Resources for 3rd Quarter 2020

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October 2020

Midstream Navigator

Run for the Border: Why Canada’s Midstream is a Superior Investment

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% (see Figure 1).

Pioneer-Parsley: Midstream Implications of Permian Merger Mania

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.

Concho-Conoco Merger: Midstream Implications of Permian Consolidation

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.

Bid It to Win It Part IV: Targa Resources – Stick to the Strategy

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.

September 2020

Midstream Navigator

DAPL Update: DAPL Gets Its Day in Court

September 24, 2020: The Dakota Access Pipeline (DAPL) has overcome one of the two major hurdles in its current legal saga.

The first, and more significant case, is its appeal (“Merits Appeal”) to the U.S. Court of Appeals for the D.C. Circuit to determine whether DAPL needs an Environmental Impact Statement (EIS), or if its current Environmental Assessment (EA) is adequate. East Daley expects the court to announce this decision in 1Q2021. The second legal issue involves whether the court should grant a stay on the D.C. District Court’s initial ruling that vacates an easement and would force DAPL to shut down operations until the court adjudicates the Merits Appeal. On August 5, the appellate court granted a stay on the injunction because the District Court did not follow the proper procedure.

2,000’ Setbacks: Setting Back Colorado Oil & Gas Development

September 17, 2020: The Colorado Oil & Gas Commission (COGCC) saw its membership and mission change following passage of Senate Bill 19181 (SB-181) in April 2019.

The risks to the industry posed by these changes are coming into sharper focus after four of the five new COGCC commissioners on September 9, 2020 voiced support for extending well setbacks to 2,000’. Setbacks have been a point of contention in Colorado for many years. Current standards require drilling at least 1,000’ from high occupancy buildings such as schools, 500’ from occupied buildings such as homes, and 350’ from outdoor areas such as playgrounds. While the ultimate vote by COGCC is pending, East Daley has investigated which E&P and midstream companies will be most impacted by 2,000’ setbacks.

This Land is Your Land – Potential Impacts of a Drilling Ban on Federal Lands

September 9, 2020: East Daley examined the impacts of a possible drilling ban on federal lands nearly one year ago, when WTI was in the mid$50s, drill bits were turning, and no one had heard of COVID-19 (see our Oct 17, 2019 Snapshot, “The Fight for Federal Lands”).

Despite so much change, one thing remains constant: politics. From rangeland conflicts like the Johnson County War and the Cliven Bundy skirmish to legacy mining claims, the use of federal lands has been disputed for decades.

Bid It to Win It Part III: Summit Midstream – Some Asset Sales Required?

September 16, 2020: East Daley in the following weeks will examine the outlook for M&A activity in the midstream sector. This week, we analyze the financial outlook for Summit Midstream ahead of results for its Dutch auction debt buyback, and whether the company needs to pursue an asset divestiture.

Summit Midstream Partners (SMLP) is grappling with a difficult debt situation made worse by the energy market downturn. Midstream companies across the industry are facing newfound financial stresses, including high leverage, lower commodity prices, and mounting counterparty bankruptcies amid market volatility this spring (see East Daley’s August 20 Snapshot, “Bid it to Win it Part I: Non-Core Asset Sales Outlook”). Even in better times, SMLP faced challenges. Volumes on its legacy and core assets were already in decline or underperforming management’s guidance from the start of 2020, and production curtailments, shut-ins, and reduced drilling activity have further strained the company’s balance sheet.

This Land is Your Land – Potential Impacts of a Drilling Ban on Federal Lands

September 9, 2020: East Daley examined the impacts of a possible drilling ban on federal lands nearly one year ago, when WTI was in the mid$50s, drill bits were turning, and no one had heard of COVID-19 (see our Oct 17, 2019 Snapshot, “The Fight for Federal Lands”).

Despite so much change, one thing remains constant: politics. From rangeland conflicts like the Johnson County War and the Cliven Bundy skirmish to legacy mining claims, the use of federal lands has been disputed for decades.

August 2020

Midstream Navigator

Marco … Laura Part I – Hurricane Activity Impacts in the Gulf of Mexico

August 26, 2020: The U.S. Gulf Coast confronts an extraordinary dual hurricane threat this week from storms Marco and Laura.

At the time of publication, Marco had been downgraded to a tropical depression after making landfall Monday near the mouth of the Mississippi River. Marco is now traveling west along the Louisiana border. Laura had strengthened into a hurricane off the western coast of Cuba and should intensify and make landfall tonight near the Texas-Louisiana border. The storm could become a Category 3 or higher, which makes it potentially more damaging than recent hurricanes that had limited impacts on U.S. energy production and midstream operations, and more like stronger storms of the 2000s such as Hurricanes Rita and Ike that caused widespread infrastructure damage and months-long impacts to oil and gas production. With widespread curtailments due to two active storms, GOM oil and gas production is at the lowest level since Hurricane Ike in 2008.

Parental Guidance – Noble Energy Drilling Scenarios & NBLX Impacts

August 19, 2020: Many producers are ready to lay down their budget knives following a volatile spring for the energy industry.

On July 20, 2020 Chevron (CVX) announced a definitive agreement to acquire Noble Energy (NBL) in an all-stock transaction valued at $5 billion (see East Daley’s July 22 Snapshot, “Chevron-Noble Merger– Midstream Implications”). Last week, Chevron (CVX) filed a Form S-4 registering 59.3 million shares for the NBL acquisition, which is due to be completed in 4Q2020. The S-4 filing provides significant background on discussions leading to the merger agreement between the two companies, including interest by the NBL Board dating from July 2019 to consolidate with another E&P. As part of its M&A review process, NBL’s management team hired J.P. Morgan as a financial adviser and conducted several unaudited financial forecasts for the firm, some details of which are disclosed in the S-4.

Marco … Laura Part I – Hurricane Activity Impacts in the Gulf of Mexico

August 26, 2020: The U.S. Gulf Coast confronts an extraordinary dual hurricane threat this week from storms Marco and Laura.

At the time of publication, Marco had been downgraded to a tropical depression after making landfall Monday near the mouth of the Mississippi River. Marco is now traveling west along the Louisiana border. Laura had strengthened into a hurricane off the western coast of Cuba and should intensify and make landfall tonight near the Texas-Louisiana border. The storm could become a Category 3 or higher, which makes it potentially more damaging than recent hurricanes that had limited impacts on U.S. energy production and midstream operations, and more like stronger storms of the 2000s such as Hurricanes Rita and Ike that caused widespread infrastructure damage and months-long impacts to oil and gas production. With widespread curtailments due to two active storms, GOM oil and gas production is at the lowest level since Hurricane Ike in 2008.

Parental Guidance – Noble Energy Drilling Scenarios & NBLX Impacts

August 19, 2020: Many producers are ready to lay down their budget knives following a volatile spring for the energy industry.

On July 20, 2020 Chevron (CVX) announced a definitive agreement to acquire Noble Energy (NBL) in an all-stock transaction valued at $5 billion (see East Daley’s July 22 Snapshot, “Chevron-Noble Merger– Midstream Implications”). Last week, Chevron (CVX) filed a Form S-4 registering 59.3 million shares for the NBL acquisition, which is due to be completed in 4Q2020. The S-4 filing provides significant background on discussions leading to the merger agreement between the two companies, including interest by the NBL Board dating from July 2019 to consolidate with another E&P. As part of its M&A review process, NBL’s management team hired J.P. Morgan as a financial adviser and conducted several unaudited financial forecasts for the firm, some details of which are disclosed in the S-4.

Knives Out – 2Q2020 E&P Guidance Review

August 11, 2020: Many producers are ready to lay down their budget knives following a volatile spring for the energy industry.

While operators slashed annual capex and production guidance in 1Q2020 updates, East Daley’s review of 2Q2020 earnings from 38 publicly traded E&Ps found only limited subsequent changes to upstream spending plans. These companies together reported 2020 capex plans 3.9% lower vs. 1Q2020. Producers with the largest downward Q-o-Q revisions to spending plans include Chevron (CVX), Devon (DVN) and Callon Petroleum (CPE), which revised their 2020 capex guidance lower by 13%, 25%, and 29%, respectively. Most producers in 2Q earnings affirmed their intent to either meet or spend less than the low side of capex guidance provided in 1Q2020, and 12 E&Ps reported no changes to prior capex guidance.

Bandy About the Barrel Part II – Gas Supply in a $30-60/bbl Oil Price Band

August 6, 2020: While oil prices have stabilized recently in the $40/bbl range, natural gas markets are seeing divergent trends.

