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December 23, 2020: Diamondback Energy (FANG) on December 20 announced two transactions to acquire Tier 1 assets in the northern Midland Basin for a combined $3.0 billion, continuing the 2H2020 trend of Permian-focused upstream consolidation.
FANG said it will acquire Permian and Bakken producer QEP Resources (QEP) in an all-stock deal for $2.2 billion, including $1.6 billion in assumed QEP debt. Separately, FANG will purchase private Permian producer Guidon Operating LLC for $0.9 billion in cash and stock. FANG expects to close both deals by early 2Q2021. QEP shareholders will receive 0.05 shares of FANG for each QEP share, giving QEP shareholders 7.2% of the combined company. Guidon Operating will receive 10.63 million FANG common shares and $375 million cash. The two transactions will add 81,500 net acres in the northern Midland Basin and 56 drilled but uncompleted wells (DUCs). FANG said it will consolidate these DUCs into its own DUC portfolio, thereby lowering its expected 2021 reinvestment ratio. QEP’s Bakken assets, which FANG classified as non-core, will generate value for the company through the harvesting of cash flows or via a divesture, pending market conditions. FANG will have 429,000 total Permian net surface acres once the acquisitions close, with 276,000 net acres in the Midland Basin.
The 2020 market downturn has precipitated the third, and in some respects the worst, bankruptcy event to rock the oil and gas sector in the last five years.
A total 41 energy companies with $56.3 billion in combined debt entered Chapter 11 in 2020, according to data from law firm Haynes and Boone and East Daley’s research. Our accounting of the year’s bankruptcies is comprised entirely of E&P companies. COVID-related market disruptions in the March-June period caused unprecedented volatility, including negative oil prices in April, and sparked the latest industry bankruptcy wave. Boom-andbust cycles also are shorter than ever, reflecting both high leverage in the upstream space and the potential for rapid supply growth and oversupply from shale development. Table 1 lists the Top 10 E&P bankruptcies this year in basins covered by East Daley. This list includes so-called “Chapter 22” repeat bankruptcies from previous commodity cycles, like Ultra Petroleum, and producers like Chesapeake Energy (CHK) that fought tooth and nail over five years to stay afloat.
December 10, 2020: Midstream earnings performance in 3Q2020 reflected the industry’s ongoing recovery from challenging conditions this spring as WTI prices stabilized in a $40/bbl price range.
The 27 midstream companies in East Daley’s coverage group posted total Adj. EBITDA of $20.6 billion in 3Q2020, a 1.3% Y-o-Y increase ($272 million) from total Adj. EBITDA of $20.3 billion in 3Q2019. Company results in 3Q2020 diverged despite the relatively flat Y-o-Y sector performance, ranging from a 22% decline in Enable Midstream’s (ENBL) earnings to a 121% increase at Altus Midstream (ALTM).
November 19, 2020: Former Vice President and Democratic Party nominee Joe Biden leads President Donald Trump 306 to 232 in projected Electoral College votes, well above the 270 required to win the presidency.
While President Trump has not conceded the 2020 presidential election, his legal challenges to state-level ballot counts to date have been unsuccessful and those who allege voter fraud have not yet produced widespread evidence of fraud that would change our expectation of Biden becoming the next President. Barring an unforeseen court intervention, Joe Biden will become the 46th U.S. President.
November 2, 2020: Despite Mountain Valley Pipeline’s (MVP) status at 92% of completion, the project’s outlook is far from certain. Updated guidance from Equitrans Midstream (ETRN), MVP’s majority owner, expects MVP to enter service in early 2021, a timeline East Daley considers optimistic.
While most work appears complete, MVP’s last leg faces large obstacles, including permitting and regulatory issues, stark pushback from environmental groups, difficult terrain to navigate, the coming winter, and COVID-19 complications. Based on our analysis, we model MVP to begin service in 3Q2021. ETRN is highly leveraged to MVP’s success, with many additional projects and contracts tied to the projects in-service date. These are all key to ETRN’s plan to reach its leverage target under 4x. Lastly, looking at the entirety of Northeast infrastructure, there is a clear need for MVP’s 2 Bcf/d capacity and potential 500 MMcf/d compression expansion.
October 27, 2020: In East Daley’s view, Canada’s midstream provides investors with capital preservation.
That’s a conclusion that investors seem to share about the investment risks and merits of the Canadian midstream market and its largest companies.
Though not without longer-term decarbonization challenges, Canada’s energy infrastructure titans – Enbridge (ENB), TC Energy (TRP), and Pembina (PBA) – offer less execution risk, less market risk, and better dividend security than their American cousins as Canadian oil and gas production remains robust. These unique attributes in Canada have translated into superior downside protection for public investors in 2020. In the trailing year, Canadian midstream stocks have outperformed U.S. midstream stocks by ~16%.
October 22, 2020: Pioneer (PXD) on Tuesday announced it will buy independent producer Parsley Energy (PE) in an all-stock deal that will create the second-largest oil and gas producer in the Permian.
PE shareholders will receive 0.1252 shares of PXD for each PE share, valuing the Austin, TX-based E&P at ~$4.5 billion, a 7.9% premium vs. PE’s valuation prior to the announcement. Including $3.1 billion in long-term debt at the end of 2Q2020, the transaction places an enterprise value of ~$7.6 billion on PE, one of the largest energy deals so far in 2020. PXD and PE expect to close the transaction in 1Q2021. Management expects the combination to drive $325 million in synergies. Scott Sheffield runs PXD. Sheffield’s son Bryan Sheffield is Parsley’s founder and chairman. The younger Sheffield retired last year as CEO but will receive a $7.5 MM change of control payout upon consummation of the merger. PE’s current President and CEO, Matt Gallagher, will join the expanded PXD board of directors, with the company’s headquarters to remain in Dallas, TX.
October 20, 2020: ConocoPhillips (COP) on Monday announced it will buy independent producer Concho Resources (CXO) in an all-stock deal that will create the second-largest oil and gas producer in the Permian Basin.
CXO shareholders will receive 1.46 COP shares for each CXO share, valuing the Midland, Texas-based E&P at ~$9.7 billion. The price represents a 15% premium to CXO’s share price before rumors of the transaction were first announced and sent CXO shares higher. Including $3.9 billion in long-term debt at the end of 2Q2020, the transaction places an enterprise value of ~$13.6 billion on CXO, the largest energy deal so far in 2020. COP and CXO expect to close the transaction in 1Q2021. Upon closing, CXO’s Chairman and CEO Tim Leach will join COP’s board of directors and serve as executive vice president and president, Lower 48.
October 8, 2020: Targa Resources’ (TRGP) primary focus is its natural gas and NGL business, though it also owns crude gathering facilities in West Texas and North Dakota.
. In 2017 TRGP decided to integrate its processing and fractionation assets by building the Grand Prix NGL Pipeline, which connects its G&P systems in the Permian, North Texas, and Oklahoma to its NGL fractionation facilities at Mont Belvieu, TX and nearby export terminal in Galena Park, TX. Grand Prix, which started service in August 2019, increased TRGP’s debt levels significantly, but the company expected increased revenue and earnings from asset integration would allow deleveraging. Volatility in oil prices this year has changed that outlook.
December 30, 2020: In 1H2020 amidst volatility in the commodity markets and uncertainty in the demand forecast, midstream companies hoping to preserve cash flow and to protect stakeholders canceled and deferred projects.
While management teams stressed capital discipline, investors were left with headwinds from base business decline and dwindling prospects for incremental EBITDA growth. For Pembina Pipeline (PBA), the cancelation of several major projects significantly capped annual EBITDA growth, with East Daley expecting a meager 0.6% by 2024. However, as 2020 ends, PBA is looking toward 2021 and giving investors a positive outlook for future earnings growth. In a December 14 release, the company provided initial 2021 EBITDA guidance and announced a $785 million capital program focused on restarting two previously deferred projects: The Empress Co-generation Facility and the Peace Phase VII pipeline expansion. Empress will result in operational cost savings and efficiencies, but the Phase VII expansion has a greater impact to PBA’s bottom-line. Previously estimated to cost $950 million (before deferment), the company’s revised plan outlines a $775 million project with fewer pump stations and slightly lower capacity (160 Mb/d) than the original 240 Mb/d. Expected to be complete in 1H2023, Phase VII will bring PBA’s Edmonton delivery capacity to ~1.1 MMb/d and be underpinned by nearly 1 MMb/d of commitments. At full run-rate, East Daley expects Phase VII will generate $111 million, or ~7x cost to EBITDA multiple. –AJ O’Donnell Tickers: PBA
December 30, 2020: Private XcL Midstream recently started its 200 MMcf/d Clearfork gas processing plant in West Virginia, which likely is drawing Marcellus - Utica rich gas produced by Tug Hill Operating away from Blue Racer Midstream’s Natrium processing facility.
As East Daley discussed in an October The Daley Note1, rig fluctuations this year in the Delaware Basin differed in New Mexico vs. Texas. As total rigs fell across the basin, the NM market share of rig activity increased from 44% to 63%. Even after the rig count rebounded in late 3Q20, NM rigs maintained majority status, even into mid-December (current rig count of 94 split 59/35). So, which of the historically active operators are bullish in NM? EOG Resources (EOG) is clearly in, with NM rigs increasing from 2 in July to 10 as of publication.
Devon Energy (DVN) is still holding steady in NM, with 8 rigs operating since early 3Q20 (taking stock of WPX Energy (WPX) activity ahead of the 1Q2021 merger adds only 1 rig in late 3Q). On the flip side, ExxonMobil (XOM) NM rig counts have dropped dramatically during 2H20, from 14 in July down to only 7 as of this writing. Concho Resources (CXO) has decreased activity as well, from 3 to 1 NM rigs, with a similar story for Chevron (CVX) at 1 rig, ahead of the announced 1Q21 merger. On the private E&P side, larger operators Mewbourne & Tap Rock were running 2 rigs in early 3Q20, and are now up to 7 and 4, respectively. As discussed in East Daley’s Midstream Navigator, “This Land is Your Land,” the NM portion of the Delaware Basin is rife with federal leases, while the TX side is almost entirely non-federal lands. Operators with NM acreage may be preferentially drilling on federal lands to get ahead of a potential ban.
According to East Daley’s G&P Allocation model, EOG, DVN, CXO, XOM, Mewbourne, and Tap Rock supply most of their volumes to privately owned Lucid Energy, EnLink (ENLC), Enterprise (EPD), DCP (DCP), Energy Transfer (ET), and Targa Resources (TRGP), providing their midstream NM assets with more drilling activity
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while the future of oil and gas production on federal lands remains uncertain. - Melissa J. Saurborn Tickers: DVN, XOM, EOG, CXO, ENLC, EPD, DCP, ET, TRGP
December 30, 2020: ONEOK (OKE) has two major G&P systems in the Williston and Anadarko that should see different 4Q20 throughput levels.
East Daley estimates the Williston will outperform in 4Q20 while the Anadarko system will probably decline. We expect Rocky Mountain system (Williston) throughput will increase by ~17% Q-o-Q based on interstate pipeline samples. Historically, these samples have served as an excellent indicator for OKE’s reported volumes. North Dakota’s well data show that a reduction in flaring is not behind the increase in Bakken volumes, as flaring grew from 99 MMcf/d in September to 149 MMcf/d in October (5.12% and 7.6% of production respectively).
We conclude that production continues to return from 2Q20 curtailments, and/or producers are working through existing DUC inventories. Anadarko pipeline samples have been a poor indicator for system performance, but the addition of Midship pipeline may improve the sample and is still useful to determine operational disruptions. Although the sample shows a decline of 19% Q-o-Q, this reading is likely overblown as volumes shift to intrastate pipelines. East Daley still expects a decrease, however, as freezing events in October and natural well declines are likely to affect overall throughput during 4Q20.
Even when implementing the worst-case-scenario of a 19% decline in Anadarko volumes, East Daley estimates that OKE is likely to outperform 4Q2020 consensus estimates of $764 million in EBITDA because of the increase in Bakken volumes. Despite the Anadarko encountering freezing events and natural well declines, the increased throughput in the Bakken should make up for the shortfall. – J.R. Blumensheid. Tickers: OKE
December 30, 2020:Current pipeline flow data from Williams’ (WMB) Bradford and Susquehanna Supply Hub systems show that volumes have rebounded strongly after shut-ins hurt flows in early October and November 2020.
Volumes are now near 6 Bcf/d and are tracking well ahead of East Daley’s 3Q post-earnings Financial Blueprint model. Continued vigorous growth on Bradford from Chesapeake and shut-in wells returning on Susquehanna appear to be the primary reasons for outperformance.
