almost 10 billion barrels today,” the company stated on its website. “By 2025, we plan to increase our production in the basin to 600,000 barrels per day, representing a fivefold increase in our unconventional Permian production.” XTO Energy works in all the major U.S. shale plays. The company has 553,392 acres in Colorado, 662,000 acres in Arkansas, 776,000 acres in Kansas, 661,000 acres in Louisiana, 267,000 acres in Montana, 685,000 acres in New Mexico, 486,000 acres in North Dakota, 381,000 acres in Utah and 135,000 acres in Wyoming. In Oklahoma the company holds 1.1 million acres and operates in 26 counties. XTO Energy is also an active operator in the Marcellus and Utica shale formations in Pennsylvania, Ohio and West Virginia. The company has 534,000 acres in Pennsylvania, 56,000 acres in Ohio and 140,000 acres in West Virginia.
FourPoint Energy is a private E&P company that operates in the Anadarko and Permian basins. The company’s 2 million gross acreage position in the Anadarko Basin is located in 13 counties in Oklahoma and Texas. FourPoint operates 5,646 producing wells and five rigs in the area and, as of Oct 25, reported gross production of 1.05 Bcfe/d, according to the company’s website. FourPoint recently entered the Permian Basin and is actively exploring opportunities for future development, according to the company. In June Double Eagle Energy Holdings III LLC and Four- Point Energy announced the formation of a new company named DoublePoint Energy LLC, which will be a pure play Midland Basin company with more than 70,000 acres in the core areas of the oilrich, multipay zones in Midland, Glasscock, Martin, Howard, Upton and Reagan counties in Texas, a press release stated.
Hess, the second largest producer in North Dakota, has 554,000 net acres in the Bakken with an average working interest of about 75%, and it reported net EUR of about 2 Bboe (as of Oct. 30). Hess’ 2018 Bakken E&P capex was set at about $900 million, and the company expected full-year 2018 Bakken production to be between 115,000 boe/d and 120,000 boe/d, according to the company’s second-quarter 2018 results report. The company also expects production to increase to about 175,000 boe/d by 2021. Second-quarter net production from the Bakken increased 6% to 114,000 boe/d from 108,000 boe/d in the year-ago quarter “due to ongoing drilling activity and improved well performance,” the company stated in the report. Production in the second quarter was “impacted by weather-related downtime in June,” and the company operated an average of four rigs in the second quarter, drilling 28 wells and bringing 27 new wells online. Hess added a fifth rig and expected to add a sixth rig early in the fourth quarter of the year.
Marathon Oil has U.S. operations in the Eagle Ford, Bakken, Scoop/Stack and Permian. In the Eagle Ford, Marathon’s production averaged 106,000 net boe/d in the second quarter, and it brought 39 gross company-operated wells to sales in the quarter with average 30-day IP rates of 1,880 boe/d (66% oil), according to Marathon’s second- quarter 2018 results. The company expected 145 to 165 gross operated wells to sales by yearend 2018. In the Bakken Shale, Marathon’s production averaged 82,000 net boe/d in the second quarter. The company brought 21 gross company-operated wells to sales in the quarter, 12 of which were in the core Hector area with average 30-day IP rates of 2,285 boe/d (79% oil). According to the company, two Three Forks wells in West Myrmidon set new basin records. The company expected 60 to 80 gross operated wells to sales by year-end 2018. In the Scoop/Stack plays, Marathon’s Oklahoma production averaged 80,000 net boe/d in the second quarter, and the company expected 40 to 50 gross operated wells to sales by year-end 2018. In the Permian Basin, the company’s Northern Delaware production averaged 17,000 net boe/d in the second quarter. Marathon brought 13 gross company-operated wells to sales in the Malaga area in Eddy County, N.M., a mix of development and appraisal wells with an average 30-day IP rate of 1,130 boe/d (61% oil), according to Marathon’s second- quarter results. “Drilling efficiencies enabled us to reduce our rig count from five to four in the second quarter, without changing our full-year guidance of 50 to 55 gross operated wells to sales,” the company said. Additionally, in June Marathon executed an agreement with San Mateo for water gathering and disposal in Eddy County, which the company said will significantly reduce unit production costs.
Matador Resources Co.