Under the terms of the agreement, NBL shareholders will receive 0.1191 shares of CVX for each NBL share. The acquisition is expected to close in 4Q2020. The CVX-NBL merger has significant implications for the midstream sector given both companies have diverse U.S. onshore portfolios in the Permian and DJ basins, as well as NBL’s existing commitments to its Noble Midstream (NBLX) spinoff. This analysis looks specifically at the midstream impacts in the combined portfolio’s U.S. onshore acreage.

Marathon Closing Refineries – The Impact on MPLX

August 3, 2020: A Reuters article released Saturday reports that Marathon Petroleum (MPC) is planning to close its currently idled Martinez, CA and Gallup, NM refineries in response to the recent reduction in fuel demand.

Under the terms of the agreement, NBL shareholders will receive 0.1191 shares of CVX for each NBL share. The acquisition is expected to close in 4Q2020. The CVX-NBL merger has significant implications for the midstream sector given both companies have diverse U.S. onshore portfolios in the Permian and DJ basins, as well as NBL’s existing commitments to its Noble Midstream (NBLX) spinoff. This analysis looks specifically at the midstream impacts in the combined portfolio’s U.S. onshore acreage.

Data Insights

October 2020 Data Insights

No Oasis from Hard Times:

October 2, 2020: Oasis Petroleum (OAS) this week filed for Chapter 11 bankruptcy protection, the latest E&P to seek protection from creditors due to lower oil and gas prices.

OAS reported long-term debt of $2.76 billion and $77 million in cash and cash equivalents as of June 30, 2020. OAS, which missed a debt payment earlier this month, said it expects to cut debt by $1.8 billion through restructuring and secured $450 million in debtor-in-possession financing. OAS’ Chapter 11 filing may create counterparty risk for midstream operators that gather and process its oil and gas in the Permian and Williston basins. Oasis Midstream (OMP) gathers most Bakken gas production for its parent company on the Wild Basin system, and OAS also has activity on Bakken G&P systems operated by ONEOK, Hess Midstream (HESM), and Targa Resources (TRGP). TRGP also gathers and processes most Delaware Basin gas production for OAS. –Andrew Ware Tickers: HESM, OAS, OMP, ONEOK, TRGP

 

Barnett Bounce:

October 2, 2020: Rig activity in the Barnett continues to rebound off lows hit this summer on new investments from private capital.

The Barnett averaged six rigs in 1Q2020 before activity plummeted amid market volatility and weak gas prices, with no rigs drilling in June. Yet some activity has restarted ahead of higher gas prices expected this winter and in 2021. Three rigs on average have drilled in September and today seven rigs are running in the Barnett, with private operators including Bend Petroleum Corp, Chisholm Energy Holdings LLC, Legacy Exploration LLC, and Gannet Operating LLC leading the rebound. Permitting is also up significantly in 3Q2020. While most current rigs are vertical, French company Total filed for 16 horizontal permits in 3Q2020. Three rigs are drilling on Targa Resources’ (TRGP) North Texas G&P system, and one each are on systems owned by Kinder Morgan (KMI) and West Texas Gas (WTG). With Henry Hub priced over $3.00/MMBtu this winter and ~$2.75 for 2021, East Daley believes the Barnett drilling rebound is sustainable. We forecast an average of six rigs in the Barnett in 4Q2020 and seven rigs in 2021 at prevailing oil and gas prices. In 4Q2020 we project G&P volumes of 2,570 MMcf/d, 9% lower Y-o-Y vs. 2,813 MMcf/d in 4Q2019. – Maria Paz Urdaneta Tickers: KMI, TRGP, WTG Tickers: RVRA, ENLC

: Making Moves:

October 2, 2020: Summit Midstream (SMLP) announced a restructuring agreement between its Summit HoldCo subsidiary and lenders for its $155.2 million term loan.

The loan was secured by 34.6 million common units plus the general partnership interest in SMLP, and SMLP in exchange will offer $26.5 million plus the 34.6 million common units, retiring the term loan at a substantial 69% discount to face value. Recent debt repurchases, a Dutch auction, and the term-loan restructuring have improved its leverage position, but SMLP still faces an uphill climb given challenging macro conditions. Falling rig activity has hurt SMLP’s long-term growth story. Whiting Petroleum (WLL) and Bruin Energy Partners together make up ~62% of SMLP’s Polar and Divide gathering volumes in the Williston, and both emerged from Chapter 11 in early September. We expect reduced rates from these bankruptcies plus lower volume growth and rig attrition will hurt SMLP’s leverage ratio (see our Sept. 16 Snapshot, “Bid It to Win It Part IV: Summit Midstream – Some Asset Sales Required?”). SMLP has several financial levers it can pull, and we project it will need $130 million from a mix of third-party debt at the subsidiary level (Double E Pipeline), $60 million from the built-in accordion feature in its subsidiary-level preferred shares, additional debt repurchases, or an asset sale to avoid breaching its 5.5x financial leverage covenant on its revolving credit line by 1Q2021 . - J.R. Blumensheid Tickers: SMLP, WLL

Rocked Like A Hurricane

October 2, 2020: Two months remain in the Atlantic hurricane season and with 23 named storms so far, this year is already the secondmost active in recorded history.

Storms so far have caused far less damage to Gulf of Mexico (GOM) infrastructure than in 2005, the record year for Atlantic storms, when hurricanes Rita and Katrina ravaged the Gulf Coast. Cumulative effects from facility shutdowns and evacuations are adding up. In 3Q2020, East Daley calculates that storms resulted in curtailments of ~45 MMbbl of oil and ~35 Bcf of gas production. We estimate hurricanes Marco and Laura curtailed half of the curtailed production, with 20% from facility shutdowns ahead of Hurricane Sally and Tropical Storm Beta. Other storms including Cristobal, Fay, and Hanna spurred additional curtailments early in 3Q2020. Among East Daley’s coverage, Shell Midstream (SHLX) and Genesis Energy (GEL) have the greatest exposure (over 50% of 1Q2020 EBITDA) to GOM hurricane disruptions (see our August 26 Snapshot, “Marco ... Laura Part II – Hurricane Activity Impacts in the Gulf of Mexico). The Atlantic hurricane season ends November 30 and operators are not out of the woods. Tropical Depression 25 formed Friday over northwest Caribbean waters, and the National Hurricane Center projects it will cross the Yucatan Peninsula and strengthen into a tropical depression in the western GOM next week. Buckle up for more volatility ahead. -Robert Ingram Tickers: SHLX, GEL

Trends Don’t Last Forever:

October 2, 2020: Marcellus gas production in Northeast Pennsylvania declined by 1.7 Bcf/d (13%) this week since reaching record output in early September.

The reduction in supply does not appear related to pipe constraints and most likely is due to voluntary curtailments owing to weak natural gas prices this month in the Northeast. End-ofmonth balancing because of excess nominations in September may also be behind the decline given weak regional spot prices. The Leidy-Transco price averaged just $1.08/MMBtu in September but dipped as low as $0.78/MMBtu on Sept. 22. Williams’ (WMB) Bradford Supply Hub accounts for one-third (660 MMcf/d) of the production decline this week. DTE’s and Energy Transfer’s (ET) gathering systems also reported material volume reductions. Chesapeake (CHK), the largest producer on the Bradford system, is a likely candidate for some of the sudden decline. Receipt meters on the Tennessee, Stagecoach, and Transco pipelines account for most of falling output and CHK has significant firm reservations on both Stagecoach and Tennessee. Despite the late-month decline, we still expect gathering systems in Northeast PA to report a record 3Q2020 as drilling and completion activity boosted volume throughput in the quarter. Looking ahead, the curtailments might reduce 4Q2020 earnings if winter weather does not materialize in October to lift basis in the Northeast. East Daley expects the Bradford system to contribute a $4 million gain for WMB Q-o-Q in 3Q2020, with the Susquehanna system contributing a $7 million gain Q-o-Q, which includes the recent reduction. - Ryan Smith Tickers: CHK, DTE, ET, WMB

September 2020 Data Insights

LNG Export Recovery Underway:

September 25, 2020: Gulf Coast LNG export operations continue to recover after Hurricane Laura, but an extended outage at Sempra Energy’s (SRE) Cameron LNG facility will hurt gas demand.