If throughput continues at these levels for the rest of 4Q20, our asset-level EBITDA for these systems would increase by ~$20 million combined for 4Q20. The higher base production would also boost EBITDA for 2021. Despite a warm start to the winter, East Daley remains bullish on natural gas prices and continued volume growth for Northeast systems through at least 2022 when pipeline egress could become constrained. – Matthew Lewis Tickers: WMB
December 18, 2020: Sentinel and Freepoint’s Texas GulfLink project recently took the lead in the regulatory process among three competing deepwater terminal applications, becoming the first to receive a draft environmental impact statement from the federal government.
However, competition and heavy overbuilding off the Texas coast could make it difficult for GulfLink to commit customers to the project. The proposed Texas GulfLink deepwater crude export facility would serve the Houston market. The project plans to construct aboveground storage near Jones Creek, TX connected via a 42inch pipeline to two offshore platforms planned ~32 miles from the coast of Freeport, TX. The facility aims to be able to load two VLCCs at once and service 15 VLCCs per month. Other proposed deepwater projects include Energy Transfer’s (ET) Blue Marlin Offshore Port (BMOP) in Nederland, TX and P66 and Trafigura’s Bluewater terminal off the coast of Corpus Christi, TX. Perhaps the strongest competitor with GulfLink is Enterprise (EPD) and Enbridge’s (ENB) Sea Port Oil Terminal (SPOT), which is also proposed off the coast of Freeport. East Daley’s Crude Hub Model sees excess capacity of ~5 MMb/d in 2024 to serve the Houston market, even without any additional projects completed. Other proposed deepwater facilities like SPOT are backed by firms that can commit their own volumes to their planned facilities. Excess capacity and steep competition will make it difficult for GulfLink to commit enough customers in the current market. – Alex Gafford Tickers: ET, ENB, EPD, PSX
December 18, 2020: Our most recent Company Dashboard shows a significant decline in Western Midstream’s (WES) DJ Basin residue volume, a decline we expect is due to fewer completions by parent company Occidental Petroleum (OXY).
We compare state reported inlets, residue gas samples, and production volumes reported by WES. We have high confidence in our DJ Basin residue pipeline sample and in our sample for WES, since all WES plants connect to interstate pipelines. Residue and plant inlets historically have correlated above 90%+ to company-reported volumes. Most recently we expected WES would complete ~40 drilled but uncompleted wells (DUCs) on its system in 4Q2020, based on its most recent guidance in 3Q2020. But that guidance so far has proved to be overly aggressive, which suggests far fewer DUC completions. Our current 4Q2020 residue forecast for the WES system is 1,015 MMcf/d compared to the realtime residue data average of 872 MMcf/d quarter to date. Reducing our volumes to line up with state and residue data lowers our 4Q2020 EBITDA forecast by ~$20 million, a forecast 1% below Street estimates for 4Q20 and in line for 2020. - Zack Van Everen Tickers: OXY, WES
December 18, 2020: Private XcL Midstream recently started its 200 MMcf/d Clearfork gas processing plant in West Virginia, which likely is drawing Marcellus - Utica rich gas produced by Tug Hill Operating away from Blue Racer Midstream’s Natrium processing facility.
In a recent DUG East conference, XcL management confirmed the start of the Clearfork facility, and said they are contemplating an 800 MMcf/d facility expansion. The Clearfork plant is part of XcL’s Appalachian Connector system, which includes 100 miles of lean and rich gas gathering pipeline in West Virginia. Tug Hill, one of the region’s fastest-growing private producers, underpins XcL’s infrastructure investment with a 600 MMcf/d anchor commitment. East Daley’s interstate pipeline sample for XcL’s system shows a ~200 MMcf/d increase in volumes from September to October, suggesting Clearfork began processing during this period as Tug Hill volumes shifted away from Blue Racer’s intrastate connection to Dominion Transmission. Tug Hill averaged three rigs this year, putting it only slightly behind giants such as Southwestern Energy (SWN) and EQT (EQT) for YTD rig activity. As public Northeast operators guide to flat production through 2021, private E&Ps and midstream systems provide opportunities. Tug Hill’s gas production ramped ~480% from 1Q2019 to 4Q2019, or ~360 MMcf/d, coinciding with XcL’s Appalachian Connector in-service date. Tug Hill revealed it would target 18% annual production growth through 2025, mostly committed to XcL’s system. Upstart XcL poses steep midstream competition, and an expanded Clearfork likely would further displace Tug Hill volumes on Blue Racer’s system. - David Dubetz Tickers: CHK, EQT, SWN
December 18, 2020: EP Energy (EPE) said December 11 it sold its southern Midland Basin acreage to an undisclosed buyer, a deal that may inject new investment into acreage serviced by West Texas Gas, Targa Resources (TRGP), and DCP Midstream (DCP). EPE expects the deal to close in early 1Q2021.
According to our G&P Allocation Tool, EPE produced ~101 MMcf/d on its southern Midland acreage in 2Q2020. West Texas Gas, DCP, and Cogent were its largest Midland midstream counterparties, processing 49%, 18%, and 7%, respectively of its produced natural gas. EPE has not deployed a rig in the Midland since May 2018, but when it drilled its rigs operated on WTG’s South Midland, TRGP’s West Texas, and DCP’s Midland systems. Pro forma for the divestiture, EPE will have ~138 MMcf/d of 2Q2020 production between the Eagle Ford (62%) and Uinta (38%) basins. 55% of the company’s production is processed by Kinder Morgan (KMI) systems, with DCP, Enterprise Products (EPD), Energy Transfer (ET), and Western Midstream (WES) each processing ~8%. In the Uinta Basin, EPE accounted for 66% of 2Q2020 production on KMI’s Altamont system, and 31% of rigs on the KMI system. There have been no rigs operating on this system since May 2020, with EPE shifting its Uinta rig to WES’s Uinta system. EPE has had minimal rig activity in the Eagle Ford since 2Q2019, with most rigs since then operating also on KMI systems. In the 1H2019, the company operated ~3 rigs in the Eagle Ford, mostly on KMI but also on Southcross Energy (SXE) and DCP systems. While the buyer of the Midland Basin acreage is unknown, a new owner may start drilling new wells and growing volumes on the West Texas Gas, TRGP, and DCP systems. – Robert Ingram Tickers: DCP, ET, EPD, EPE, KMI, SXE, TRGP, WES
December 18, 2020:We are deep enough into December to highlight that 4Q2020 natural gas gathering and processing (G&P) volumes in the Bakken are on track to exit 2020 higher than the year’s start on some midstream assets, with G&P activity particularly strong on systems owned by ONEOK (OKE), Hess Midstream (HESM), Kinder Morgan (KMI), and Crestwood Equity (CEQP).
Bakken production has bounced back after sweeping curtailments in 2Q2020 spurred by falling oil prices. New gas processing facilities started by KMI, OKE, HESM, and CEQP in the nine months prior to the downturn have enabled more gas capture and less flaring as the Bakken production surges from formerly shut-in wells. We highlight six of the top gas processors in the basin. East Daley projects ONEOK (OKE), the largest gas processor in the Bakken, to post its highest throughput in company history in 4Q2020 at 1,224 MMcf/d, a 9% increase over 1Q2020 volumes. OKE processes ~40% of the basin’s marketed natural gas production. We expect HESM to post 8% growth for 4Q2020 vs. 1Q2020, and we estimate Crestwood (CEQP) has filled its 150 MMcf/d Bear Den plant during 4Q2020. We estimate KMI’s total Bakken volumes in 4Q2020 to equal what the company processed in 1Q2020, while Targa Resources (TRGP) is expected to come up just a hair short. Oasis Midstream (OMP) is the outlier due to its reliance on bankrupt parent Oasis Petroleum. We expect OMP’s processed gas volumes to decline 11% vs. 1Q2020. Even with volumes mostly bouncing back to 1Q2020 levels, the longer-term outlook is not as optimistic as the active rig count has fallen from the mid-50s in the beginning of the year to ~14 in 4Q2020. – Andy Ptacek Tickers: CEQP, HESM, KMI, OKE, OMP, TRGP
December 11, 2020: The Anadarko Basin experienced freezing events in late October that we estimate will impact 4Q2020 midstream throughput for ONEOK (OKE) and EnLink Midstream (ENLC).
Oklahoma City, OK midpoint temperatures dipped well below freezing on October 26, resulting in a subsequent drop in our interstate gas sample. Volumes for the Anadarko Basin plunged 24% from 4,466 MMcf/d on October 24 to 3,328 MMcf/d on October 29. When weather warmed, interstate samples recovered. The overall impact in October was only a 3% decline vs. volumes recorded in September, and sample volumes for the Anadarko remain higher by 6% Qo-Q despite the disruptions. Midstream names such as ENLC and OKE seem to be most impacted by the freezing events. Most of their systems are located to the north of the SCOOP, and each had sample volumes declines over 70% from October 23 to October 29. ENLC cited freezing events in its most recent earnings call that it said disrupted operations in 4Q2020. ENLC and OKE sample volumes remain 12% and 17% below 3Q2020 averages, respectively. Larger systems operated by Enable Midstream (ENBL) and DCP Midstream (DCP) with more exposure to the SCOOP and overall drilling activity appear less affected. East Daley will revise 4Q2020 throughput for ENLC and OKE downward in its 4Q2020 Blueprint Financials as a result of this event. – J.R. Blumensheid. Tickers: DCP, ENBL, ENLC, OKE
December 11, 2020:Kinder Morgan (KMI) this week provided preliminary 2021 Adj. EBITDA guidance that came in below Street consensus but was close to East Daley’s estimates.
KMI guided to 2021 Adj. EBITDA of $6,800 million, which is $260 million (~3.7%) below consensus of $7,060 million (as of December 7) but in line with East Daley’s 3Q2020 Post-Call earnings model at $6,810 million. KMI said it expects DCF of $4,400 million vs. East Daley’s estimate of $4,538 million. The delta to our estimate appears to be from higher maintenance Capex. Implied FCF to Equity (DCF minus growth capital) is $3,600 million vs. our $3,784 million estimate. The delta is also largely due to higher maintenance capital spend. In our 3Q2020 Pre-Call Board Report, we noted that 2021 Adj. EBITDA growth vs. 2020 would be difficult for KMI. We see future headwinds based on current commodity prices and the lackluster production outlook, the recent stagnation of refined product demand, and lower realized oil prices and production declines for KMI’s CO2 segment. Legacy contracts are also expiring on multiple KMI pipelines (Ruby, Fayetteville Express, Midcontinent Express, Cheyenne Plains, KMCC, and Double Eagle) that we expect will be recontracted at lower volumes and rates. KMI also has rate-case risk for Tennessee Gas Pipeline, El Paso, and Florida Gas Transmission, which all are forecast to see some downside due to previously settled rate cases. - Matt Lewis Tickers: KMI
December 11, 2020: Large crude egress pipelines have dominated headlines for Permian Basin infrastructure, but a handful of smaller players are also making moves on intra-basin systems, such as Lotus Midstream’s newly started 150 Mb/d Augustus Pipeline.
Lotus, a private Permian operator backed by EnCap Flatrock, operates the Centurion Pipeline system, which it acquired from Occidental (OXY) in 2018. Centurion’s network of intra-basin and long-haul pipes span ~2,900 miles from the Permian to the Cushing hub. Cashflow generated by the Centurion system fell from ~$55 million in 4Q2018 to ~$30 million in 2Q2020. Volume attrition appears to be the driver, with total throughput in 2Q2020 of ~510 Mb/d, down ~300 Mb/d from 4Q2018. East Daley believes competition from other Permian midstream operators, such as Enterprise (EPD) and Plains All American (PAA), is likely to blame. However, Lotus has made strategic moves to strengthen its position and recoup volumes, becoming a JV partner on the 1.5 MMb/d Wink to Webster Pipeline (W2W) and boosting Centurion’s intra-basin connectivity via Augustus, which began taking shipments on December 1. Augustus connects Centurion’s Midland terminal to Crane, TX where shippers have access to Magellan Midstream’s (MMP) Longhorn Pipeline or the EPIC system for delivery to Houston or Corpus Christi. Shippers will pay committed rates of $0.230.29/bbl or walk-up rates of $0.35-0.50, according to an October 30 FERC tariff filing, competitive with rates offered by peers. While Centurion has not revealed the commitments behind Augustus, we assume volumes will come from shippers on Longhorn and EPIC, making companies such as OXY, Pioneer (PXD), Laredo Petroleum (LPI), Altus Midstream (ALTM), and Rattler Midstream (RTLR) likely candidates. – AJ O’Donnell Tickers: ALTM, EPD, LPI, MMP, OXY, PAA, PXD, RTLR
December 11, 2020: M Chevron (CVX) plans to slash its long-term Capex budget by ~25% to preserve its dividend amid lower oil and gas prices, a potential headwind for midstream companies including Energy Transfer (ET), DCP Midstream (DCP), and MPLX (MPLX) that gather and process for the major’s U.S. operations.