Matador operates in the Delaware and Midland basins, Eagle Ford Shale and Haynesville Shale. The company reported second-quarter average production of 52,900 boe/d (56% oil), 29,700 bbl/d of oil and 139.2 MMcf/d of natural gas, according to the company’s second-quarter 2018 results report. As of Aug. 1, Matador expected to complete and turn to sales 151 gross (74.1 net) operated and nonoperated wells this year. The company’s second-quarter average production in the Delaware Basin was 46,500 boe/d (59% oil), 27,400 bbl/d of oil and 114.6 MMcf/d of natural gas, the report stated. Matador completed 33 gross wells in the Delaware Basin in the second quarter. From Jan. 1 through Aug. 1, Matador acquired or had under contract approximately 16,000 net leasehold and mineral acres in and around its existing acreage positions in the Delaware Basin, including approximately 3,400 net mineral acres, the report stated. During the second quarter, Matador also divested about 400 net undeveloped acres of its Eagle Ford leasehold position in South Texas for total consideration of about $8 million, the report stated.
Newfield Exploration Co.
Newfield’s U.S. operations are in the Anadarko and Arkoma basins of Oklahoma, the Williston Basin of North Dakota and the Uinta Basin of Utah. Second-quarter net production for the company’s U.S. assets was 186,700 boe/d (39% oil and 62% liquids). “Stronger than expected production results were driven primarily by the Anadarko Basin, which averaged 131,100 boe/d (midpoint of guidance was 123,000 boe/d), an increase of 13% relative to the prior quarter and approximately 48% year-over-year,” according to Newfield’s second- quarter 2018 results report. Second-quarter average net liquids production in the Anadarko Basin was more than 80,000 boe/d. The company’s net crude oil production from the Anadarko Basin averaged more than 42,000 bbl/d of oil (up more than 40% year-overyear), the report stated. The company also continues to advance its Sycamore, Caney, Osage, Resource Expansion (Score) initiative. According to the company, it saw recent positive drilling results in the Northwest Stack in northeast Dewey County, Okla., where the company holds about 24,000 net acres (more than 70% operated). By the end of the year, more than 80% of this position was expected to be HBP, according to the report. In the Williston Basin, Newfield’s net production in the second quarter averaged 21,000 boe/d. On Nov. 1, Encana Corp. announced its intent to acquire Newfield Exploration Co. for $5.5 billion. The transaction includes approximately 360,000 net acres in the Scoop/Stack in the Anadarko Basin and is expected to close in the first quarter of 2019, according to a press release.
Noble Energy’s U.S. onshore operations are located in the Denver-Julesburg (D-J) Basin, Delaware Basin and Eagle Ford Shale. Total sales volumes from the company’s U.S. onshore assets averaged 244,000 boe/d in the second quarter, and U.S. onshore oil volumes totaled a record 105,000 bbl/d of oil, according to the company’s second-quarter 2018 results report. During the second quarter, Noble averaged nine operated drilling rigs (two D-J, six Delaware and one Eagle Ford) and six operated fracturing crews (three D-J and three Delaware). In the D-J Basin, the company had 335,000 acres and reported production of 110,000 boe/d and total proved reserves of 484 MMboe at yearend 2017. Noble also drilled or participated in 138 gross wells that year and reported 6,226 gross productive wells at year-end 2017. The D-J Basin averaged 121,000 boe/d and brought 16 operated wells online in the second quarter of 2018. In the Delaware Basin, the company had 117,000 acres, was running five rigs and reported total sales volumes of 38,000 boe/d in the fourth quarter of 2017. Noble had 238 MMboe total proved reserves as of year-end 2017. In the second quarter of 2018, sales volumes from the Delaware Basin totaled 47,000 boe/d and the company brought 23 operated wells online. In the Eagle Ford Shale, the company had 33,000 net acres and reported production of 70,000 boe/d and 191 MMboe total proved reserves at year-end 2017. Noble also drilled or participated in 47 gross wells that year and reported 344 gross productive wells at year-end 2017. In the second quarter of 2018, sales volumes from the Eagle Ford totaled 76,000 boe/d and the company had brought online nine operated wells.
Oasis Petroleum Inc.