Cameron and Cheniere Energy’s (LNG) Sabine Pass facility both ceased operations as Laura made landfall, wiping out 3.1 Bcf/d of feedgas for exports. Feedgas deliveries to Sabine Pass surged following its opening on September 9, peaking near full utilization on September 18 at 3.9 Bcf/d. Cameron LNG however took a direct hit from Laura in Lake Charles, LA and is contending with lost power supply. SRE CEO Jeff Martin stated on September 17 that he expects Cameron should return to full operations “in the next six weeks,” meaning the facility’s ~2 Bcf/d of feedgas capacity could remain offline until mid-October. Despite the loss of Cameron, LNG exports made a robust recovery in the weeks following Laura. Total U.S. receipts rose to 8 Bcf/d before some short-term shutdowns this week as precautions to Tropical Storm Beta, and we expect a quick recovery ahead. East Daley estimates that LNG export netbacks based on Dutch TTF prices turned positive this month, and recent gas sample data supports East Daley’s view that LNG export demand remains strong because of favorable netbacks. We expect LNG exports to average 10.2 Bcf/d in 2021. – David Dubetz Tickers: SRE, LNG

Citizen Shopping Spree:

September 25, 2020: Privately owned Citizen Energy III’s recent acquisition of Blue Mountain Midstream from Riviera Resources (RVRA) may have implications for EnLink’s (ENLC) Central Oklahoma G&P system.

The Blue Mountain deal follows on Citizen’s merger in October 2019 with Roan Resources, another private E&P operator in the Anadarko, through a 50/50 acreage dedication split between ENLC and Blue Mountain in the southern STACK and northern SCOOP plays. According to East Daley’s G&P Allocation Model, Citizen accounted for over half of the drilling activity on the ENLC system from March 2020 to present. Citizen averaged 1.3 rigs on ENLC’s footprint from January 2020 to late August (out of two rigs total) and had one rig on the Blue Mountain system in March and April. Citizen in August said it purchased Blue Mountain Midstream from Riviera, giving the company the ability to produce, gather, and process gas. Within a month, Citizen’s lone rig on the ENLC system moved further south onto its newly acquired Blue Mountain footprint. East Daley models Citizen’s 2Q2020 gas volumes on the ENLC system at 133 MMcf/d, ~16% of total throughput, and 35 MMcf/d on Blue Mountain, or ~36% of system throughput. Given ENLC’s reliance on Citizen for drilling activity, the Blue Mountain deal may pose risk to new production on the Central Oklahoma G&P system. - Melissa J. Saurborn Tickers: RVRA, ENLC

: Laissez Les Contracts Roll :

September 25, 2020: Upland Exploration announced promising well results that included the highest reported 24-hour peak oil production per completed lateral length in the DJ Basin (among post-2010 wells with laterals over 4,000’).

SHLX confirmed that shippers moved volumes below MVC contracts and will book credits for MVC shortfalls. SHLX has these cash-flow protections until YE2020 when two contracts roll off. Based on open season tariffs filed in 2019, East Daley estimates these two contracts protect ~75 Mbl/d of throughput at a rate of $0.85/bbl. Historical volumes and tariffs have correlated to the spread between Houston and Louisiana oil markets. In our last model, the forward strip for this spread was strong, and we modeled these contracts renewing for 55 Mb/d at a rate of $0.50/bbl, resulting in potential downside risk of ~$14 million in annual revenue. The LLS – Houston spread has decreased since our last model, averaging $0.26/bbl through 2021. Based on this forward spread and recent throughput, there could be additional downside to our current model. Fortunately for SHLX, this is its last contract roll-off until 2024, when East Daley estimates ~162 Mb/d rolls off at a $0.73/bbl rate, followed by 100 Mb/d in 2030 at a $1.09 rate. -Zack Van Everen Ticker: SHLX

No Growth Mindset

September 25, 2020: The Federal Reserve Bank of Dallas released a survey this week revealing that two-thirds of oil and gas executives believe U.S. crude production has already peaked

Among 147 executives surveyed, 66% said they expect oil production will never reach the recent highs set late in 2019 and 1Q2020. The pessimists cited OPEC’s role in setting prices, domestic bankruptcies, and federal political risks (current and future) as reasons they believe the best days are behind the oil patch. East Daley holds the contrarian view that U.S. oil production one day will hit records again, though investors will require some patience. While our U.S. Macro Forecast expects stagnant oil production in 2021, we model growth returning by 2022 at the current WTI strip. But we expect growth post-2022 to be slow and shallow, and far short of robust supply gains seen amid the latest expansionary cycle from 2018 to 1Q2020. Permian production should rebound first, returning to 1Q2020 levels by 1H2023. But declines in highercost oil basins will drag on the total. We expect crude production will return to 1Q2020 levels in eight years, by 2H2028, by which time the Permian would account for one-half the U.S. share. In 2028, we expect rigs to be ~64% of the 475-rig peak. We base our growth expectation on fundamentals, and political uncertainty could moderate this growth. -Robert Ingram

Stepping Down from Stepping Back:

September 25, 2020: EThe debate over 2,000’ well setbacks in Colorado has triggered widespread concerns among anxious executives and investors, particularly in the DJ Basin where impacts would be most profound

East Daley has identified Occidental Petroleum (OXY), PDC Energy (PDCE), and Extraction Oil & Gas (XOG) as the DJ producers with leases most at risk from longer setbacks, increasing risks for companies like Western Midstream (WES) and DCP Midstream (DCP) that operate G&P systems in the basin (see our September 17 Snapshot, “2,000-foot Setbacks: Setting Back Colorado Oil & Gas Development”). We have updated our September Production Scenario Tools for Colorado basins to estimate how 2,000’ setbacks would affect oil and gas production, classifying operators’ acreage as low, medium or high risk. We found in the DJ, longer setbacks would reverse our long-term outlook for oil and gas supply growth. As companies work through their existing drilling permits, we project DJ rig counts would fall by 75% by the start of 2022 as 2,000’ setbacks put new permitting on ice, driving oil production 26% lower to ~352 Mb/d in 2022 vs. our current estimate of ~477 Mb/d. Gas production in the DJ would decline by ~16% to 2.37 Bcf/d vs. our latest estimate of 2.81 Bcf/d in 2022. East Daley will explore the risks by basin and operator in Colorado from 2,000’ well setbacks in our next webinar on Wednesday, September 30, tune in for more details. -Tyler Heather Tickers: DCP, OXY, PDCE, WES, XOG

Busting CHOPS:

September 18, 2020: Genesis Energy (GEL) said its offshore Cameron Highway Oil Pipeline System (CHOPS) will likely not be fully operational by the end of 3Q2020 after Hurricane Laura hit Louisiana in late August.

Due to the disruption, GEL is diverting volumes to its 64%owned Poseidon pipeline. In a stroke of good fortune, GEL said it also has received $41 million in cash from a letter of credit filed with a previous customer default, sending its stock up about 4% on the week. East Daley’s GEL Financial Blueprints previously modeled throughput on CHOPS and Poseidon to be 228 Mb/d and 270 Mb/d, respectively but we now expect at least 35 days of disruption on CHOPS in 3Q2020. Volumes on GEL’s 100%-owned CHOPS could shift downward to ~141 Mb/d and, in a best-case scenario, Poseidon volumes could shift up to 314 Mb/d. We model tariff rates on Poseidon at $1.30/bbl vs. a rate on CHOPS of $1.70/bbl, so with lower tariffs and less ownership, diverted volumes could reduce GEL’s EBITDA up to $10 million. Yet GEL also likely has MVCs on CHOPS protecting some cash flow. East Daley estimates these developments, including the cash settlement and $3-5 million offshore repair costs, on balance will increase GEL’s Adj. EBITDA by $26-$38 million in 3Q2020 vs. prior expectations. We now see 3Q2020 EBITDA ranging between $172 million and $184 million vs. Street consensus of $157 million for the quarter. Shell Midstream (SHLX) also may see upside from its minority ownership in Poseidon. – J.R. Blumensheid.Tickers: GEL, SHLX

Bottled Potential:

September 18, 2020: Northeast gas markets were left behind by the summer rally in Henry Hub and producers once again are curtailing production.