CVX said December 3 it would set an annual capital and exploratory budget in 2021 of $14 billion and expects to spend $14-$16 billion through 2024, a steep drop from its prior annual budget range of $19-$22 billion. CVX plans to spend $5 billion in 2021 on its U.S. E&P business, of which $2 billion (36%) is earmarked for its Permian operations. That would be on par with its 2020 budget of $2 billion, which CVX revised lower in March on falling oil prices. CVX in July 2020 acquired Noble Energy (NBL), bolstering its Permian acreage and adding sizeable positions in the DJ and Eagle Ford basins. Nearly all CVX’s Eagle Ford gas is gathered and processed by ET while its DJ Basin G&P activity is split between DCP and Western Midstream (WES). Chevron’s Permian Basin gas is processed by over 20 midstream counterparties led by ET, MPLX, and Enterprise (EPD). According to East Daley’s G&P Allocation Tool, the largest midstream counterparties for CVX’s U.S. shale portfolio include ET, DCP, WES, and MPLX, which processed 26%, 18%, 14%, and 11% of its 1Q2020 gas production, respectively. Combined legacy CVX and NBL 2020 rigs in the Permian, DJ, and Eagle Ford have been 10, down from ~25 in 2018 and 2019. CVX’s lower capital budget reflects the challenges posed by $40/bbl oil for volume growth for midstream companies. – Robert Ingram Tickers: CVX, DCP, EPD, EQT, ET, MPLX, NBL, TRGP, WES
December 11, 2020:NGL prices between the Midcontinent and Gulf Coast have tightened considerably, posing a threat to NGL shipping demand and marketing earnings for midstreamers like ONEOK (OKE) that rely on a healthy spread.
Since 2018, the weighted basket price for NGLs at Conway, KS has averaged $2.42/bbl below Mont Belvieu pricing, but that discount has shrunk to $0.27 so far in 4Q2020. The Conway discount was as wide as $10.95/bbl in 3Q2018, driven by rising NGL production in liquids-rich basins like the Anadarko and Rockies, and NGL rail shipments into Conway from the Northeast. The latter source began to decline in 1Q2019 when Energy Transfer (ET) started its Mariner East 2 (ME2) pipeline to move NGLs to its Marcus Hook, PA terminal for exports, reducing Northeast rail volumes to Conway. As ME2 throughput grew, the Conway-Mont Belvieu NGL price spread fell. Lower commodity prices in 2020 have further dampened Midcontinent NGL supply, while ET’s Mariner East 2X pipeline (estimated 225 Mb/d capacity) is expected to come online by YE2020, diverting more Northeast rail shipments away from the Conway market. ONEOK (OKE) has especially benefited when spreads are wide, using its Arbuckle and Sterling pipelines to ship NGLs via its marketing affiliate from Conway to the premium Mont Belvieu market. We expect OKE’s NGL marketing earnings ($205 million, or 7% of estimated 2020 EBITDA) to be threatened with less supply into Conway limiting the spread, at least until more export infrastructure and demand arises at Mont Belvieu. Projects that connect Conway to Mont Belvieu, such as William’s (WMB’s) Bluestem Pipeline, also may see lower earnings as a result. – Ajay Bakshani, CFA Tickers: ET, OKE, WMB
December 4, 2020: Just as the skiers crowd the Colorado slopes every winter, rig activity in the DJ Basin is on the upswing: after rigs dropped to a low of three in July, operators have increased basin activity up to nine rigs.
We see two possible drivers: First, the recent ruling from the Colorado Oil and Gas Commission (COGCC) on 2,000-foot setbacks (see our November 25 Data Insights); Second, the uptick in oil futures, with average 1Q2021 WTI futures rising from $39/bbl in early October to over $46 in Friday’s trading. Some operators such as PDC Energy (PDCE) and private Bayswater Exploration have held rig activity steady through the downturn, averaging two and one rig(s), respectively since April. On the flip side, operator Occidental Petroleum (OXY), which laid down its last rig in late April, has returned to the basin, adding two rigs in late October and early November. PDC’s steady activity benefits DCP Midstream (DCP), as East Daley’s G&P Allocation Model shows PDC sends ~90% of its 568 MMcf/d of gas production to DCP’s processing system. Bayswater adds another ~20 MMcf/d to DCP, with the remaining ~7 MMcf/d to privately owned Rimrock. Recent activity also bodes well for Western Midstream (WES), as parent-company OXY currently sends ~94% of its 880 MMcf/d to WES’s facilities. - Melissa J. Saurborn Tickers: DCP, OXY, PDCE, WES
December 4, 2020:East Daley expects growing production next year in top-tier natural gas basins will lead to material volumes and earnings growth for certain midstream assets, a theme we highlight in our newly released 2021 Midstream Guidance Outlook.
Encouraging new natural gas pipeline contracts posted by Enable Midstream (ENBL) for its Line CP validate our view and suggest this uptrend may already have started in the Haynesville. After several painful years of reduced contract volumes and lower rates, ENBL in recent months locked in a net ~450 MMcf/d of new contracts on its Line CP, which moves gas from the Carthage Hub in East Texas to Delhi, LA. The new counterparties include GEP Haynesville, which added a hefty 300 MMcf/d via a seven-year contract; Rockcliff Energy, one of the fastest-growing Haynesville E&Ps, which subscribed to 150 MMcf/d for two years; and Chesapeake Energy (CHK), which reserved 100 MMcf/d in December via a one-month deal. Contracted rates are significantly discounted at ~$0.05-$0.08/Mcf, but the new deals still add $7 million in annual EBITDA upside to our Enable Gas Transmission model. While we do not forecast higher rates because of a large amount of underutilized eastbound capacity from the ArkLaTex Basin, Line CP still has ~400 MMcf/d of uncontracted capacity and Enable could add additional contracts if Haynesville production grows as we predict. - Matt Lewis Tickers: CHK, ENBL
December 4, 2020: Altus Midstream (ALTM) shares have soared following a generous dividend announcement, an early and unexpected holiday gift to shareholders, though East Daley sees a potentially tight liquidity window as a result.
In its 3Q2020 earnings, ALTM surprised the market with a proposed $1.50/share quarterly distribution that management said it would seek Board approval to begin in March 2021. ALTM’s shares traded Friday over $46, up 368% from $10.03 on November 4 prior to the announcement. The $1.50 quarterly distribution would have equated to a 60% yield based on the November 4 closing price. ALTM management, in its 3Q2020 earnings call, said it expects covenant leverage on its credit facility to be in a 2-3x range through 2022. But we estimate ALTM would come close to hitting the 5x covenant in 2022 if it follows through with the $1.50 quarterly distribution starting in 1Q2021 and the decision to retire its Series A preferred shares later next year (assuming it uses 100% debt for the refinance). In prior earnings calls, ALTM management highlighted the late 2021 to early 2022 period to take out its preferred shares via refinancing. The total payout for the preferred shares, which includes an embedded derivative option incentivizing a payoff within the late 2021 or early 2022 timeframe, would be north of $720 million. East Daley already forecasts 2021 Adj. EBITDA and DCF above the midpoint of management’s guidance, and we expect the proposed dividend would give ALTM less room for error due to the 5x leverage covenant on its revolving line of credit. However, there could still be upside to our forecasts if third-party gathering agreements or new drilling by parent-company Apache (APA) are realized sooner than we expect, or if our throughput projections on the Shin Oak and EPIC Crude pipelines are too low. In a less probable scenario, ALTM could partially refinance some of its current preferred shares with a new issuance or a different series of preferred shares that do not include an embedded derivative option. We estimate this path would be more expensive than using 100% debt to buy the shares out. If ALM refinances the preferred shares with new notes, the additional cash burden of a $1.50/share quarterly distribution would still seem to put ALTM in a much tighter liquidity window in 2022. In any scenario, we view ALTM’s proposed dividend as aggressive, particularly given the recent market tumult caused by the COVID pandemic. Despite its heady share gains, a more conservative approach, starting with a smaller dividend that gradually increases over time, may better reward ALTM shareholders over the long term. – J.R. Blumensheid Tickers: ALTM, APA, KMI
December 4, 2020: Maverick Natural Resources on December 2 said it acquired FourPoint Energy, the largest producer in the western Anadarko Basin and a potential boost for midstream providers such as ArcLight, Enable Midstream (ENBL), Energy Transfer (ET), and ONEOK (OKE) that process gas for FourPoint.
FourPoint adds to Maverick’s portfolio of mature properties in 13 states in seven producing areas, including the Anadarko, ArkLaTex, and Permian. The two companies are majority controlled by EIG Global Energy Partners, suggesting some portfolio consolidation by EIG. The transaction also includes MidPoint Midstream, which gathers primarily for FourPoint in four counties on the Texas-Oklahoma state line. According to East Daley’s G&P Allocation Model, Fourpoint’s largest gas processers include ArcLight (37%), Enable Midstream (ENBL), Energy Transfer (ET), and ONEOK (OKE), which processed 37%, 22%, 14%, and 13% of its 4Q2019 produced gas, respectively. FourPoint’s drilling has steadily declined from a peak of seven rigs at the start of 2018. While its rigs in 2018 were focused on ENBL, OKE, and ET systems, its drilling activity in 2020 has shifted to ArLight and DCP Midstream (DCP) systems. Maverick operated an average of 0.9 rigs in 2018 and 2019, generally maintaining two rigs for about half of the year. Nearly all its rigs have been on ArcLight’s MidCoast and Chapel Hill systems in the ArkLaTex, with limited drilling on Targa Resource’s (TRGP) Versado system in the Permian. The FourPoint acquisition may lead to more investment by Maverick on the Anadarko properties, which would bode well for rig stability and future volumes for FourPoint’s gas processors in the basin. – Robert Ingram Tickers: DCP, ENBL, ET, OKE, TRGP
December 4, 2020: Ethane recovery should subside in 4Q2020 as an earnings driver because of a shrinking frac spread, somewhat mitigated by higher rig counts.
Several midstream companies reported earnings beats in 3Q2020 (vs. Bloomberg consensus) and some of the biggest beats came from vertically integrated NGL players like Targa Resources (TRGP), Energy Transfer (ET), ONEOK (OKE), and DCP Midstream (DCP). Whether plant operators extract or reject ethane can juice or put a damper on quarterly earnings. While ethane rejected into the gas stream provides more MMBtu-linked earnings on long-haul gas pipelines, processed ethane carries a tariff on NGL pipes, at the fractionation unit, and at the export dock. NGL pipelines leaving NGL-rich basins like the Anadarko rely on favorable frac spreads to reward ethane processing. The uptick in NGLs produced in the Midcontinent in 3Q2020 likely will subside in 4Q based on rising gas prices, creating an incentive for plant operators to reject ethane instead of processing it. The average frac spread (Henry Hub – c2 Mt. Belvieu) has declined from more than $0.08/gal in 2Q2020 and 3Q2020 to $0.05/gal through the first two months of 4Q2020. The declining frac spread should be a headwind for DCP’s Southern Hills pipe volumes Q-o-Q, as DCP management warned on its 3Q2020 earnings call. By order of magnitude a 10 Mb/d change in NGL volumes on Southern Hills equates to about $2.5 million in quarterly EBITDA, net to DCP’s 66.7% interest. On the flip side, rigs have increased slightly from 17 on average in 3Q2020 to 20 in 4Q2020, with Citizen Energy and two smaller operators adding a rig each. – Rob Wilson Tickers: DCP, ET, OKE, TRGP
November 25, 2020:TC Energy (TRP) said November 17 that Natural Law Energy (NLE), a First Nations group, will invest up to C$1 billion ($764 million) in its Keystone XL Pipeline (KXL), a savvy effort to curry political favor ahead of an expected decision by the incoming Biden administration on the project.
TRP said the deal requires NLE to secure financing and expects the first phase of the transaction to close in 3Q2021. KXL is one of several crude oil egress megaprojects, including Enbridge’s (ENB) Line 3 replacement and the Trans Mountain Pipeline, designed to assure export avenues for Canada’s producers and eliminate bottlenecks. KXL would move up to 830 Mb/d of bitumen to the U.S. Midwest. By enlisting indigenous group support, TRP and NLE hope to win over President-elect Joe Biden, who has vowed to reject a presidential permit for KXL. We believe a veto would be moderately more costly politically given the broader coalition of project backers. Nevertheless, East Daley’s base case assumes KXL will not be built due to aboveground risks. While the odds remain long, TRP is pursuing the only viable path we see for winning political support. – Andrew Ware Tickers: ENB, TRP
November 25, 2020: Occidental Petroleum (OXY) announced on November 10 plans to eliminate carbon emissions by 2050 from the oil and gas it extracts and sells, becoming the first U.S. oil company to follow the lead of European peers like Shell (RDS) and Total (TOT) and announce a netzero emissions plan.