Oasis Petroleum primarily operates in the Williston and Delaware basins. The company has about 506,000 net leasehold acres in the Williston Basin. “We are currently focused on exploiting what we have identified as significant resource potential from the Bakken and Three Forks formations, which are present across a substantial majority of our acreage,” the company said on its website. In June Oasis Petroleum sold an estimated 4,400 boe/d of net production and about 65,000 net acres of noncore assets in the Williston Basin for $283 million, a press release stated. In the second quarter, the company produced 79,400 boe/d from its U.S. assets, representing an increase of 28% over the second quarter of 2017, according to Oasis Petroleum’s second-quarter 2018 results report. The company expected third-quarter 2018 production to range between 85,000 and 88,000 boe/d, which accounts for divestitures that were expected to close during the third quarter. In the second quarter, the company also completed and placed on production 37 gross (27.8 net) operated wells, including 35 gross (25.8 net) operated wells in the Williston Basin and two gross (two net) operated wells in the Delaware Basin, the report stated. The company expected to complete about 110 gross operated wells this year in the Williston Basin and six to eight gross operated wells in the Delaware Basin.
Occidental Petroleum Corp.
Occidental Petroleum’s U.S. operations are focused in the Permian Basin. The E&P company is one of the largest operators and oil producers in the Permian, with nearly 2.5 million net acres and producing about 9% of the total oil in the basin. Occidental manages operations in the Permian Basin through two businesses: Permian Resources, which consists of growth-oriented unconventional opportunities, and Permian EOR, which utilizes EOR techniques, such as CO2 flooding and waterfloods. In the second quarter, Permian Resources’ average production volumes were 201,000 boe/d, and Permian EOR’s were 153,000 boe/d, according to Occidental’s second-quarter 2018 results report. In addition, each year Occidental’s Permian EOR business injects more than 950 Bcf of CO2 into oil reservoirs in the Permian, making Occidental the largest injector of CO2 for EOR in the Permian Basin, and among the largest globally, the company said on its website.
Parsley Energy operates in the Midland and Delaware basins. The company’s second-quarter 2018 net oil production increased 14% quarter-over-quarter and 57% year-over-year to 67,700 bbl/d of oil, and total net production averaged 107,800 boe/d, according to Parsley’s second-quarter 2018 results report. Parsley placed 45 gross (44 net) operated horizontal wells on production during the second quarter. “This higher-than-anticipated net well count was driven by operational efficiency gains and acreage trades that increased Parsley’s average working interest,” the company said in the report. “In light of these trends, the company is increasing the number of operated horizontal wells it expects to place on production in 2018 from 144 net wells to approximately 158 net wells. These additional net wells are not predicated on the addition of incremental rigs or completion crews.” During the second quarter, Parsley spudded 43 wells and placed 45 gross operated horizontal wells on production (37 in the Midland Basin and eight in the Delaware Basin). Parsley expected development activity to remain weighted to the Midland Basin for the remainder of the year, the report stated. The company increased full-year 2018 net oil production guidance to between 68,000 bbl/d and 70,500 bbl/d of oil. According to the company, at the midpoint the updated range translates to estimated year-over-year growth of 54%.
PDC Energy’s focus is on the Core Wattenberg Field in the Denver-Julesburg (D-J) Basin in Colorado and the Delaware Basin in West Texas. In the Wattenberg Field, the company has drilled 20 to 22 horizontal wells per 640-acre section. “The 2018 capital investment program is focused on the Kersey area, with some spuds in its Plains area, as well as turning in-line the 24 horizontal wells it acquired in the Prairie area,” the company said on its website. PDC expected to run three drilling rigs in the D-J Basin this year. In the Delaware Basin, the company has about 60,000 net acres in Reeves and Culberson counties, and it expected to run three drilling rigs this year. “The drilling in 2018 is focused primarily on drilling single Wolfcamp wells in the A or B benches to meet drilling obligations as well as a downspacing test in its Eastern area that will evaluate the equivalent of 12 wells per section in the Wolfcamp A and a well that will test the Wolfcamp C,” the company said. PDC reported second-quarter production of 9.4 MMboe, representing a year-over-year increase of 20% from Wattenberg and Delaware basin operations, according to the company’s second- quarter 2018 results report. In addition, PDC reported second-quarter production of about 103,000 boe/d as well as oil production of about 3.9 MMbbl, which represented 42% of the company’s total production.