EQT revealed at a recent Barclays conference that it was shutting in ~425 MMcf/d of Marcellus and Utica production as of September 1 while hedging its future price exposure. EQT previously curtailed up to 1.4 Bcf/d of its Northeast production starting in May. Henry Hub futures jumped from ~$1.50/MMBtu in late June to as high as $2.66 in August before trading down to $2.06 Friday. Yet Appalachian gas prices never joined the rally. Dominion South traded at a ~$1.25 discount to Henry Hub in August, and cash prices fell under $1 this week. Infrastructure constraints, high storage levels, and seasonal weakness explain the disconnect. An explosion in May on the Texas Eastern pipeline impacted up to 1 Bcf/d of southbound capacity from Appalachia, limiting egress. Autumn is also a typically weak period for demand. Currently there are 28 active rigs in the Marcellus-Utica, down 53% vs. a year ago, with rigs mainly on assets operated by MPLX, Williams (WMB), Blue Racer Midstream, and Equitrans (EQTR). Despite recent weakness, Appalachian prices for the winter are much higher at ~$2.70/MMBtu in 1Q2021, which should translate into more drilling and production by producers like EQT. -Maria Paz Urdaneta Ticker: EQT, EQTRN, MPLX, WMB Busting

Little Lady, Big Results:

September 18, 2020: Upland Exploration announced promising well results that included the highest reported 24-hour peak oil production per completed lateral length in the DJ Basin (among post-2010 wells with laterals over 4,000’).

Little Lady 22-1NH was drilled with a 4,883’ lateral targeting the Niobrara B formation and flowed a peak 1,396 Boe/d over 24 hours, equal to 285 Boe/d per thousand feet of completed interval. The well was completed with 1,800 lbs. of proppant and 2,200 gallons of water per lateral length vs. core DJ wells that typically have 500-1,500 lbs. of proppant and 750-1,750 gallons of water per lateral length. Nearby operators with permits to this pad include Occidental Petroleum (OXY), Highpoint Resources (HPR), and a handful of private E&Ps. Summit Midstream (SMLP), which gathers for the pad, is expected to see relatively stable production on its DJ system over the next several years. The potential for 2,000’ well setbacks in Colorado is a major uncertainty for the industry that East Daley is closely monitoring (see our September 17 Snapshot, “2,000’ Setbacks: Setting Back Colorado Oil & Gas Development”). But the Little Lady well shows the geology remains compelling in the DJ Basin if producers and midstream companies can navigate the above-ground risks. - Robert Ingram Tickers: HPR, OXY, SMLP

Big Getting Bigger

September 18, 2020: EQT, the largest U.S. gas producer, has reportedly placed a $750 million bid on Chevron’s (CVX) Northeast assets which include ~800,000 acres in the Marcellus-Utica and a 31% interest in the Laurel Mountain gathering system in Pennsylvania.

Williams (WMB) owns the remaining 69% of Laurel Mountain and operates the dry gas assets. East Daley models the majority of CVX’s Northeast production on the two G&P systems. We estimate Laurel Mountain gathered ~335 MMcf/d of CVX production in 1Q2020, or ~75% of total system throughput, and generated $10 million in EBITDA ($7 million net to WMB). We estimate WMB’s Ohio Valley Midstream system in West Virginia gathered and processed 109 MMcf/d of CVX production, or ~16% of total throughput. East Daley believes upside exists for WMB with an EQT purchase. CVX averaged just over one rig on Laurel Mountain and less than one rig on Ohio Valley Midstream in 2019 and has not operated a rig in the area since January 2020. In the month prior, CVX said it would take a massive $10+ billion write-down in FY2019, citing lower long-term gas prices, and attributed about half of the impairment to its Appalachia assets. EQT has been much more active in the Northeast, averaging four rigs in 2020. The CVX acreage is also a direct bolt-on for EQT, with the Laurel Mountain acreage connecting to acreage acquired from RICE on the east end while the wet acreage on Ohio Valley Midstream is nestled between EQT’s dry Marcellus acreage in Pennsylvania and its dry Utica production in Ohio. Upon closing, EQT would likely monetize the 31% ownership interest in Laurel Mountain by looking to either Equitrans Midstream (ETRN) or WMB, the majority owner. -Andy Ptacek Tickers: CVX, EQT, ETRN, WMB

Rejection Hurts:

September 18, 2020: Ethane priced at Mont Belvieu had been trading at its highest levels ($0.265/gal) since March 2019 before Hurricane Laura crashed the market.

Laura, a Category 4 storm, barreled through the U.S. petrochemical capital in southwestern Louisiana and shut down nearly 30% of U.S. ethylene production capacity. About 20% of capacity remains offline as crackers struggle to restart amidst power outages. Mont Belvieu ethane prices fell 30% from August 24 to September 3, down to $0.185/gal, and remain lower at $0.211/gal as of September 17. At lower price levels, it makes less sense to separate ethane from the gas stream. According to data from PointLogic Energy, ethane rejection has increased by 386 Mb/d (+54%) since September 1, with 83% of the reduction coming from Texas basins like the Permian which almost entirely feed Gulf Coast crackers. As a result, NGL pipeline operators in the region such as Energy Transfer (ET), Enterprise Products (EPD), Targa Resources (TRGP), DCP Midstream (DCP), and ONEOK (OKE) should experience some volume declines on their NGL pipes for 3Q2020. Weaker ethane and NGL prices should also hit more commodity-exposed names like TRGP and DCP in their G&P segments. —Ajay Bakshani Tickers: DCP, EPD, ET, OKE, TRGP

No Drilling Off Sunshine State:

September 11, 2020: In a largely symbolic gesture, President Donald Trump on September 8 extended and expanded the ban on drilling offshore Florida.

The existing Gulf of Mexico (GOM) drilling moratorium, passed in 2006, would have expired in 2022 and covered most of the Eastern and a small section of the Central GOM. The order extends this deadline to 2032 and adds restrictions to drilling off the Florida, Georgia, and South Carolina Atlantic coastlines. The move makes sense ahead of the election, particularly in the swing state of Florida. Offshore drilling is unpopular due to the potential threat to the tourism industry, with 64% of Florida voters expressing opposition in a March 2019 Quinnipiac University poll. Politics have impeded development since the 1980s discovery of the Destin Dome gas field 25 miles south of Pensacola, FL. The Eastern GOM contains recoverable resources of 3.6 billion bbl of oil and 11.5 Tcf of gas, according to BOEM estimates, yet contains only 98 of the 100,000+ wells drilled in the entire GOM. Operators include Murphy (MUR), Occidental Petroleum (OXY), and Shell (RDS). Aside from the Gulfstream gas pipeline, jointly owned and operated by Williams (WMB) and Enbridge (ENB), there are no offshore pipes near the Eastern blocks. Effectively this represents a discounted prospective growth area that will remain untapped, probably forever. - Robert Ingram Tickers: ENB, MUR, OXY, RDS, WMB

Grand Prix’s Final Lap:

September 11, 2020: Targa Resource’s (TRGP) recently filed uncommitted tariff rate in excess of $5/bbl for NGLs transport from Oklahoma to Mt. Belvieu, TX is a precursor to EBITDA growth from an unlikely source.

TRGP hasn’t grown cash flow in Oklahoma since early 2019. Its SouthOK and WestOK G&P systems realized steep Q-o-Q volume declines of 22% and 14%, respectively in 2Q2020 due to low crude prices followed by well shut-ins. This was on top of a sharp decline in Anadarko drilling that preceded the downturn, from 150+ active rigs in 1Q2019 to 13 today. Yet TRGP will likely see upside downstream of its Oklahoma plant tailgates. TRGP’s Grand Prix NGL pipeline has generated ~$150 million in EBITDA over the last year by linking its own and third-party Permian NGL production to the Gulf Coast market. By 1Q2021, TRGP is due to provide NGL pipe capacity from Oklahoma to its fractionators in Mt. Belvieu via the Grand Prix northern extension, which will connect to Williams’ (WMB) Bluestem project and TRGP’s Oklahoma and North Texas plants, including Hickory Hills, Stonewall, and Tupelo. East Daley estimates $40 million of EBITDA growth from TRGP’s NGL pipe extension in 2021. A recent order noted that construction is ahead of schedule and the extension could be online as early as November 1, 2020. Additional capacity means legacy NGL pipes owned by DCP Midstream (DCP) and ONEOK (OKE) will have a third party to compete for NGLs. -Rob Wilson Tickers: DCP, OKE, TRGP, WMB

DUC Season in Colorado:

September 11, 2020: Enterprise Products (EPD) secured several victories by nixing its Midland to Echo 4 (ME4) crude pipeline project.