OXY formed a low carbon ventures organization in 2018 that focuses on new technologies. In the Permian, OXY stores 20 million metric tons of CO2 annually, which it claims would offset emissions from more than 4 million cars. OXY is the largest producer in both the Permian and DJ basins following its acquisition of Anadarko Petroleum in 2018. Nearly all its gas in the DJ Basin is produced on the Western Midstream (WES) system. OXY in 1Q2020 accounted for 65% of total throughput on WES’s DJ system. The largest midstream counterparties for OXY in the Permian are Enterprise (EPD), WES, and Caprock, which gather 27%, 21%, and 7% of its 1Q2020 Permian production, respectively. OXY also has its own G&P system in the Permian, which accounts for 8% of OXY’s produced gas. The OXY announcement continues its prioritization of ESG initiatives, though midstream counterparties could face challenges if more U.S. operators follow. – Robert Ingram Tickers: EPD, OXY, RDS, TOT, TRGP, WES
November 25, 2020: The Powder River was one of the hardest-hit basins in 2020 but is beginning to show life with four active rigs, a positive development for private Meritage Midstream, operator of the basin’s largest G&P system.
Gathered gas volumes on the Meritage system in September hit an all-time high of 189 MMcf/d, representing 48% of all volumes processed in the Powder River. The system saw a large volume drop in May due to curtailments, but volumes quickly ramped once shut-in production was brought back online in June. East Daley expects Meritage volumes will grow as three of the four active rigs in the basin operate on the system. The largest producers on Meritage are EOG Resources followed by Devon, which previously owned the system. The outlook is less positive for Crestwood Equity, (CEQP) which operates the second-largest Powder River Basin G&P system. CEQP system also saw volumes decline in May, but volumes since have not bounced back. No rigs are currently operating close to its system’s footprint, and its largest customer, Chesapeake Energy, is going through bankruptcy. CEQP’s EBITDA from the Powder River represents 9% of its total cash flow for FY2020. ONEOK (OKE) and Western Midstream (WES) have similar exposure to Powder River G&P services, which represents less than 1% of their FY2020 EBITDA. Both OKE and WES systems saw a decline in volumes in 2Q2020, although not as pronounced as for Meritage and CEQP, and both systems have rebounded near pre-COVID levels. -Andy Ptacek Tickers: CEQP, OKE, WES
November 25, 2020: A delayed start to the 2020-21 heating season is weighing heavily on winter gas prices, creating some risks to East Daley’s bullish 2021 natural gas price thesis and potential upside for gas-exposed midstream names.
Month-to-date heating degree days (HDD), which accumulate as temperatures fall below 65o Fahrenheit, are 26% below the 30-year U.S. average as of November 20, according to TrueWeather. Balmy weather has kept furnaces idled and postponed the start of seasonal storage withdrawals. As a result, Henry Hub futures for 1Q2021 delivery have declined 16% this month, averaging $2.85/MMBtu at press time. In our 2021 Midstream Guidance Outlook, we project rising gas prices in 2021 due to 3.9 Bcf/d of higher Y-o-Y gas demand, led by 3.0 Bcf/d of increased LNG exports, and 1.0 Bcf/d Y-o-Y less gas production. Our outlook assumes normal winter temperatures return, but a mild season like 2019-20 would reduce our 2021 ResCom demand forecast by 0.7 Bcf/d. The power sector should help cushion the blow were prices to fall in another mild winter, picking up more demand at the margin from coal switching. With a normal winter, we forecast higher gas prices will promote dry gas production from the ArkLaTex and Northeast, providing volume upside to midstream names with G&P assets in these basins. Northeast G&P names such as Williams (WMB) and MPLX (MPLX) should see material EBITDA growth as longterm acreage dedications prevent producers from seeking better rates on competing systems. Competition for G&P services in the ArkLaTex is fierce and we project EBITDA growth for ArkLaTex G&P names including WMB, Enable Midstream (ENBL), and Energy Transfer (ET) to remain relatively flat in 2021 despite increased volumes. -David Dubetz Tickers: ENBL, ET, MPLX, WMB
November 25, 2020: The Colorado Oil and Gas Conservation Commission (COGCC) on November 23 voted to approve longer 2,000-foot setbacks for new oil and gas development but included several “off-ramps” that should help to mitigate the effects to E&Ps and midstream companies operating in Colorado.
Known as Series 600, the setback rules are part of a larger package of regulations the COGCC approved for new oil and gas development in the state. Previously, operators required a 500-foot setback from above-ground structures to permit a well in Colorado. While longer setbacks pose some risk to future development, the COGCC included four off-ramps in the Series 600 rules which should cushion the blow. The new rules permit property owners to sign waivers agreeing to shorter setbacks for new wells, and E&Ps can apply to the COGCC for variances if they intend to employ “substantially equivalent” protections when drilling and completing new wells with shorter setbacks. East Daley previously analyzed a worst-case scenario resulting from 2,000-foot setbacks in the DJ, Piceance, San Juan, and Green River basins, and found Western Midstream (WES), DCP Midstream (DCP), Enterprise (EPD), and Williams (WMB) to be the most at-risk midstream companies (see our September 17 Navigator, “2,000’ Setbacks: Setting Back Colorado Oil & Gas Development”). Our analysis did not consider the exemptions included in the final Series 600 package. WES and DCP operate gathering systems primarily in the DJ Basin, and EPD and WMB primarily operate systems in the Piceance Basin. It remains to be seen how much latitude the COGCC will grant operators that seek permit variances, but investors should breathe easier knowing that a worst-case scenario is avoided. – Robert Ingram Tickers: DCP, EPD, WES, WMB
November 20, 2020: Ovintiv (OVV) is rumored to be selling its Eagle Ford acreage, which it bought in 2014, a potential driver for midstream operators.
OVV is the 13th largest oil producer and 20th largest gas producer in the Eagle Ford. The E&P, formerly named EnCana, produced 25 Mb/d and 70 MMcf/d in 1Q2020, nearly all in Karnes County, TX from 517 wells. Flint Hills Resources and Eastex Crude gather 34% and 30% of OVV’s Eagle Ford crude production, respectively. According to East Daley’s G&P Allocation Tool, Enterprise Products (EPD) gathers and processes ~90% of OVV’s gas production in the basin, with the balance split between DCP Midstream’s (DCP) and Energy Transfer’s (ET) Eagle Ford G&P systems. OVV currently operates no rigs in the Eagle Ford, down from two rigs in 1Q2020, with 86% of its basin rigs on the EPD system, according to East Daley’s Midstream Activity Tracker. Ovintiv operated an average 6.8 rigs in 3Q2020, including rigs in the Permian (3.0), Anadarko (2.0), and Western Canada (1.8). Its drilling is down over one-half from 1Q2020, when OVV operated 14.8 rigs in these three basins. The divestiture of OVV’s Eagle Ford assets could provide upside to EPD, Flint Hills Resources and Eastex Crude if a buyer jumpstarts spending in the basin. – Robert Ingram Tickers: EPD, ET, MPLX, OKE, OVV, PBA
November 20, 2020: Delaware Basin rig activity has rebounded nicely off August lows, particularly in the northern part of the basin, which should benefit Lucid, Targa Resources (TRGP), and MPLX (MPLX) with systems in the area.
Drilling in the Delaware Basin totaled 68 rigs in the latest week, up 13 rigs (19%) from lows set in August. Activity in the northern Delaware, which includes acreage 10 miles north of the Texas-New Mexico border in Lea and Eddy counties, NM, has been the most resilient and seen the most rig adds. E&Ps drilling in the northern Delaware include Tap Rock Resources, Cimarex Energy (XEC), and EOG Resources (EOG). East Daley anticipates that wells drilled by these producers will feed G&P systems operated by Lucid, TRGP, and MPLX in the northern part of the basin. Southern Delaware midstream operators faced steep rig reductions earlier this year, bottoming at just seven rigs (down 88% from Jan 2020) as E&Ps like Diamondback Energy (FANG), Parsley Energy (PE), and Callon Petroleum (CPE) exited the Delaware. Producers in the southern Delaware have added five rigs since August, including additions from private E&Ps including Jetta Operating Co., Colgate Energy, Primexx Energy Partners, and Encore Energy. Volumes on private G&P systems in the southern Delaware like Brazos, Eagle Claw, and Salt Creek have declined since early 2020 but stand to benefit if E&Ps continue to boost drilling and completion activity there. Meanwhile, drilling in the middle Delaware has remained mostly flat, with slight reductions in rig counts in the past several months as operators migrate north and south. – Ryan Smith Tickers: CPE, EOG, FANG, MPLX, PE, TRGP, XEC
November 20, 2020: Energy Transfer’s (ET) Blue Marlin Deepwater Port (BMOP) recently joined three other pending applications with the U.S. Department of Transportation’s Maritime Administration to build a deepwater port terminal to export crude oil and accommodate fully loading very large crude carriers (VLCCs).
The BMOP proposal involves building a new pump station and a 37-mile pipeline from an existing tank farm in Nederland, TX to the existing Stingray Pipeline, which transports gas from a platform complex in the Gulf of Mexico. ET would convert both facilities to oil service from natural gas. The proposed facility aims to load up to 2 MMb/d. The BMOP proposal comes late to the game as competing export projects have been working through the application process for well over a year. Enterprise (EPD) and Enbridge (ENB) in January 2019 filed for the Sea Port Oil Terminal (SPOT), which would handle 2 MMb/d off the coast of Freeport, TX. The pair held meetings on SPOT’s draft environmental impact statement in February 2020 but suspended the application in June 2020. Other projects include the Bluewater terminal, proposed by Phillips 66 (PSX) and Trafigura to load 2 MMb/d off the coast of Corpus Christi, TX and Freepoint’s Gulf Link port off the coast of Freeport which has a smaller design at 1 MMb/d. Beyond these offshore proposals, Buckeye’s new South Texas Gulf terminal at Corpus Christi would dredge to allow access to a land-based port. Despite interest in expanding export capacity, East Daley’s Crude Hub Model projects a significant overbuild in crude export infrastructure on the U.S. Gulf Coast. However, long lead times and optionality for an oil market recovery likely justify pre-engineering announcements, along with the prospect of a wellhead-to-water integrated logistics solution providing a competitive edge. For the short term, we see limited likelihood for anchor shipper interest. - Alex Gafford Tickers: ET, EPD, ENB, PSX
November 20, 2020: Sempra Energy (SRE) announced a positive final investment decision (FID) for its Costa Azul LNG export project in western Mexico, a project that should open a new egress route for Permian gas on TC Pipelines’ (TCP) North Baja Pipeline once it starts operations.
Sempra’s ECA Liquefaction subsidiary will build the single-train project next to its existing LNG import facility in Baja California, Mexico at an estimated cost of ~$2 billion. Phase 1 has a nameplate capacity of 3.25 million tons (MT) per annum of LNG and an initial offtake capacity of 2.5 MT (~335 MMcf/d). The project is backed by 20-year sale and purchase agreements with Mitsui & Co. and an affiliate of Total. North Baja Pipeline, owned by TCP, has awaited FID on the Costa Azul export project for its North Baja Xpress project, which will double pipeline capacity. North Baja connects to the Gasoducto Bajonorte pipeline to reach the Costa Azul LNG facility. North Baja executed a binding precedent agreement for a 20-year initial term for the full 495 MMcf/d of capacity at a proposed negotiated rate of $0.094/MMBtu, according to the project filing, which would bring total expansion revenue to ~$17 million per year. Including estimated annual Opex of $577,000 and property taxes of $3.3 million, TCP would realize annual EBITDA of ~$14 million for the North Baja project. Estimated total project cost is ~$90 million, giving this project an EBITDA multiple just above 6.4x. SRE projects Phase 1 of the Costa Azul project will enter service in late 2024. By utilizing existing assets at a relatively modest investment, the Costa Azul LNG export should boost returns for TCP’s asset while opening new markets for Permian gas. – Zack Van Everen Tickers: SRE, TCP
November 20, 2020: Gulfport Energy (GPOR) said November 14 it is filing for Chapter 11 bankruptcy, the latest E&P to file for debtor protection and a new counterparty risk for midstream names like Summit Midstream (SMLP) and Equitrans (ETRN) that gather for GPOR in the Utica, as well as TC Energy (TRP) and Energy Transfer (ET) which own interstate pipes on which GPOR has firm contracts.