Pioneer Natural Resources
Pioneer Natural Resources has operations in the Permian Basin and Eagle Ford Shale in Texas. However, the company is in the process of becoming a pure play Permian Basin operator by the end of the year. Pioneer has 750,000 gross acres and is the largest acreage holder and producer in the Midland Basin with approximately 550,000 gross acres in the northern portion of the play and approximately 200,000 gross acres in the southern Wolfcamp joint venture area. The company reported second-quarter production of 274,000 boe/d in the Permian Basin and expects to place 250 to 275 wells on production this year, according to its second-quarter 2018 results report. Pioneer’s full-year 2018 updates included the company expecting its noncore asset divestiture process to be completed by the end of the year; closed sales of the West Panhandle field, Raton Basin and selected Eagle Ford acreage for $383 million; and progressing its divestiture of Eagle Ford and other South Texas assets, according to the report.
QEP Resources operates in the Permian Basin and Williston Basin. The company reported year-end 2017 proved reserves of 684.7 MMboe and second- quarter 2018 production of 14.1 MMboe. In the Permian Basin, QEP reported year-end 2017 proved reserves of 272.7 MMboe. Permian Basin net production averaged about 44,100 boe/d (91% liquids), and the company placed 37 gross operated horizontal wells on production during the second quarter, according to QEP’s second-quarter 2018 results report. At the end of the quarter, the company had five operated rigs in the Permian, and it released one of its operated rigs during mid-July. In the Williston Basin, the company reported year-end 2017 proved reserves of 146.9 MMboe. According to its second-quarter 2018 report, QEP is open to bids from potential buyers regarding the sale of all or a portion of its Williston Basin assets. At the end of the second quarter, the company had no drilling rigs in the Williston Basin.
Range Resources has operations in the Appalachia region and in north Louisiana. In the Appalachia region, the company has about 875,000 net acres and reported third-quarter 2018 net production of 1.98 Bcfe/d. This year Range directed about 85% of its capital budget toward Marcellus Shale development. According to the company’s third-quarter 2018 results report, “Range’s net production for the third quarter of 2018 averaged 2,267 MMcfe per day, consisting of 1,530 MMcf per day of natural gas, 111,469 barrels per day of NGL and 11,314 barrels per day of condensate and oil. This makes Range one of the top 10 natural gas producers in the U.S. and a top three NGL producer amongst E&P companies.”
Sanchez Energy’s operations are in the Eagle Ford and Tuscaloosa Marine Shale, where the company reported second-quarter production of 7.2 MMboe, or 79,516 boe/d, according to the company’s second- quarter 2018 results report. Sanchez drilled 57 gross (33 net) wells and completed 41 gross (28 net) wells in the second quarter. As of June 30, Sanchez had 2,278 gross (918 net) producing wells with 73 gross wells in various stages of completion, according to the report. As of year-end 2017, the company had 487,000 gross leasehold acres (about 285,000 net acres) and more than 8,000 gross (3,700 net) specifically identified drilling locations for potential future drilling in the Eagle Ford. About 748 of these drilling locations represented proved undeveloped reserves, according to the company.
Shell has interest in 500,000 acres (260,000 net acres) in the Delaware Basin with focus on the Wolfcamp, Bone Springs and Avalon formations. Shell has focused on de-risking its acreage in the Delaware Basin and has advanced several key areas, according to the company. Shell has more than 1,300 operated and nonoperated wells and six operated and eight nonoperated rigs (as of the third quarter) across Loving, Ward, Winkler and Reeves counties. The company accelerated development in the Permian with a plan to bring about 100 Shell operated new wells online this year. To do so, Shell focused on multiwell pad drilling and long lateral wells to improve efficiencies and reduce surface impacts, the company said. In line with this acceleration in activity, Shell’s production has increased from 25,000 boe/d in 2013 to more than 100,000 boe/d in 2018 (operated and nonoperated) and is expected to increase to more than 200,000 boe/d by 2020 (GES, post royalty). Most of the production is light tight oil. Shell has made significant investments in the supporting gathering lines and central processing facilities (CPFs). It operates five CPFs and plans to develop additional facilities to match its production growth, the company said Oct. 29. The company also operates 11 saltwater disposal (SWD) surface facilities and 20 SWD injection wells. By the end of the year, it expected to have 14 SWD surface facilities and 24 SWD wells. In early 2019 Shell will deploy the first integrated prototype of its iShale program in the Permian. The program leverages advances in automation, digitalization and advanced analytics to optimize field design and enhance well productivity.