EPD said September 9 it will cancel ME4 after amending agreements with some customers to extend minimum volume commitments (MVCs) on its other pipes, Midland to Echo 1-3, to move crude from Midland to the Gulf Coast, in exchange for reduced near-term volume commitments. In the process, EPD will save $800 million in growth capex while reducing cash flow risk on its asset base. EPD said cancelling ME4 will reduce its planned capex this year to $2.8 billion and $1.6 billion in 2021. The ME4 cancellation removes 450,000 b/d of future takeaway from the Permian, a small step in addressing a looming oversupply of basin egress capacity. East Daley’s latest Crude Hub Model projects the Permian will be significantly overbuilt even without ME4, which was due to start in 1H2021, as lower oil prices weigh on supply. By the end of 2022, we project the Permian will be overbuilt by about 3.5 MMb/d, resulting in tight spreads between Midland and the Gulf Coast. We see risks of rate and volume cuts to legacy pipes like Plains All American’s (PAA) Cactus I, Basin, and Sunrise II, as well as the Longhorn and BridgeTex systems owned by Magellan Midstream (MMP). EPD’s amended MVCs help hedge against these risks, a small price to pay for greater long-term security. -Andrew Ware Tickers: EPD, MMP, PAA

Road to Recovery

September 11, 2020: Gulf of Mexico (GOM) oil and gas production is recovering quickly since Hurricane Laura made landfall on August 27.

The GOM gas pipe sample jumped to 2.3 Bcf/d over the Labor Day weekend, or just 6% below the 30-day average prior to the start of system shutdowns ahead of the storm. Some damage has been reported. Genesis Energy (GEL) said its CHOPS oil pipeline system will not be fully restored before October 1. In the interim GEL is rerouting oil production into the Auger or Poseidon pipelines. Enbridge (ENB) said its Garden Banks gas pipeline remains shuttered due to damage from the storm, which has curtailed 0.2 Bcf/d of gas and ~60,000 bbl/d of oil production mostly operated by Shell. The gas pipe outage will probably keep oil production shut at Shell’s Enchilada, Auger, and Salsa fields that feed the Auger Pipeline. The Auger Pipeline accounts for only ~2% of Shell Midstream’s (SHLX) Adj. EBITDA, so even a prolonged outage would have minimal impact to its 3Q and 4Q2020 earnings. Williams’ (WMB) Transco Pipeline was one of the only pipelines reporting gas production during Hurricane Laura due to Shell’s Perdido field, located on the western part of the U.S. offshore, remaining online. Most offshore pipes including Nautilus, Transco, and Discovery are reporting strong volume recoveries so far. However, GOM output remains about 25% below 1Q2020 levels after voluntary curtailments and certain pipe outages reduced output. There could be upside to 4Q2020 production if the storm season remains quiet, but as of this writing the National Hurricane Center shows six potential storms. – Ryan Smith Tickers: ENB, DCP, GEL, SHLX, WMB

One Big Setback:

September 11, 2020: Markets responded quickly to news on Thursday, September 10 that all but one commissioner on the Colorado Oil & Gas Commission (COGCC) voiced support for 2,000-foot setbacks for oil and gas drilling in Colorado.

Companies hit hard by the news include PDC Energy (PDCE, -11%), DCP Midstream (DCP, -11%), Occidental Petroleum (OXY, -8%), and Western Midstream (WES, 7%), which all have sizeable investments in the DJ basin. Setbacks, which limit how close operators can drill near above-ground structures, have been a contentious issue in Colorado. Residents voted down Proposition 112 by 55% in 2018, rejecting rules that would have imposed 2,500-foot setbacks on drilling. After Governor Jared Polis and the Democratic-led Colorado House and Senate were inaugurated in January 2019, they quickly introduced Senate Bill 181, which mandated rulemakings to overhaul the industry, in the process changing the COGCC’s mandate from fostering oil and gas development to regulating the industry. The COGCC will not vote on the setback regulation until late October, when they will have completed hearings on all the proposed rules. Companies and investors now have new uncertainties to consider before investing in the state. East Daley will publish a Snapshot next week exploring the upstream and midstream risks posed by increased setbacks in Colorado. – Robert Ingram Tickers: DCP, OXY, PDCE, WES

Chaparral’s Chapter 22 Risks:

September 9, 2020: On August 16, Chaparral Energy (CHAP), an Anadarko basin operator, filed for Chapter 11 protection for the second time in less than four years, the infamous twice over Ch. 11, or “Chapter 22” filing.

East Daley’s G&P Allocation Model shows CHAP’s gas production of ~108 MMcf/d is gathered and processed by several midstream systems that should disperse counterparty risks. EnLink’s (ENLC) Central OK system processes just over half of CHAP’s volumes (57 MMcf/d) from its core STACK acreage. Targa Midstream (TRGP) receives one-quarter (28 MMcf/d) of CHAP’s northern Oklahoma production on its West OK system. Yet ENLC and TRGP both have diverse portfolios that help minimize risks. CHAP’s volumes represent 6% of throughput on ENLC’s Central OK system and 9% on TRGP’s West OK system. Like other E&Ps, CHAP has decreased its rig activity. CHAP consistently operated 3-4 rigs in the basin from 2018 to late 2019 but began dropping rigs in 1Q2020 and laid down its final rig in April. Anadarko operators have dropped over 130 rigs since 1Q2019, down to 13 rigs currently, making for a grim short-term outlook. The largest basin producer, Continental Resources (CLR), operated 22 rigs in 1Q2019 but only two rigs currently. In contrast to CHAP’s G&P contracts, CLR delivers most of its ~1 Bcf/d of STACK & SCOOP volumes to Enable (ENBL)’s Anadarko system, representing ~54% of its processed volumes. - Melissa J. Saurborn
Tickers: CLR, CHAP, ENBL, ENLC, TRGP

Not Dead Yet:

September 9, 2020: Producers are looking to drill again in the western Rockies in anticipation of higher gas prices.

As recently as 1Q2019, up to 23 rigs were drilling for gas in the in the Green River, Piceance, San Juan, and Uinta basins. Rigs began to drop in August 2019 as Henry Hub prices fell to the $2.20/MMBtu level, and recent market volatility has accelerated the pullback, down to only two rigs across all four basins in June 2020. But drilling appears to have bottomed with higher gas prices above $3/MMBtu expected this winter and into 2021. We have seen a few rigs return already to the western Rockies, and East Daley expects additional rig activity with higher gas prices into 2021. While these are not huge basins in terms of production, increased producer activity may generate some upside for Williams (WMB), Enterprise Products (EPD), MPLX, and Summit Midstream (SMLP), all of which gather gas volumes in the western Rockies. All four companies now have active rigs on their systems, although still fewer than in early 2019. Producers to watch include Jonah Energy, Ultra Petroleum, Southland Royalty, Terra Energy Partners, and Hilcorp. -Tegan Louw Tickers: EPD, MPLX, SMLP, WMB

I’m Coming Out:

September 9, 2020: Whiting Petroleum (WLL) on Sept. 1 announced it had emerged from Chapter 11 bankruptcy and completed its financial restructuring.

WLL declared Chapter 11 on April 1, the first publicly traded producer to file for bankruptcy after the crash in oil prices. WLL operated four rigs at the start of 2020, all in the Bakken, but dropped its final rig in late April. WLL also has DJ basin exposure in its Redtail field but has not used a rig to develop its acreage since June 2017. Nearly all of WLL‘s wells in the DJ basin are on its company-owned Redtail G&P system, which we argued this week could be a coveted asset if sold off to a midstream company (see our Sept. 1 Snapshot, “Bid It to Win It Part II: Finding Midstream Diamonds in the Rough”). WLL is the third-largest crude producer in the Bakken and had rigs in 2020 mostly on the ONEOK (OKE) and MPLX Robinson Lake G&P systems, which gathered 45% and 13%, respectively of its Bakken gas production. WLL accounts for 27%, 13%, and 11% of total throughput on the MPLX Robinson Lake, OKE, and HESM Tioga systems, respectively. WLL produced 8.1% of gross Bakken oil production in 4Q2019. Its share slipped to 7.1% in 2Q2020; we expect continued decline to 6.4% in 4Q2020. WLL’s emergence from bankruptcy could mean the return of some rigs for OKE and MPLX. Robert Ingram Tickers: Tickers: Tickers: HESM, MPLX, OKE, WLL

LNG Demand Recovery:

September 9, 2020: Recent weakness in LNG exports should end soon based on global price activity.