Oklahoma City, OK-based GPOR said it entered into a restructuring agreement to secure $262.5 million in debtor-in-possession financing from its existing lenders under its revolving credit facility, including $105 million in new money available upon court approval. GPOR expects to eliminate ~$1.25 billion of about $2.5 billion in funded debt as part of the restructuring agreement. GPOR is asking the court to reject firm contracts with Rockies Express Pipeline (owned by Tallgrass Energy and Phillips 66 (PSX)), Rover Pipeline (owned by ET and Blackstone), Cheniere Energy’s (LNG) Midship Pipeline, and TRP’s ANR, Columbia Gulf, and Columbia Gas pipelines. TRP, Midship Pipeline, and Rockies Express in September petitioned the FERC to preserve its jurisdiction over gas transportation agreement in the event of a GPOR bankruptcy. Gulfport produced 1.5 Bcf/d in 4Q2019, ~85% from the Utica in the Northeast and the balance from the SCOOP in the Anadarko Basin. According to East Daley’s G&P Allocation Tool, ETRN and MPLX (MPLX) processed 43% and 32%, respectively of GPOR’s Utica production. In the Midcontinent, Intensity Midstream’s Woodford Express system processed nearly all GPOR’s SCOOP production, and GPOR accounted for 92% of gas volumes gathered on the Woodford Express system. In the Utica, GPOR accounted for 18%, 13%, and 6% of volumes gathered by SMLP, ETRN, and MPLX, respectively. Midstream operators have braced for a GPOR bankruptcy filing, and several confront downside as the producer restructures. – Robert Ingram Tickers: ET, ETRN, GPOR, LNG, MPLX, PSX, SMLP, TRP
November 13, 2020: The Anadarko Basin averaged 16 rigs in 3Q2020, a historic low, but E&Ps are returning to the basin ahead of expected higher gas prices this winter and in 2021.
An average of 18 rigs drilled in October and 21 rigs in the first week of November, with operators including Continental Resources (CLR), Citizen Energy III LLC, Mewbourne Oil Co., and GBK Corp. leading the rebound. Our samples show Anadarko gas volumes increased ~12% W-o-W and by ~5% in 3Q2020. About 40% of current Anadarko rigs are active on acreage served by gathering systems operated by DCP Midstream (DCP) and Enable Midstream (ENBL). DCP’s Midcontinent system comprises ~225 miles of pipelines in Grady, Garvin and McClain counties, OK. It connects to 10 gas plants, including the Chitwood, Cimarron, Mustang, and Sherhan plants. Total processing capacity allocated to the DCP system is 1,612 MMcf/d, though we estimate only 10% of capacity is currently being used. In 1Q2020 the DCP system gathered ~274 MMcf/d, or ~7% of the entire basin’s gas production of ~3,649 MMcf/d. With Henry Hub priced over $3/MMBtu this winter and ~$3.15 for 2021, East Daley believes Anadarko rig activity will increase to average 21 rigs next month and 25 rigs in 2021 at prevailing oil and gas prices. In 1Q2021 we project G&P volumes of ~7,900 MMcf/d, 13% lower Y-o-Y vs. ~9,100 MMcf/d in 1Q2020. While activity is modest, we expect the DCP system will maintain its share of rigs in the basin. – Maria Paz Urdaneta. Tickers: CLR, DCP, ENBL
November 13, 2020: EOG Resources (EOG) announced last week the Dorado gas discovery in South Texas, a potential boost for future Eagle Ford drilling that could lift volumes for several gas gatherers.
EOG said Dorado is a 21 Tcf net natural gas resource located primarily in the prolific dry gas window in Webb County, TX. Since 2019, EOG has drilled 17 wells in the Dorado play. EOG said returns on its Dorado wells compete with its top oil prospects, and that Dorado provides an additional 1,250 net locations in the Eagle Ford. EOG currently has one rig active in Webb County that began drilling on October 30, indicating development of the Dorado discovery is afoot. Webb County accounted for 28%, or 2.2 Bcf/d, of 1Q2020 Eagle Ford gas production. EOG is the largest gas producer in the Eagle Ford, with 73% of its gas production (both wet and dry) from Webb, Karnes, and Gonzales counties. The largest gas gatherer for EOG in the Eagle Ford is Navarro Midstream Services, a subsidiary of Lewis Energy. Of EOG’s U.S. rigs in 2019, ~28% drilled in the Eagle Ford and 53% in the Permian Basin. Nearly all EOG rigs active last year in South Texas operated in the wet gas window of the Eagle Ford. According to East Daley’s Midstream Activity Tracker, 82% of EOG’s Eagle Ford rigs in 2019 were on Enterprise’s (EPD) gathering system and 8% on Energy Transfer’s (ET) system. The EOG announcement, if it fulfills expectations, could provide upside for midstream companies in the dry gas portion of the basin. – Robert Ingram & Melissa J. Saurborn Tickers: EOG, EPD, ET
November 13, 2020: Bonanza Creek Energy (BCEI) on November 9 said it agreed to buy HighPoint Resources (HPR) for ~$376 million, a deal that would create the fifth-largest oil producer in the DJ Basin and potentially stabilize volumes into DCP Midstream (DCP).
The combined E&P would have a continuous leasehold of ~206,000 net acres and ~50 Mboe/d production in the DJ. With a rural footprint and only ~8% of acreage subject to federal mineral or surface regulations, BCEI expects minimal effects from DJ Basin regulatory risks. Our analysis confirms this perspective. BCEI and HPR are among the least at-risk E&Ps in the DJ if Colorado adopts 2,000’ setbacks for new wells (see our September 17 Snapshot, “2,000 Setbacks: Setting Back Colorado Oil & Gas Development”), which we expect is imminent. HPR and BCEI entered 2020 operating a single rig each, both mainly drilling on DCP’s G&P system. HPR dropped its rig in March and BCEI stopped drilling in April. According to East Daley’s G&P Allocation Model, DCP gathered 86% of the combined company’s 1Q2020 production. The two E&Ps together accounted for ~15% of 1Q2020 gas production gathered by DCP and Noble Midstream (NBLX) and ~36% gathered on Summit Midstream’s (SMLP) DJ system near the Colorado-Wyoming state line, in which Highpoint holds an original stake. The transaction continues a trend of increased M&A activity in the DJ and could provide rig stability for associated midstream counterparties. – Robert Ingram Tickers: BCEI, DCP, EOG, HPR, NBLX, SM
November 13, 2020: Plains All American’s (PAA) 3Q2020 results highlight a likely theme for Permian egress pipes in the coming years: deficiency payments.
Management previously stated on its 2Q2020 earnings call that PAA had collected ~$25 million in revenue from deficient shippers that it would later recognize in 3Q2020. That oil volumes would decline amid economic lockdowns and falling prices is no surprise. But PAA shocked the market last week, disclosing actual deficiency payments in its 3Q2020 financials of $64 million, nearly $40 million higher. While PAA did not call out specific pipes or shippers, 2Q2020 pipeline financials filed with FERC show the primary suspect was Cactus II, PAA’s new Permian-to-Corpus Christi pipeline. Compressed oil prices are a big factor behind the deficiency payments. The spread between Midland and Magellan East Houston (MEH) has collapsed from $2.50/bbl at the start of 202020 to ~$0.40 currently, which is well below the lowest Permianto-Corpus tariff rate. Volumetric data filed with state regulators through September show Cactus II has recovered some volumes from April lows, but the pipe is still running below its total commitment level. East Daley believes another reason for Cactus II’s underutilization is the composition of its committed shippers. Commodity trading giant Trafigura (300 Mb/d) is a project anchor, and inadequate hedges could affect Trafigura’s ability to capture arbitrage now that spreads are tighter between Midland, Houston, and Brent markets. Trafigura contracts capacity at Corpus Christi docks owned by NuStar (NS) and Buckeye Partners, and other state data show lower export volumes at these docks. – AJ O’Donnell Tickers: NS, PAA
November 13, 2020: Higher ethane recovery drove NGL production and transportation volumes in 3Q2020, a rare positive midstream fundamental in the North American landscape. DCP Midstream (DCP), Enable (ENBL), EnLink (ENLC), Enterprise (EPD), Energy Transfer (ET), and ONEOK (OKE) all reported an uptick in NGL production.
Even with Hurricane Laura shutting down significant cracker capacity in September, ethane recovery and production levels remained near all-time highs. Ethane export demand grew as more international ethane crackers came online and more ethane export capacity starting along the Gulf Coast. According to the EIA, ethane exports increased 15% Y-o-Y in July and August 2020 despite widespread COVID-19 degradation. Besides higher ethane demand, shut-ins and lower drilling caused by the spring price collapse have reduced ethane supply, driving a bullish supply/demand mismatch. As total ethane production is still below pre-COVID levels, we expect continued reductions in ethane rejection and commensurate positive pricing and volume fundamentals for the NGL logistics providers. ET and EPD sit in the catbird seat with the only U.S. ethane export terminals, which in fairness represent only <1% and 2% of our 2020 EBITDA projections for each company, respectively. Given increasing export demand, it would not surprise us to see more export projects such as ET’s 180 Mb/d Orbit ethane terminal, which we forecast to generate $100 million/year of EBITDA once complete in 4Q2020. – Ajay Bakshani, CFA Tickers: DCP, ENBL, ENLC, EPD, ET, OKE
November 6, 2020: Canadian E&P operators historically implement a seasonal rig “spring break-up” that lasts from March to June, but lockdown-induced price weakness has squashed the normal resumption of activity.
Because the ground becomes too soft and muddy for transporting heavy oilfield equipment, rig counts in the Western Canadian Sedimentary Basin (WCSB) typically drop as much as 20% in May from their January/February peak. Operators would normally bring back rigs in June and July, but the price collapse has muted the seasonal rebound. The WCSB rig count is currently at 65 rigs and has ranged from 10 (May 10) to 311 (February 9) in 2020. Nearly half of these rigs are in Alberta, with Alberta’s rig share normally ~70% of the total count. Operators with the weakest rig recovery include Husky (HUS.TO), Cenovus (CVE), Ovintiv (OVV), and Canadian Natural Resources (CNQ). HUS and CNQ have midstream units that primarily gather their own gas, servicing 62% and 90% of respective total gas production. Pembina (PBA) gathers and processes 80% of OVV and 54% of CVE gas production. The sustained deviation from the spring break-up phenomenon portends medium-term trouble for WCSB midstream counterparties. – Robert Ingram Tickers: CNQ, CVE, HUS.TO, OVV, PBA
November 6, 2020: With spare Northeast takeaway scarce, the Rover Pipeline, owned 35% by Energy Transfer (ET) and 65% by Blackstone, has been flowing gas at or above nameplate capacity.
A May 2020 explosion on the Texas Eastern (TETCO) system cut up to 2 Bcf/d of Northeast egress capacity while Marcellus and Utica gas production has been robust. Appalachian gas prices have been under severe pressure, and wide spreads between Dominion South and Michcon markets open an arbitrage opportunity for Rover shippers. Rover ran almost 200 MMcf/d over nameplate capacity of 3.5 Bcf/d when spreads from Dominion South to Michcon were widest, as shippers used short-term and interruptible contracts to maximize deliveries. About 14% of Rover’s capacity, or ~500 MMcf/d, is not under long-term subscription. In October, Rover contracted short-term volumes at up to $0.40/MMBtu, contributing ~$3 million of additional revenues. These rates are near legacy tariffs that have historically been out of the money. Dominion South to Michcon forward spreads average $0.50/MMBtu through 2021 and, if these spreads hold, Rover should continue to see $2-$3 million in monthly revenue uplift. Besides Rover, Rockies Express and Enbridge’s (ENB) NEXUS pipeline also are benefitting from tight egress out of the Northeast and could see higher rates for new long-term contracts. - Zack Van Everen Tickers: ENB, ET
November 6, 2020: Equitrans Midstream (ETRN) again delayed the expected start-up of its Mountain Valley Pipeline (MVP) to 2H2020 from 1Q2020, a decision which will prolong the time before Northeast producers see relief from regional egress constraints.
In its 3Q2020 earnings report, ETRN cited construction delays resulting from legal challenges for holding up construction on ~25 miles of the project. In mid-October, the Fourth Circuit Court of Appeals issued a temporary administrative stay of MVP’s Nationwide 12 permit, preventing construction over water crossings until the Court rules on the full motion to stay. The Court issued the temporary stay just a week after FERC lifted a year-long stop-work order. MVP is also waiting on approval to pass through the Jefferson National Forest. East Daley had assumed ETRN’s prior 1Q2020 start-up target was optimistic due to its permitting challenges, and we have modeled MVP starting in 3Q2020. ETRN also raised its cost estimate to $5.8-$6.0 billion. ETRN originally projected MVP to cost $3.7 billion when construction started in 2018. With only 8% left to complete, MVP’s uncertain outlook drives the fate of long-term Northeast production and price differentials. In our Northeast Production & Constraint Forecast, we model that rapid growth in regional gas production requires MVP to be in service by 2022 or the Northeast will face egress capacity constraints and structurally wider differentials. We explore the ramifications of MVP delays for ETRN and competing Northeast pipes in our latest Snapshot, “Mountain Valley Pipeline Hurdles: Only the Last Mile Counts”. – Andrew Ware Ticker: ETRN Ticker: ETRN
November 6, 2020:While the Keystone XL project grabs most headlines, the base Keystone pipeline drives incremental bearishness to our TC Energy (TRP) outlook in a $40/bbl WTI price strip.