SM Energy Co.
SM Energy’s operations are in the Midland Basin and Eagle Ford Shale. In the second quarter, the company reported production of 10.5 MMboe, or 115,000 boe/d, according to the company’s second-quarter 2018 results report. As of February 2018, the company expected production growth of 135% from 2017 to 2019 in the Midland Basin. For full-year 2018, SM Energy expected production of 43.5 MMboe to 45 MMboe (an average of about 42% oil in the commodity mix), according to the report. In the third quarter, SM Energy reported total production of 12 MMboe (130,200 boe/d), which comprised 42% oil in the commodity mix and 62% liquids, according to the company’s third-quarter 2018 preview report. The company’s third-quarter production was 64,800 boe/d in the Permian and 65,400 boe/d in the Eagle Ford.
Southwestern Energy Co.
Southwestern Energy (SWN), with more than 500,000 acres in the Marcellus Shale in the Appalachian Basin, produces natural gas, oil and NGL. For the first nine months of 2018, SWN produced 252 Bcfe and generated adjusted EBITDA of $1 billion, 21% above the period a year ago “due to an ongoing benefit from higher value natural gas liquids and oil production,” the company said. During the third quarter, SWN announced the sale of Fayetteville Shale E&P and midstream assets for $1.87 billion. The transaction was expected to close in early December.
Whiting Petroleum Corp.
Whiting Petroleum operates in the Rocky Mountain region, with its largest projects in the Bakken, Three Forks and Niobrara. The company reported second-quarter production of 11.5 MMboe (84% crude oil/NGL), averaging 126,180 boe/d. The Bakken/Three Forks plays in the Williston Basin averaged 103,480 boe/d, and the Redtail Niobrara/Codell plays in the Denver-Julesburg Basin averaged 22,005 boe/d. During the second quarter, Whiting drilled 33 wells in the Williston Basin area and no wells in the Redtail area as well as put 22 wells on production in the Williston Basin and 16 wells on production at Redtail, according to the company’s second-quarter 2018 results report. Whiting also completed a $130 million acquisition of Williston Basin properties contiguous with the East Missouri Breaks and Hidden Bench areas, the report stated. The properties included 54,833 net acres and had production of 1,290 boe/d and estimated proved reserves of 26 MMboe (as of July 31).
WildHorse Resource Development Corp.
WildHorse Resource Development (WRD) has 418,000 net acres in the Eagle Ford as well as operations in the Austin Chalk in East Texas. In September WRD acquired 20,305 net acres in the Eagle Ford, Austin Chalk “and other intervals” with about 39 boe/d of net production, a press release stated. The company increased its average production by 107% to 46,700 boe/d for the second quarter of the year compared to 22,600 boe/d for the second quarter of 2017, according to WRD’s second-quarter 2018 results report. The company brought 28 gross (26.2 net) Eagle Ford wells online and completed five Eagle Ford refractures in the second quarter. Second-quarter net production consisted of about 33,400 bbl/d of oil, 6,000 boe/d of NGL and 43.5 MMcf/d of natural gas. On Oct. 30, Chesapeake Energy announced its intent to acquire WildHorse. The transaction is expected to close in the first half of 2019, a press release stated.
WPX Energy has 100,000 net acres in the Permian and 85,000 net acres in the Williston Basin. The company reported second-quarter oil volumes of 80,800 bbl/d from its operations in the Delaware and Williston basins, according to its second- quarter 2018 results report. During the second quarter, WPX’s Delaware production averaged 74,400 boe/d, and the company had 20 wells with first sales in the basin. WPX completed 32 gross operated wells (29 net) in its two core basins during the second quarter of 2018 and participated in another seven gross (one net) nonoperated wells in the Delaware Basin, the report stated. The company’s Williston Basin production averaged 50.6 Mboe/d in the second quarter, and WPX completed 12 Williston wells during the quarter, evenly split between the Bakken and Three Forks formations. The company expected full-year 2018 oil volumes of 78,000 bbl/d to 82,000 bbl/d, according to the report.
Oklahoma operator looks to shed Canada and Barnett assets.
E&P spending in North America is expected to lag behind international markets, where some regions could see double-digit spending growth.
The company says the Mowry and Niobrara shale plays have increased its estimated resource potential in the basin to more than 2 billion barrels of oil equivalent.