U.S. natural gas demand has remained resilient despite COVID disruptions, with 2Q2020 consumption flat vs. 2019, but gains in electric sector demand are masking a steep decline in exports. EIA data show LNG exports of 3.6 Bcf/d in June, a 55% decline from 8.1 Bcf/d in January. East Daley projects feedgas to export terminals bottomed at 2.8 Bcf/d in July as benchmark Asian and European gas prices converged with Henry Hub, leading to widespread cargo cancellations. Despite recent disruptions, forward price curves point to a recovery ahead. Spreads between Henry Hub and TTF, a Dutch trading hub in northwest Europe, should widen significantly in 4Q2020. East Daley estimates netbacks for Gulf Coast LNG exports will turn positive to Europe starting in October and grow increasingly profitable into 2023. Spot LNG exports to Asia remain out of the money until YE2021 based on JKM LNG contract prices but are profitable thereafter. Notably, spreads to Europe have strengthened in the last month despite a 28% rise in 2021 Henry Hub futures. We expect LNG exports in 2021 will average 10.1 Bcf/d as global demand returns. Gas-levered midstream names such as Antero Midstream (AM), Equitrans Midstream (ETRN), Summit Midstream (SMLP), MPLX, and Williams Companies (WMB) should benefit from more demand for gas from basins in the Northeast and Haynesville as WTI remains subdued and associated gas production muted. -David Dubetz Tickers: AM, ETRN, SMLP, MPLX, WMB


DUC Season in Colorado:

September 9, 2020: In its 2Q2020 earnings’ call, Diamondback Energy (FANG) reiterated its plan to focus 70% of its activity in the Midland basin for the rest of 2020.

East Daley has raised our earnings outlook for Western Midstream (WES) after the company reported 2Q2020 EBITDA well above our and Street expectations. With little drilling activity on its G&P asset footprint in the quarter, we attribute the volume and earnings beat to a drawdown in drilled but uncompleted (DUC) wells. In its 2Q2020 earnings call, WES disclosed that E&Ps held an inventory of 250 DUCs on its G&P systems, 50% of which belong to Occidental Petroleum (OXY) in the DJ and Delaware basins. WES management said it expects E&Ps to complete ~100 DUCs in 2H2020, 50% of which are on its DJ system. With MVCs in place for both gathering and processing, East Daley now assumes OXY and third parties will complete DUCs in line with management’s guidance. In East Daley’s Blueprint Summaries, we had modeled that 21 DUCs in 2H2020 and 50 DUCs in 2021 would be completed on WES’s DJ system. Similarly, our forecast for DUC completions in the Delaware was below WES’s new guidance. In addition to the drawdown in DUCs, DCP Midstream (DCP) disclosed its contract with WES on the new Latham II plant would not start until 2021, which is later than expected. WES has used its own gathered volumes to fill the Latham complex before DCP’s contract begins on Latham II. Using the latest state-reported plant inlet volumes in East Daley’s Production Scenario Tools and WES’s updated guidance for DUC completions, we are more bullish on the company’s cash flow outlook. Our EBITDA forecast for WES is now slightly above WES’s updated guidance range for 2020 and above the Street in 2021. –Zack Van Everen Tickers: Tickers: DCP, WES

August 2020 Data Insights

Recovery at Port of Corpus Christi:

August 28, 2020: According to East Daley’s ship tracking data, activity appears to have returned to normal at most crude terminals in the Port of Corpus Christi following a fatal barge explosion.

On August 21, the dredger Waymon L. Boyd struck an underwater propane pipe, triggering an explosion and fire that claimed four lives. While the Port managed to secure the ruptured line and extinguish the fire, the dredger then fell apart and sank, blocking the ship channel. The fire took place near the former International Grain Port Terminal that EPIC Midstream has repurposed into its EPIC Marine Terminal for crude exports. The terminal includes two docks, a West dock that went into service in 4Q2019 and an East dock due to start in 1Q2021. Drone footage shows the fire closest to the terminal’s East dock. EPIC has not commented on any damage to its facilities or further delays to shipments. East Daley’s ship tracking data show the debris blocked crude tanker traffic west of the fire until August 24. Other terminals impacted by the temporary shutdown include Flint Hills West, Buckeye, Citgo West, Pin Oak, Valero’s (VLO) Valero West, and Plains’ (PAA) terminal. The channel closure was short and unlikely to negatively impact oil export volumes. Tickers: PAA, VLO

Back to Frac:

August 28, 2020: Crestwood Equity (CEQP) is benefiting from the return of shut-in wells in the Bakken where processing at its Bear Den plant has rebounded sharply.

Residue gas from Bear Den fell 54% M-o-M in May 2020 but has recovered to ~100 MMcf/d, in line with output before COVID disruptions. The Bear Den plant was expanded in 3Q2019 and can process up to 150 MMcf/d of gas gathered on CEQP’s Arrow system. Wells that were not curtailed should have naturally declined, so the return of Bear Den’s output near April levels suggests that new wells are being added. WPX Energy (WPX) is a likely contributor. WPX said in 2Q2020 earnings that it brought a completion crew back to the Bakken in July. This crew is likely working through DUCs that are connected to Arrow and processed by Bear Den, supporting the strong comeback in gas output. WPX also has run the only rig on the Arrow system since May, from a peak of seven rigs in 4Q2019. But WPX also said it plans to cut its Bakken drilling from two rigs to one, meaning coin-flip odds that WPX drops the final rig on CEQP’s system. WPX executives also said sustained oil prices closer to $50/bbl are required to maintain growth. East Daley currently models Bear Den’s FY2021 gas processing at 110 MMcf/d, but if WPX drops its rig and stops completing DUCs, volumes could fall to ~75 MMcf/d. Lower gas processing would reduce CEQP’s Arrow EBITDA by 13%, from ~$263 million to ~$229 million for FY2021. Tickers: CEQP, WPX

All Downhill from Here:

August 28, 2020: Western Canadian Select (WCS) has long been the worst oil price point for North American producers, at times trading at a $20-$30/bbl discount to WTI.

Recently WCS prices have strengthened, trading at only a ~$11/bbl discount to WTI. This is not likely to be the new normal though, and producers and investors should expect weakness ahead. WCS has been discounted less because E&Ps have reduced oil production in response to the market downturn, opening space on Enbridge’s (ENB’s) Mainline system that delivers crude to U.S. Midwest markets. The differential should stay around $11/bbl while space is available on ENB’s Mainline, since it costs $5-6/bbl to ship crude on the pipeline to the Midwest, plus another ~$5/bbl discount for the heavybitumen grade. ENB should see further upside once oil production increases and its Mainline, which accounts for 30% of its EBITDA, fills up. But Canadian producers would then need to go back to using rail. The price differential should then widen back to $15-17/bbl, or approximately the price to rail barrels to Cushing. Tickers: ENB

The Bigger They Are, the Harder They Fall:

August 28, 2020: ONEOK (OKE) has amassed the largest G&P system in the Williston basin but has also been hit hard by shut-ins in recent months.

OKE in 2019 processed 46% of the Williston’s 2.4 Bcf/d of marketed gas production. Throughput on the 1.3 Bcf/d OKE system peaked in March 2020 at an average of 1,157 MMcf/d, but the latest monthly plant data show receipts dropped to 758 MMcf/d in May and bottomed in June under 700 MMcf/d. Based on the system’s residue flow sample, East Daley estimates throughput into OKE’s processing plants is back above 1 Bcf/d in August. This bounce-back is slightly higher than what East Daley is modeling for OKE in our latest Blueprint Summaries. Residue gas flow data from OKE’s plants suggest inlet receipts of 971 MMcf/d so far in 3Q2020 vs. our estimate of 865 MMcf/d in OKE’s Blueprint. However, rig activity on OKE’s G&P system has dropped to four from an average of 22 rigs in 1Q2020, which should eventually drag on output. The total Williston flow sample also helps us estimate OKE’s NGL volumes in the basin, and we project NGL volumes in August have only reached 88% of the March average. Lower crude prices have tempered producers’ drilling programs and OKE’s growth outlook. Since the downturn, OKE has delayed over $1 billion in planned capex in the Williston, including the 200 MMcf/d Demicks Lake III and 200 MMcf/d Bear Creek II processing plant expansions. Ticker: OKE

Best of Times, Worst of Times:

August 28, 2020: In its 2Q2020 earnings’ call, Diamondback Energy (FANG) reiterated its plan to focus 70% of its activity in the Midland basin for the rest of 2020.