Keystone serves the Midwest and Gulf Coast via take-or-pay contracts totaling 555 Mb/d. A 2014 FERC filing shows most committed barrels delivered into Wood River, IL (375 Mb/d) with the rest to Cushing (155 Mb/d). Almost all barrels that originate in Canada are on a 20-year term. East Daley expects oil production to decline in most basins with lower prices. Our Crude Hub Model predicts the combination of lower supply into Cushing and poorly timed egress projects will exacerbate overbuilt transportation between Cushing and the Gulf Coast. This supply/demand imbalance leads to lower asset utilization and compressed rates. The current spread between Cushing and the Gulf Coast is about $0.65/bbl, and Seaway’s spot tariff rate is as low as $0.35 for light crude and $0.75 for heavy crude. The effective tariff rate for Marketlink, Keystone’s southern leg, in 2Q2020 was $2.32/bbl, partially supported by above-market MVCs. Though we already risk Marketlink’s volumes, rates, and ability to market barrels, the egress oversupply may drive more downside to cash flow. Total MVCs in place from Cushing to the Gulf Coast are unknown, but the same 2014 FERC filing showed Gulf Coast-bound commitments of 380 Mb/d. Handicapping the effective tariff rate by even $0.30/bbl could create more than $75 million of additional annual revenue risk to Keystone than we currently model, driving us even further below Street consensus for 2021 through 2024 than our current forecast. – Rob Wilson Ticker: TRP
November 6, 2020:At press time, Democratic Party nominee Joe Biden was leading by razor-thin margins in Georgia, Pennsylvania, Nevada, and Arizona.
President Trump vowed to challenge election results but, barring judicial intervention, Biden has the more plausible path to the White House. We see many risks, and a few opportunities, for energy and the midstream sector in a Biden presidency: more oversight, new climate regulations, slower permitting, and new hurdles for certain pipe projects. Methane rules likely are reinstated, and the Paris climate agreement is back on the table. Biden is calling for a permitting freeze on federal lands, which creates uncertainty for midstream names like DCP Midstream (DCP), Energy Transfer (ET), Plains All American (PAA), and Enterprise Products Partners (EPD) that operate assets near federal lands on the New Mexico side of the Delaware Basin (see chart) We also see risks to ET’s Dakota Access Pipeline (DAPL) in a Biden term. An appellate court ruling against DAPL would kick its environmental review back to regulatory agencies and potentially result in its shutdown amid a protracted re-permitting process. Biden also has pledged to revoke a presidential permit for the Keystone XL project. East Daley’s base case already assumes that TC Energy (TRP) will not check all the regulatory and political boxes necessary to build KXL, so additional project risks would not affect our outlook. Regulatory roadblocks and resource access aren’t bad for all, just bad for certain players. If legal and regulatory hurdles constrain resource access and transportation under a Biden administration, we would expect this to strengthen oligopoly characteristics within midstream for existing assets. EDC Team Tickers: DPC, EPD, ET, PAA, TRP
October 30, 2020: Bakken producers have been slow to return rigs after the downturn in 2Q2020.
Many E&Ps operating in the basin have outlined plans to keep rig counts flat until WTI prices return to ~$50/bbl. While basin activity remains depressed, Marathon Oil (MRO) has increased drilling from zero rigs in June to three rigs operating today. We model two of the rigs on acreage served by ONEOK’s (OKE) Bakken G&P system, while the third rig is operating on Targa Resources’ (TRGP) Badlands system. Increased drilling activity is a welcome sign for OKE, the largest gas processor in the basin. Drilling activity is still far below pre-COVID levels, as we model only seven rigs operating on the system, a 72% reduction from rig counts at the start of the year. The additional rig contributions from MRO don’t change our 4Q2021 EBITDA forecast for OKE’s Bakken system of $130 million, down ~11% from 4Q2019 earnings of $146 million. MRO is the only driller operating on TRGP’s Badlands system, which is in line with our forecast. Assuming producers maintain one rig on TRGP’s system in 4Q2020 and an average of 1.5 rigs in 2021, we expect the asset to generate $11 million in 4Q2021, down 18% from 4Q2019. – Tyler Heather Tickers: MRO, OKE, TRGP
October 30, 2020: A recent surge in Eagle Ford Shale drilling benefits Energy Transfer (ET), though a quadrupling of recent activity would be required to thwart a large EBITDA decline we project through 2024 on its gathering system.
According to East Daley’s Midstream Activity Tracker, E&Ps have added eight rigs in the Eagle Ford from the week of September 13 to October 18, four on ET’s Eagle Ford system. The system earned $484 million in EBITDA in FY2019, or 30% of segment EBITDA and 4% of ET’s total EBITDA. It is the largest G&P system in ET’s portfolio by volume and earnings. East Daley expects ET’s Eagle Ford system to maintain current activity levels in 4Q2020 based on our latest Blueprint Model. The relative resurgence in Eagle Ford rigs is a positive sign, but the treadmill is onerous. The most recent rig count is well below pre-COVID levels of around 25 rigs, and ET will need much more activity to battle volume and EBITDA declines. We expect the system’s EBITDA to plummet from $484 million in 2019 to $220 million by FY2024, making it one of the company’s largest declining assets over the next few years. According to East Daley’s system-level Production Scenario Tools, activity levels would need to quadruple to around 20 rigs for the system to maintain its historical volumes and EBITDA. — Ajay Bakshani, CFA Tickers: ET
October 30, 2020: EQT, the largest U.S. gas producer, will buy Chevron’s (CVX) Northeast assets and potentially open a point of leverage, and an M&A window, with Equitrans Midstream (ETRN). CVX’s Northeast assets comprise ~800,000 acres in the Marcellus-Utica and a 31% interest in the Laurel Mountain gathering system (Williams (WMB) owns the remaining 69%) in Pennsylvania.
We expect EQT to be more active than CVX, which has not operated a rig on the acreage since January 2020. EQT has averaged ~4 Northeast rigs in 2020. We predict upside for WMB as most of CVX’s current Northeast production is on the Laurel Mountain JV and WMB’s Ohio Valley Midstream system. The news follows rumors that EQT also made an offer to acquire CNX, which holds over 800,000 acres in the MarcellusUtica and produces ~1.5 Bcf/d. CNX recently rolled up its midstream gathering partner, CNX Midstream (CNXM). EQT would produce over 5.5 Bcf/d if it completes the deal. EQT has curtailed production in 2020 in response to weak market conditions, and the acquisition of the CVX acreage and potentially CNX would bring EQT further market power. While these deals provide upside to EQT, the read-through to ETRN isn’t as clear. EQT may steer capex away from ETRN acreage, a potential lever for its contract dispute on the Hammerhead pipeline. However, EQT may look to divest gathering assets, such as the stake in Laurel Mountain or CNXM legacy assets, a potential omnibus deal that could reduce uncertainty for both parties. East Daley estimates CNXM legacy assets gathered an average of 1.9 Bcf/d in 1Q2020 and generated $61 million in Adj. EBITDA. We estimate Laurel Mountain gathered ~335 MMcf/d in 1Q2020 and generated $10 million in Adj. EBITDA. – Alex Gafford Tickers: CNX, CVX, EQT, ETRN, WMB
October 30, 2020: Cenovus Energy (CVE) said it has reached a deal to purchase Husky Energy (HSE.TO) to create the third-largest Canadian oil producer, behind Canadian Natural Resources (CNQ) and Suncor Energy (SU), as the E&P consolidation wave moves north.
Husky shareholders will receive 0.7845 of a Cenovus share plus 0.0651 of a Cenovus share purchase warrant for each Husky share. The all-stock Husky deal, valued at C$3.8 billion (US$2.9 billion), should close in 1Q2021. Once the Husky acquisition is complete, 58% of combined 1Q2020 gas production in the Western Canadian Sedimentary Basin (WCSB) will come from pre-deal Cenovus, with 88% gathered and processed by Pembina (PBA). Most G&P activity is done on legacy Veresen (VSN.TO) systems acquired by PBA in 2017. Nearly 61% of legacy Husky natural gas production is gathered on its own midstream systems, according to East Daley’s G&P Allocation Model. Of the average 1.9 Husky and 3.4 Cenovus rigs deployed so far in 2020, 49% and 90% were on the PBA system, respectively. PBA gathers and processes ~3.4 Bcf/d and is Canada’s largest midstream gatherer, servicing ~19% of WCSB gas production. The combined company will account for 12.5% of PBA volumes, and the tie-up should provide increased stability and certainty for the midstream provider. The deal comes less than a week after ConocoPhillips’ acquisition of Concho (COP-CXO) and Pioneer’s purchase of Parsley (PXD-PE). East Daley hosted a webinar on October 29 to explore the implications of E&P merger mania. Log in to access a replay. – Robert Ingram _CNQ, COP, CVE, CXO, HSE.TO, PBA, PE, PXD, SU, VSN.TO
October 30, 2020: Energy Transfer (ET) on October 26 cut its distribution 50% to $0.1525/quarter ($0.61 annualized), sending its unit price plummeting 20% for the week.
Management’s lack of explanation did not help. The cut surprised us, as according to East Daley’s Blueprint Financial Models, ET’s distribution coverage should stay well above 1.5x through FY2024. Even accounting for a DAPL shutdown, we expect ET to maintain greater than 1.1x coverage. Until management provides more operational guidance, leverage and credit ratings agencies likely explain the move. While coverage is healthy through 2024, we expect leverage to remain above 5.0x through FY2022. Rating agencies such as Moody’s already have ET on negative outlook and have warned against sustained periods of leverage above 5.0x. We think this is a much more likely rationale than operational issues. Other investment-grade midstream companies with negative outlooks at the rating agencies include TC Pipelines (TCP), TC Energy (TRP), and MPLX LP (MPLX), which are all rated Baa2/BBB. For highyield midstream companies, risk from E&P parents (ex. Western/Occidental) often drive credit ratings. A high yield also can portend distribution cut risk. ET’s yield was near 20% prior to the announced cut. Seventeen midstream companies in East Daley’s coverage have yields above 11% (see chart). When comparing leverage to equity yield, ONEOK (OKE) and Genesis Energy (GEL) appear most likely to cut their dividends based on these key risk metrics. – Ajay Bakshani, CFA Tickers: ET, GEL, MPLX, OKE, OXY, TCP, TRP, WES
October 23, 2020: Aethon Energy has been one of the most active drillers in the Ark-La-Tex Basin over the last few years, consistently running anywhere from 5 to 9 rigs, yet few area midstream companies are benefiting.
Aethon’s Louisiana gas volumes have climbed to over 1 Bcf/d since early 2019, making the private E&P one of the fastest growers in a highly competitive basin for G&P. Publicly traded midstream companies have largely missed out on the volume upside as Aethon and its midstream subsidiaries gather ~90% of the company’s own Louisiana production. Aethon is following a similar blueprint in East Texas where it has deployed 2 to 3 rigs with midstream subsidiary Kudu Midstream gathering most volumes. While East Daley forecasts volume upside for most publicly traded Ark-La-Tex G&P names heading into 2021, public midstream growth is mitigated when active producers drill on private systems. Skinny margins and rate attrition across the basin suggest to us that Ark-Las-Tex G&P systems should consider consolidation, a phenomenon that has yet to occur. - Matt Lewis
October 23, 2020: East Daley models EnLink Midstream’s (ENLC) 3Q2020 Adj. EDITDA of $250 million, $4 million above consensus estimates for the quarter (as of Oct. 2).
We expect significant growth from the Permian segment Q-o-Q as interstate samples show a large increase in throughput volume. ENLC’s Delaware G&P system sample increased by 25% Q-o-Q, indicating that producers have possibly brought curtailed production back online. This could also show that the Tiger processing plant is now operational. Besides the Delaware system, ENLC’s Midland G&P system is seeing a ~9% increase in interstate volumes Q-o-Q. A rebound in Permian gas prices is another likely positive. East Daley models percent-of-proceeds (POP) contract exposure on ENLC’s Midland system using the El Paso Permian spot price, which historically correlates well with the segment’s NG sales. East Daley expects improvement in overall NG margins as the El Paso Permian spot price improved by 26% Q-o-Q, which we model will increase gross margins by $2 million in 3Q2020. We expect that greater volumes on both systems, coupled with the increase in in-basin spot prices for natural gas, will help lift the Permian segment’s segment profit from $44 million in 2Q2020 to $48 million in 3Q2020. The projected uplift in the Permian is likely a major driver of our above-consensus EBITDA estimate for 3Q2020. - Jarred Blumensheid Tickers: ENLC
October 23, 2020: In early November, the Colorado Oil and Gas Conservation Commission (COGCC) will promulgate new drilling regulations, including potential 2,000’ setback requirements for permitting new wells, that could constrain production.