FANG plans to reduce its operated rigs to about four in the Midland and two in the Delaware in 2H2020. FANG is increasingly focused on the Midland due to its relatively resilient economics amid lower oil prices, including lower LOE, available infrastructure, and lower midstream costs. FANG’s Midland focus may negatively impact some private G&P systems in the Delaware such as Brazos Midstream and Vaquero Midstream, which should see less throughput. In addition to less drilling, FANG also estimated that roughly two-thirds of its curtailed production is based in the Delaware. Brazos and Vaquero were most likely impacted by this decision as their combined interstate deliveries dipped to a 2020 low of 124 MMcf/d in late April and May. Yet Midland assets like EnLink’s (ENLC) MEGA system and Rattler Midstream’s (RTLR) Amarillo Rattler JV have seen gathered gas volumes hold relatively steady. FANG’s Midland shift will help lift ENLC’s Permian segment in future quarters, as production curtailments likely will not be as severe as some anticipate. Although the move helps RTLR’s JV investment in Amarillo Midstream, RTLR’s sourced water volumes fell 18% Q-o-Q as Midland wells produce less water than in the Delaware. East Daley expects RTLR’s gathered volumes will decline further in 3Q2020 and negatively impact its overall 2020 EBITDA. Tickers: ENLC, FANG, RTLR

Best House on a Bad Block:

August 21, 2020: The law firm of Haynes & Boone published its latest quarterly bankruptcy report on oil and gas last week.

From 2015 to July 2020, H&B tallies $291 billion in defaults, 60% of which came from E&P, 33% from OFS, and under 8% from midstream. The $80 billion in defaults on secured and unsecured debt thus far in 2020 puts the industry on track for $136 billion in total defaults on an annualized basis, which would eclipse the recent $85 billion peak in 2016. In 2020, we’ve seen $460 million in midstream defaults from three entities: Maximum Elite Pipeline, Kingfisher Midstream, and Permico Midstream Partners. Tom Ward’s new entity Mach Resources, along with partner Bayou City, bought the assets of Alta Mesa and its midstream subsidiary out of bankruptcy for $160 million. That compares to a market value of $3.8 billion in 2018, a massive failure for Jim Hackett, who previously ran Anadarko, and private equity firm Riverstone, which had backed the new venture. Permico’s Texas NGL pipeline was to have been a 500-mile, 300 Mb/d line from the Permian to Corpus Christi, one part of a larger $1.8 billion NGL system to Mt. Belvieu.

Start Me Up:

August 21, 2020: A new rig began drilling in the southernmost part of the DJ basin, indicating new opportunities for Western Midstream (WES).

Crestone Peak Resources, a private E&P formed in October 2016, is using the rig to develop its newly acquired acreage in Adams and Arapahoe counties, CO. In March 2020, Crestone agreed to pay ConocoPhillips (COP) $380 million for 97,000 acres, nearly tripling its acreage position. The newly acquired position has significantly less urban exposure than Crestone’s legacy acreage near the cities of Broomfield, Lafayette, Erie, Frederick, and Boulder. Urban exposure has long been a concern for DJ operators, with initiatives like Proposition 112 (2018) and CO Senate Bill 181 (2019) raising more hurdles for drilling and completing wells in CO’s Front Range. COP in 2019 had maintained one rig on the acreage sold to Crestone, in part to meet drilling obligations as part of an agreement with Anadarko (APC), later acquired by Occidental Petroleum (OXY). Crestone maintained an average 2.3 rigs in the DJ in 2019, with all new wells processed by WES. Crestone stopped all drilling in mid-April amid market volatility, but the return of a rig indicates a readiness to start new development. It is unclear if the new rig on the legacy COP acreage is long term or to meet ongoing obligations with OXY, but the lack of COGCC permits in this region suggests the latter. Tickers: APC, COP, OXY, WES

Up from Here:

August 21, 2020: Producer shut-ins and curtailments severely affected the Powder River basin in 2Q2020.

East Daley’s gas sample showed gathered volumes, excluding coalbed methane (CBM) production, declined 33% Q-o-Q in 2Q2020. But the outlook is improving for midstream operators and leading producers like EOG Resources (EOG) and Devon (DVN). Average 3Q2020 gathered gas volumes in the Powder River are 24% higher vs. 2Q2020, suggesting shut-in wells are back. Moreover, a rig operated by Pajero Energy returned to the basin in early August after a six-week period with no rig activity. EOG removed their final rig from the Powder River in late June. It had been operating on privately owned Meritage’s system, the largest G&P system in the basin. Meritage saw Q-o-Q gas gathering decline 29% in 2Q2020, but its volumes have rebounded strongly, back up 29% so far in 3Q2020. Other nearby systems, including Western Midstream’s (WES) Hilight plant and privately owned operators Evolution and Tallgrass have seen similar recoveries. DVN and EOG are the largest E&Ps on Meritage’s system, accounting for 60% of its gathered gas volumes. The turnaround for the basin and Meritage bodes well for Riverstone, Meritage’s private equity sponsor. Tickers: DVN, EOG, WES

MEGA Millions:

August 21, 2020: MEnLink Midstream (ENLC) had an outstanding 2Q2020, beating consensus estimates by up to 8%, or $19 million.

The beat was primarily driven by ENLC’s Permian segment, which had its best quarter to date. Several factors including asset location, contractual agreements, increased throughput, and commodity price moves led to the segment’s outperformance. ENLC’s MEGA G&P system in the Midland is primarily backed by Diamondback Energy (FANG), Concho Resources (CXO), and Crownquest. The FANG and CXO relationships were inherited from ENLC’s acquisition of Coronado Midstream. Although most of ENLC’s G&P contracts are fixed fee, the legacy Coronado relationships are structured as percentage-of-proceeds (POP) contracts. Average Henry Hub prices declined from $1.91 to $1.71/MMBtu Q-o-Q, which normally would be nothing to get excited about. However, East Daley believes the POP contracts are tied to El Paso Permian rather than Henry Hub, and both El Paso Permian prices and ENLC’s overall gas sales jumped ~100% from 1Q2020 to 2Q2020. With production curtailed across the basin, declining associated gas production relieved takeaway constraints and caused Permian gas prices to nearly double. This would also explain ENLC’s negative gas sales in 2Q2019 when Permian prices went negative on oversupply, and the subsequent jump in 3Q2019 when the Gulf Coast Express pipeline came online. If our assumption is correct, these POP contracts should continue to outperform for ENLC in 3Q2020 as Permian gas prices remain strong amid a summer heat wave in the U.S. West. Tickers: ENLC, FANG, CXO

Hit the Gas:

August 21, 2020: EQT Corp. (EQT) has restored production from all wells previously curtailed in the Southwest Marcellus-Utica (SWMU), the company said in its 2Q2020 earnings report. While lower-for-longer WTI prices near $40/bbl force oil-weighted producers into maintenance mode, natural gas prices continue to climb higher.

YTD 2021 Henry Hub futures have increased 20%, or $0.48/MMBtu to average $2.90/MMBtu as of August 19. East Daley combines our Production Scenario Tools from 16 basins with our gas demand forecast to derive an adjusted Henry Hub price required to balance the U.S. gas market. Our August PST predicts Henry Hub prices will average $3.04/MMBtu in 2021, 14c higher than prevailing prices. East Daley estimates that market-driven curtailments from April to August have removed 5.6 Bcf/d of associated gas supply from major oil basins, requiring more production from dry gas basins like the Marcellus and Haynesville to backfill lost supply (see East Daley’s August 6 Snapshot, “Bandy About the Barrel Part II – Gas Supply in a $30-60/bbl Oil Price Band”). Further driving Henry Hub is that natural gas demand has remained resilient during COVID, particularly for power generation. EIA’s latest data show average gas demand from March to May increased 1% Y-o-Y, in contrast to a sharp decline in petroleum demand this spring. East Daley predicts natural gas has further to climb in 2021, presenting potential upside to gas-weighted midstream names such as Antero Midstream (AM), Equitrans Midstream (ETRN), Summit Midstream (SMLP), MPLX LP (MPLX), and Williams (WMB). Tickers: AM, ETRN, SMLP, MPLX, WMB

Eagle Dive:

August 14, 2020: Market volatility has reduced rig activity in all major oil basins, but impacts have been particularly severe in the Eagle Ford.