This is a concern for DCP Midstream (DCP), which operates the largest gas G&P system in the basin. DCP’s system processed 41% of the DJ’s gas in 3Q2020, according to pipe samples, and serviced acreage on which 42% (4.4 rigs) of the basin’s 12.5 average rigs have drilled in 2020. DCP’s G&P system comprises ~3,500 miles of pipeline in Weld County, CO and connects to 10 plants with 1,160 MMcf/d of combined capacity. It gathered 1,252 MMcf/d in 2Q2020, up 15% Y-o-Y vs. 1,085 MMcf/d in 2Q2019. With Henry Hub priced over $3/MMBtu this winter and ~$2.75 for 2021, East Daley forecasts an average of four rigs in the DJ in 4Q2020 and six rigs in 2021. In 4Q2020 we project gas production of 2,881 MMcf/d, 2% lower Y-o-Y vs. 2,943 MMcf/d in 4Q2019. DCP is among midstream system operators that may see less future drilling if the COGCC’s new regulations mandate longer well setbacks (see our Sept. 17 Snapshot, “2,000’ Setbacks: Setting Back Colorado Oil & Gas Development”). If rig counts were to fall 75% by the start of 2022 due to more restrictive setback regulations, East Daley projects DJ gas production would fall 16% to ~2,370 MMcf/d in FY2022. Holding production flat would require 5.5 rigs on the DCP system. If activity remains lower because of lower prices and tighter regulations, we would project a modest EBITDA decline of ~$6 million from 2020 to 2024 for the asset. Most of DCP’s legacy volumes are under percentof-proceeds contracts, but minimum volume commitments backstop its newer G&P plants, somewhat mitigating near-term downside. Further, a robust inventory of grandfathered permits likely reduces near-term cash flow challenges. – Maria Paz Urdaneta. Ticker: DCP
October 23, 2020: Delaware Basin producers appear to be favoring the New Mexico side of the basin, likely because of potential risk to Federal lands access if President Trump loses the White House in November.
That should lead NM-focused midstream volumes on the north side of the basin to benefit through the first half of 2021. As the Delaware rig count decreased this year, one interesting trend stands out: operators did not lay down rigs at the same rate on the New Mexico vs. Texas portions of the basin. While the NM rig count in January was roughly twice the current count (99 vs. 44), the NM market share of Delaware rigs increased from 44% to 64%. On the flip side, the TX rig count dropped from 126 to 25 over the same time, while Texas market share decreased from 56% to 35%. Operators have proprietary reasons for moving rigs (e.g. economics, commitments, etc.), but another factor is the potential ban on drilling or fracking on federal lands. The NM portion of the Delaware Basin is rife with federal leases, while the TX side is almost entirely non-federal lands. (see our Sept. 9, Snapshot, “This Land is Your Land – Potential Impacts of a Drilling Ban on Federal Lands”). According to East Daley’s G&P Allocation model, the four most active operators in New Mexico include ExxonMobil (XOM), Devon Energy (DVN), EOG Resources (EOG), and Concho Resources (CXO). They supply most volumes to EnLink (ENLC), Enterprise (EPD), DCP Midstream (DCP), Energy Transfer (ET), Targa Resources (TRGP), and privately owned Lucid Energy. We expect NM volumes to outpace TX Delaware volumes for the next two to three quarters of results based on Federal lands uncertainty. - Melissa J. Saurborn Tickers: CXO, DVN, ENLC, EPD, ET, TRGP, XOM
October 23, 2020: Upstream consolidation accelerated this week following ConocoPhillips’ (COP) announced $9.7 billion purchase of Concho Resources (CXO) and Pioneer Natural Resources’ (PXD) $4.5 billion buyout of Parsley Energy (PE).
The two all-stock deals for a combined $21.2 billion, including assumed debt, will create the second- and third-largest oil and gas producers in the Permian Basin, behind Occidental Petroleum (OXY). The companies plan to close both deals in 1Q2021. COP will gain CXO’s 800,000 gross Permian acres, including 520,000 acres in the Delaware Basin where there are potential operational synergies (see our October 20 Snapshot). PXD will acquire PE’s 248,000 net acres, bolstering its leading position in the Midland and establishing a foothold in the Delaware. Among midstream names, Targa Resources (TRGP) in particular will see impacts as it gathers and processes 79% of PE and PXD’s combined Permian gas production (see our October 22 Snapshot) A post-merger Pioneer would account for nearly 30% of TRGP’s gathered Permian gas volumes. ConocoPhillips would have more diverse exposure to Permian midstream companies once the CXO deal is finalized, including Energy Transfer (ET), TRGP, Western Gas (WES), and Lucid, which would gather 27%, 17%, 12%, and 10% of its gas production, respectively. Major crude gatherers for COP-CXO and PXD-PE include Plains All American Pipeline (PAA) and Enterprise (EPD). As producers scale up in the Permian, we expect area midstream companies will benefit from healthier E&P counterparties and more stable future drilling, potentially offset by greater merged customer bargaining power. East Daley will host a webinar on Oct. 29, “E&P Merger Mania: Implications for Midstream,” register here. – Robert Ingram Tickers: COP, CXO, EPD, ET, PE, PXD, TRGP, WES
October 16, 2020: Cabot Oil & Gas (COG) revealed it is curtailing some Northeast gas production in response to weak Appalachian prices.
COG said it began shutting in production on September 18 and was curtailing 372 MMcfe/d by October 1, rising to 450 MMcfe/d on average in the first week of October. East Daley speculated that voluntary curtailments were likely behind a ~1.7 Bcf/d drop in receipts on northeastern Pennsylvania systems at the end of September, and COG confirmed its role in some share of the observed regional decline. We model COG as a counterparty on Williams’s (WMB) Bradford Supply Hub system, and pipe flows show evidence of curtailments beginning September 18, averaging ~350 MMcf/d through the end of the month. Receipts on WMB’s Susquehanna Supply Hub, which gathers over 2 Bcf/d of COG’s produced gas, also have declined since the end of September. In its 2Q2020 earnings call, COG guided that it would sell 17% of its 3Q2020 gas production at the Transco Zone 6 Non-NY price point. In the week prior to COG’s shut-ins, the fixed price at this hub slid by 72%, from $1.41/MMBtu to $0.83, likely precipitating COG’s decision to curtail production. COG is the latest gas-focused E&P to announce curtailments amid weak shoulder-month prices in anticipation of higher winter prices just around the corner. –David Dubetz Tickers: Tickers: COG, WMB
October 16, 2020: Rig counts in the Eagle Ford Shale (EFS) have soared in the past month to 21 rigs from the August low of 11, potentially driving volumetric upside for a handful of basin gatherers.
While rig recovery has occurred in all major basins, none has been as robust as the Eagle Ford. ConocoPhillips (COP) maintained four rigs this summer while Marathon Oil (MRO) recently added one rig, taking it to three deployed. We attribute increasing rig activity to singular rigs brought on by companies such as Penn Virginia (PVAC), Silverbow (SBOW), Callon (CPE), CML Exploration, and Escondido Resources, all of which dropped rigs this summer. New EFS drillers that have brought on one rig each include Ineos, Peles, and Headwaters Energy Partners. There are six rigs each on the DCP Midstream (DCP), Enterprise (EPD), and Energy Transfer (ET) systems in the EFS, up from lows of three, one, and two rigs, respectively. Total 1Q2020 Eagle Ford gas production was 7.9 Bcf/d, and ET, EPD, and DCP accounted for 23%, 19%, and 9% of gathering, respectively. Kinder Morgan’s (KMI) EFS system accounts for 10% of basin throughput, but producers haven’t run rigs on this system acreage since June. Rigs higher than we previously modeled could spell volumetric upside for some EFS gatherers.–Robert Ingram Tickers: COP, CPE, DCP, EPD, ET, KMI, MRO, PVAC, SBOW
October 16, 2020: Bloomberg reports that ConocoPhillips (COP) is in talks to acquire Permian producer Concho Resources (CXO), which would boost COP’s presence in the Permian where CXO controls mineral rights to about 800,000 gross acres, including 520,000 acres in the Delaware Basin.
CXO has seven rigs drilling in the Permian but maintained 18 rigs prior to the market downturn in March. COP has one rig in the Permian and moved several rigs out of the basin when oil prices dropped. In 2019, COP averaged about 17 U.S. rigs, of which about 60% were drilling in the Eagle Ford and Williston Basin. According to East Daley’s Midstream Activity Tracker, nearly all of COP’s historical Permian rigs were on Western Gas’s (WES) DBM system. Four of CXO’s active rigs are drilling on EnLink Midstream’s (ENLC) Midland gathering system. CXO also has two rigs on Crestwood Energy Partners’ (CEQP) Permian system and one rig on Targa Resources (TRGP)’s Versado system in the Permian. If a deal were to go through, the combined E&P would produce ~300 Mb/d of oil and 1.2 Bcf/d of gas. The largest gas midstream counterparties affected would be Energy Transfer (ET), TRGP, WES, and Lucid Energy Group, which would account for 27%, 17%, 12%, and 10% of the combined E&P’s gas G&P activity, respectively. The largest oil counterparties affected by this deal would be Plains All American (PAA), Enterprise (EPD), and TRGP, which would gather 22%, 10%, and 6%, respectively, of the combined company’s oil production. The pair may announce a deal in a few weeks, Bloomberg reports. A COP-CXO deal could provide upside for midstream companies with exposure to the combined company’s acreage. -Robert Ingram Tickers: COP, CXO, ENLC, EPD, ET, PAA, TRGP, WES
October 16, 2020: East Daley’s analysis suggests that historically high ethane recovery paired with the restart of formerly shut-in production will lead to higher throughput on DCP Midstream’s (DCP) Southern Hills NGL pipeline and ONEOK’s (OKE) Arbuckle and Sterling NGL systems and lift both companies’ fractionation operations in upcoming 3Q2020 results.
We follow EIA’s reported NGL volumes in PADD II in Oklahoma and Kansas to gauge NGL recovery in the Anadarko Basin. From this, we estimate the amount of ethane recovered or rejected back into the gas stream in the region and forecast earnings impacts for local midstream operators. In June 2020, the PADD II region recorded the highest ethane recovery level in the EIA dataset dating back to 1993, with companies extracting about 86% of ethane produced. The following month, Mont Belvieu ethane prices fell slightly from an average of 22 cents per gallon (cpg) to 21 cpg, while the percentage of ethane recovered also fell slightly to 83%. In August, ethane prices climbed higher and averaged over 24 cpg, which likely drove ethane recovery above the record attained in June. This seesaw of price and higher recovery levels partially pushed ethane prices back down to 20 cpg in September and in October to date. But headed into 3Q2020 results, we expect bullish results from these NLG assets will provide a nice tailwind for both DCP and OKE earnings. -Andy Ptacek Tickers: DCP, OKE
October 16, 2020: Increased oil and gas production from the return of flush shut-in wells in the Williston Basin should drive attractive cash flow for midstream operators in 3Q2020 results.
Bakken gas production has risen ~13% so far in October vs. 3Q2020, according to our interstate residue gas pipe sample, and is ~3% higher than average 1Q2020 volumes. We saw Bakken gas volumes plummet in 2Q2020, declining ~25% Q-o-Q as producers curtailed wells amid falling oil prices. The basin-wide gas sample rebounded towards the end of 2Q2020, up ~21% Q-o-Q on average in 3Q2020, and gas volumes have continued to rise. Increased oil and gas production are likely not because of new wells, as operators only deployed an average of ~11 rigs in 3Q2020. Rather, built-up gas pressure within wells after producers shut them in likely takes credit for flush production. ONEOK (OKE), Kinder Morgan (KMI), and Targa Resources (TRGP) should benefit from the transitory pop this quarter. OKE’s processed gas volumes increased 22% Q-o-Q in 3Q2020 and are up 19% QTD. KMI’s gas volumes increased 31% in 3Q2020 and are up 17% QTD. TRGP, which has both crude and gas systems in the Bakken, saw gas processing increase 26% Q-o-Q in 3Q2020 and volumes are up 12% QTD. East Daley uses our gas sample to predict Bakken oil production. In our latest 3Q2020 Blueprint Financial Models, we forecast Bakken crude volumes will be 49% higher in 3Q2020 vs. our prior quarterly forecast. As a result, we increased our 2H2020 EBITDA forecast for the TRGP crude system from $42.8 to $60.1 million. Besides the crude, additional gas volumes would flow through the Little Missouri IV plant, benefiting both Hess Midstream (HESM) and TRGP. We expect an additional 85 MMcf/d flowed through Targa’s Badlands gas system in 3Q2020 vs. our 2Q2020 forecast, and we have raised our 4Q2020 outlook by 105 MMcf/d for the Badlands gas system. -Tegan Louw Tickers: HESM, KMI, OKE, TRGP
October 9, 2020: TC Energy (TRP) on October 5 made an offer to roll up all outstanding common units of TC Pipelines (TCP) it did not already own. The purchase would represent a 7.5% premium to the 20-day volume-weighted average price.
. If approved, TRP would consolidate all of TCP’s pipes apart from Iroquois Pipeline, and its effective ownership of Iroquois would go from ~13% to ~49%. The transaction offers the pro forma entity potentially lower rate risk on TCP’s pipelines. Most TCP pipelines likely will require tariff rate resets between 2022-24 due to over-earning measured by Return on Equity (ROE). East Daley forecasts ROE for all TCP pipes exceeding FERC guidelines, which poses rate-cut risk and drives TCP’s negative outcome in our proprietary Treadmill Incline Intensity (TII) metric, a measure of cash flow execution and replacement risk. Under FERC’s gas pipeline tariff regime, pipeline assets moving from a master limited partnership to a C-corporation will include both accumulated deferred income tax (ADIT) and income tax as part of the ROE equation. Assuming a pipeline does not have a large negative ADIT balance, the net result is a lower calculated ROE and, therefore, reduced risk of a rate cut. Investors in TCP would win from the premium and increase in asset quality of TRP, offset by the negative tax consequences of a corporate takeover of a partnership entity. This calculation will vary by an investors’ basis. More broadly, the transaction continues the roll-up of subsidiaries that most recently included CNX Midstream (CNXM) by CNX Resources (CNX). Other potential roll-ups include Western Midstream (WES) by Occidental Petroleum (OXY) and Noble Midstream (NBLX) by Chevron (CVX). -Zack Van Everen Tickers: CNX, CNXM, NBLX, OXY, TCP, TRP
October 9, 2020: Pembina Pipeline (PBA) has 460 MMcf/d net ownership in the Younger processing plant in northeastern British Columbia in Canada’s Montney formation.
While gas receipts sent through the facility have declined slightly from ~636 MMcf/d in 1Q2018 to 530 MMcf/d in 2Q2020, the volume of NGLs recovered has plummeted. In 1Q2018, the Younger plant was extracting over two gallons of NGLs per Mcf (GPM) of gas inlet, but NGL recovery fell to ~0.5 GPM in 2019. As a result, mixed-stream NGL extraction fell from 32 Mb/d to ~7.5 Mb/d. The decline in NGL recovery is likely because additional processing plants came online upstream of the facility and have stripped out additional NGLs, sending a drier gas stream for further processing. East Daley forecasts BC gas production will grow through YE2020 and that volumes through the Younger plant will increase to 551 MMcf/d in 4Q2020, averaging ~560 MMcf/d in FY2021. We forecast NGL recovery to remain around 0.75 GPM for the rest of 2020 and FY2021, which results in NGL production of 9.6 Mb/d in FY2021. In East Daley’s Blueprint Financial Models for PBA, we model that a drier gas stream and 0.75 PPM will cause FY2021 EBITDA to fall by ~$49 million vs. profitability when NGL recovery rates were higher at ~2.0 GPM. For PBA to generate the same earnings as in 2018, gas inlets would need to surpass the Younger plant’s current capacity of 750 MMcf/d, indicating the drier gas stream will keep earnings below previous highs. –Tyler Heather Tickers: PBA
October 9, 2020: Sempra Energy (SRE) on October 8 implemented a controlled facility shutdown at its ~2 Bcf/d Cameron LNG terminal ahead of Hurricane Delta, just after restarting production this week.
Cameron exported a cargo on October 5, its first loading since shutting down in late August ahead of Hurricane Laura. Sempra’s CEO had estimated the Cameron facility would resume full operations in mid- to late October. Dominion’s (D) Cove Point terminal also has been offline since September 21 for routine maintenance that should last about three weeks. Despite the ~3 Bcf/d reduction in export capacity and disruptions from four large Gulf storms, U.S. LNG exports have returned to May levels at ~6 Bcf/d. East Daley forecasts further LNG export growth ahead, reaching 10 Bcf/d by YE2020 as we estimate netbacks to Europe turned positive in September based on Dutch TTF prices. Deliveries have increased to Cheniere Energy’s (LNG) Sabine Pass and Corpus Christi terminals since the first week of May, up 25% and 300%, respectively. Sabine Pass is operating near full capacity and Corpus Christi at ~95% of capacity. Freeport LNG also has returned to full capacity. – Alex Gafford Tickers: D, LNG, SRE
October 9, 2020: Royal Dutch Shell (RDS) announced it will cut its upstream operations by as much as 40% as the major redirects its focus into renewable energy. RDS plans to reduce its workforce by up to 10%, or 9,000 jobs by YE2022, and slash capital invested in new E&P projects.
RDS said it will focus its future upstream capex on operational hubs such as the Gulf of Mexico, the North Sea, and Nigeria. Since January, RDS has reduced its Permian rigs from seven to two, and its rigs in the Western Canada Sedimentary Basin (WCSB) fell from two to one. Shell had no rigs in the WCSB in May and June. Over 57% of RDS’s 1Q2020 throughput in the WCSB was gathered on its own system, but its announcement could affect other midstream counter-parties including KeyCorp (KEY), Energy Transfer (ET), and Pembina Pipeline (PBA), which account for 7%, 5%, and 5% of RDS’s throughput in the WCSM, respectively. In the Permian, RDS has been drilling only on Crestwood Energy Partner’s (CEQP) Willow Lake system, on which it has been active since October 2019. Major gas gatherers for RDS in the Permian include Western Midstream (WES), EnLink Midstream (ENLC), Brazos Midstream, and Caprock, which account for 20%, 19%, 14%, and 12% of 1Q2020 throughput, respectively. RDS also produces in the Northeast, with 75% of its gas throughput handled by National Fuel Gas (NFG) and 25% handled by ET. RDS’s move follows a growing strategy of working more toward climate and ESG goals, particularly among European integrated companies. -Robert Ingram Tickers: CEQP, ENLC, ET, KEY, NFG, PBA, RDS, WES
October 9, 2020: Chevron (CVX) completed its acquisition of Noble Energy (NBL) on October 5 following NBL shareholder approval. The all-stock acquisition valued NBL at $4.2 billion at closure, down from $5.0 billion when first announced in July but still the upstream’s biggest deal in 2020. Shares of Noble Midstream (NBLX) jumped 10% on the news amid speculation that new ownership may kick-start drilling on its system in the DJ and Permian basins after CVX formed a new Rockies business unit.
CVX is now the general partner of NBLX and holds ~63% of the limited partner units. The NBL acquisition will increase CVX’s exposure to G&P systems owned by Energy Transfer (ET), DCP Midstream (DCP), and Western Midstream (WES), in addition to NBLX (see our July 22 Snapshot, "Chevron-Noble Merger – Midstream Implications”). The major has much deeper pockets than NBL and will boost counterparty credit quality for NBLX and other midstream operators, but expectations for more drilling may be premature without higher oil prices. According to drilling scenarios outlined in a Form S-4 filing, CVX projects the number of new wells drilled on NBL acreage at or below East Daley’s current forecasts (see our August 19 Snapshot, “Parental Guidance – Noble Energy Drilling Scenarios & NBLX Impacts”). CVX’s “Low” scenario entails no wells being drilled in the DJ for 2021, which would reduce our 2021-2022 EBITDA estimates for NBLX by 19%. In the “Base” scenario, we would reduce our estimates 4-6% in 2021-2022. - Ajay Bakshani, CFA Tickers: CVX, DCP, ET, NBLX, WES
October 2, 2020: Drilling activity in the Powder River basin is down to 1 rig vs. ~20 active rigs in January-February 2020. The final PRB rig is operated by EOG Resources (EOG) on Meritage’s privately held G&P system.
At the start of 2020, the most active drillers in the basin included Chesapeake (CHK) with 5 rigs, EOG with 3 rigs, and Devon Energy (DVN) with 3 rigs. By May 10, 2020 both CHK and DVN had ceased drilling in the PRB, leaving EOG as the last active E&P. Average total rig count in 2Q2020 is ~85% lower vs. 1Q2020. Given the lack of drilling, E&Ps likely are relying on legacy production or completing DUCs for new volumes. Average gas sample volumes in the PRB declined ~26% from 1Q2020 to 2Q2020. Interstate gas sample volumes can be used as a proxy for changes in both gas and crude production. Gas volumes in the basin reached a low of 330 MMcf/d in early May 2020 but recovered ~35% in early June. East Daley previously highlighted that Tallgrass Energy’s (TGE) Douglas system, Meritage’s system, and Crestwood Equity Partners’ (CEQP) Bucking Horse system have been most impacted by shut-ins and declining activity (see the May 29 Data Insight, “Last Rig Standing in the PRB”). TGE’s system continues to be hit the hardest, with average gas volumes 55% lower Q-oQ in 2Q2020. Meanwhile, CEQP’s Bucking Horse system and Meritage have seen Q-o-Q declines of ~38% and ~29%, respectively in 2Q2020. Tickers: CEQP, CHK, DVN, EOG, TGE
October 2, 2020: In May 2019, Plains All American (PAA) and Delek Logistics Partners (DKL) announced the formation of the Red River Pipeline JV and disclosed plans to expand the oil pipe extending from Cushing, OK to the Gulf Coast.
For $128 million, DKL acquired a 33% interest from PAA in the Red River system and pledged to increase its pipe commitments from 35 Mb/d to 100 Mb/d upon completion of the pipe expansion. In return, PAA offered DKL an incentive rate on its existing and new commitments of $1.00/bbl, or ~50% below the normal rate. The incentive originally was set to expire July 1, 2020, around when the Red River expansion was due for completion. Yet in a May 2020 FERC filing, PAA added new language extending the incentive for another year, to August 1, 2021, albeit at a slightly higher rate of $1.25/bbl. The lower-for-longer tariff incentive primarily affects Red River’s average realized tariff and forecasted EBITDA for FY2021. East Daley’s updated Red River Pipeline EBITDA forecast is now $16 million lower than our 1Q2020 Post-Call forecast (see chart). The expected $16 million impact to the JV’s 2021 earnings is a 25% reduction to prior estimates and is solely attributable to a lower average tariff, as East Daley’s updated volume projections did not change from the 1Q2020 Post-Call model. While the decline in earnings is certainly not devastating to each JV partner’s consolidated EBITDA, it does raise concerns about the pipe’s earnings beyond 2021 should PAA decide to keep rolling the incentive on an annual basis. Tickers: PAA, DKL
October 2, 2020: It is no secret that the Williston, with its gathering infrastructure constraints and relative geographic disadvantages, is among the basins hardest hit by the downturn in commodity prices.
While many E&Ps have curtailed production and cut completion crews, Hess (HES) has taken a different tact and secured 6 MMb of oil storage in 3 VLCCs chartered off the Gulf Coast for their Bakken production. The North Dakota Oil and Gas Division’s June monthly update stated that 1 frac crew is still pumping in the Williston along with 10 active drilling rigs. Due to the storage it has secured, East Daley believes that HES is the only E&P that has been completing wells in the basin through the downturn. While the gas sample for the entire basin fell 40% from early March 2020 to a trough in the second week of May, the HESM–Tioga system was padded by wells flowing from HES and only fell 17% in the same period. HES announced plans to operate only 1 rig in the Williston for the rest of 2020, which will hinder HESM’s ability to reach full system utilization over the long term. In the short term however, the system has seen limited reduction in its gas sample compared to other systems in the basin, thanks to HES’s continued completions and secured storage. Ticker: HES
October 2, 2020: East Daley’s analysis of Permian pipe data points to a recovery in June for shut-in volumes on some G&P systems, including Lucid’s private South Carlsbad system in the Delaware subbasin.
The South Carlsbad pipe sample fell 25% (140 MMcf/d) in just four days from April 27 to May 1, 2020, suggesting shut-ins rather than natural declines. Concho Resources (CXO) and EOG Resources (EOG) together produce 48% of the gas gathered on Lucid’s system and are likely responsible for this drop. CXO and EOG curtailed estimated Permian oil production of 28 Mb/d and 50 Mb/d, respectively, during the downturn, yet E&Ps should begin to restore wells as WTI rebounds from April lows. Between May 31 and June 7, the South Carlsbad sample recovered 32%, or 120 MMcf/d, regaining much of the volume lost since March. This period coincides with June 2 comments by EOG executives that it would begin restoring curtailed production in 2H2020. Since April 19, EOG’s rigs on South Carlsbad have fallen just 10% vs. a 50% drop in total system rigs. While rigs are a lagging indicator of future production, EOG’s sustained activity suggests their commitment to develop acreage on Lucid’s system. South Carlsbad’s pipeline sample indicates that the pace of recovery is likely to mirror the slope of volume declines when wells were first shut, which has implications on recovery scenarios across public and private systems. East Daley’s Company Dashboards provide insight into how systems uniquely respond to operator curtailments and allow clients to model recovery profiles based on real-time data. Tickers: CXO, EOG