Only nine rigs were operating in the basin as of Aug. 2, an 89% decline from an average 84 rigs drilling in 1Q2020. By contrast, the latest rig count is 72% lower in the Permian vs. the basin’s 1Q2020 average rig count. Drilling has also held up better in the remote Bakken, where the rig count is 78% lower vs. 1Q2020. While drilling has flattened or increased in other oil basins as WTI rebounded over $40/bbl, Eagle Ford rigs continue to decline. According to East Daley’s Midstream Activity Tracker, Enterprise (EPD), Energy Transfer (ET), and DCP Midstream (DCP) operate the basin’s top G&P systems by drilling, averaging 27, 20, and 17 rigs, respectively in 1Q2020. Only one rig was active on EPD’s Eagle Ford system as of Aug. 2, while ET’s and DCP’s systems each had four rigs. East Daley’s Blueprint Model forecasts a limited increase in rigs on DCP’s system but sees downside risk ahead for ET and EPD. We project a reduction of $25 million and $21 million in 2021 EBITDA for ET and EPD, respectively, if Eagle Ford rigs remain at current levels. Tickers: : DCP, EPD, ET

Bring it Back:

August 14, 2020: EQT Corp. (EQT) has restored production from all wells previously curtailed in the Southwest Marcellus-Utica (SWMU), the company said in its 2Q2020 earnings report.

EQT on May 16 began curtailing 1.4 Bcf/d of production when Dominion South gas prices fell under $1/MMBtu. According to East Daley’s SWMU pipe sample, ~80% of EQT’s curtailed volumes came from Equitrans’ (ETRN) Strike Force/Poseidon and Pennsylvania G&P systems. In its earnings update, ETRC said EQT’s shut-in program impacted 2Q2020 revenue, lasting for 45 days at an average 1.2 Bcf/d on its G&P systems. EQT CEO Toby Rice said the E&P used “a moderated approach” to return shut-in wells in early July and had fully restored production. East Daley’s pipeline sample shows SWMU gas production steadily increased from July 10 to July 20, returning near prior output levels in early May. EQT characterized its SWMU shut-in program as a success, reporting no degradation of performance from shutin wells, and said it is prepared to repeat curtailments if regional gas prices fall again. Tickers: AEQT, ETRN

Eagle Dive:

August 14, 2020: Market volatility has reduced rig activity in all major oil basins, but impacts have been particularly severe in the Eagle Ford.

Only nine rigs were operating in the basin as of Aug. 2, an 89% decline from an average 84 rigs drilling in 1Q2020. By contrast, the latest rig count is 72% lower in the Permian vs. the basin’s 1Q2020 average rig count. Drilling has also held up better in the remote Bakken, where the rig count is 78% lower vs. 1Q2020. While drilling has flattened or increased in other oil basins as WTI rebounded over $40/bbl, Eagle Ford rigs continue to decline. According to East Daley’s Midstream Activity Tracker, Enterprise (EPD), Energy Transfer (ET), and DCP Midstream (DCP) operate the basin’s top G&P systems by drilling, averaging 27, 20, and 17 rigs, respectively in 1Q2020. Only one rig was active on EPD’s Eagle Ford system as of Aug. 2, while ET’s and DCP’s systems each had four rigs. East Daley’s Blueprint Model forecasts a limited increase in rigs on DCP’s system but sees downside risk ahead for ET and EPD. We project a reduction of $25 million and $21 million in 2021 EBITDA for ET and EPD, respectively, if Eagle Ford rigs remain at current levels. Tickers: : DCP, EPD, ET

Bring it Back:

August 14, 2020: EQT Corp. (EQT) has restored production from all wells previously curtailed in the Southwest Marcellus-Utica (SWMU), the company said in its 2Q2020 earnings report.

EQT on May 16 began curtailing 1.4 Bcf/d of production when Dominion South gas prices fell under $1/MMBtu. According to East Daley’s SWMU pipe sample, ~80% of EQT’s curtailed volumes came from Equitrans’ (ETRN) Strike Force/Poseidon and Pennsylvania G&P systems. In its earnings update, ETRC said EQT’s shut-in program impacted 2Q2020 revenue, lasting for 45 days at an average 1.2 Bcf/d on its G&P systems. EQT CEO Toby Rice said the E&P used “a moderated approach” to return shut-in wells in early July and had fully restored production. East Daley’s pipeline sample shows SWMU gas production steadily increased from July 10 to July 20, returning near prior output levels in early May. EQT characterized its SWMU shut-in program as a success, reporting no degradation of performance from shutin wells, and said it is prepared to repeat curtailments if regional gas prices fall again. Tickers: AEQT, ETRN

DUCing a Downturn:

August 14, 2020: Western Midstream (WES) handily beat earnings expectations last week due partly to outperformance on its Delaware basin G&P assets.

WES posted 2Q2020 Adj. EBITDA of $514 million, ~18% above East Daley’s forecast and 16% above consensus estimates. Gas throughput on the WES – DBM system in West TX totaled 1.3 Bcf/d, a 1% decline from 1Q2020 but 9% above our forecast. East Daley believes the Delaware gas assets outperformed due to lower-than-forecasted curtailment volumes and a healthy DUC inventory following robust drilling in 2019. The assets are tied closely to Occidental Petroleum (OXY) following its acquisition of parent Anadarko Petroleum (APC) in August 2019. Since the deal closed, activity on the WES – DBM system rose from 10 to 21 rigs in 4Q2019 and 1Q2020. Active E&Ps include OXY/APC, BP, ConocoPhillips (COP), and private Mewbourne Oil. Drilling activity has dropped to ~4 rigs following recent volatility, with Mewbourne maintaining a two-rig program. OXY’s rig count on the system dropped from 4.5 in 1Q2020 to 0 in June and July. OXY was recently operating two rigs in the Permian and guided in 2Q2020 earnings to one net Permian rig in 2H2020. Declining rig counts and a less-than-stellar upstream outlook will pose challenges for WES to maintain outperformance on its Delaware basin assets. Tickers: WES, OXY, BP, COP

Appalachian Marriage:

August 14, 2020: On August 12, Southwestern Energy (SWN) announced an all-stock transaction to acquire Montage Resources (MR).

The merger, expected to close in 4Q2020, will create the third-largest gas producer in Appalachia behind EQT and Antero Resources (AR), with pro forma 2Q2020 combined production of 3.3 Bcfe/d. The MR acquisition will boost SWN’s Northeast footprint by 70%, adding ~325,000 acres concentrated in the SWMU. There is little overlap between G&P systems used by the two E&Ps. Montage gathers mostly on the Eureka Hunter and Blue Racer systems. Nearly all SWN production is gathered on DTE Energy’s (DTE) Bluestone system and G&P systems operated by MPLX, Energy Transfer (ET), and Williams (WMB). MR in 2020 has averaged 0.6 rigs on Blue Racer and 0.3 rigs on MPLX Mobley. SWN this year has operated rigs on MPLX’s Majorsville (1.7 rigs), Howard Energy’s Angelina (1.1 rigs), DTE’s Bluestone (1.1 rigs), and WMB’s Ohio Valley (0.6 rigs) systems. Currently, Montage is running one rig on the Blue Racer system while SWN is operating two rigs split between the DTE Bluestone and MPLX Majorsville systems. The SWN-MR tie-up could bring opportunities for gatherers near MR’s undeveloped acreage in SWMU like Blue Racer and MPLX. Tickers: AR, DTE, ET, EQT, MR, SWN, WMB

The Good, Bad, and Ugly:

August 14, 2020: EIA this week slashed its near-term outlook for U.S. oil production, falling well below East Daley’s own view on the recent impacts of shut-ins.

In its August STEO, EIA reduced its oil production forecast by ~0.7 MMb/d in 2Q-3Q2020 vs. its July STEO, with crude supply now seen dipping below 10 MMb/d in June. By contrast, East Daley’s July Production Scenario Tools forecasts 2Q-3Q2020 oil production 0.6 MMb/d higher vs. the latest STEO. In 3Q2020, East Daley projects U.S. oil production will average 11.3 MMb/d vs 10.8 MMb/d by EIA. East Daley forecasts curtailments based on E&P guidance and daily gas pipe sample data, and we refine our estimates monthly as producers update on shut-in volumes and timing for their return. While East Daley does not expect shut-in impacts to be as severe, we are less optimistic than EIA for a rebound in oil production next year. We project oil production to be relatively flat in 2021, averaging 10.7 MMB/d vs. EIA’s 11.1 MMb/d outlook. Our recent survey of 2Q2020 earnings by E&Ps shows widespread hesitation to return rigs back to work in major oil basins, which we expect will slow a return to growth (see East Daley’s Aug. 11 Snapshot “Knives Out – 2Q2020 E&P Guidance Review”). We believe merging upstream feedback with real-time data yields a more realistic modeling of oil supply. To learn more about East Daley’s perspective on 2Q2020 E&P guidance, tune in to our webinar on August 19.

Barnett Bounce-back:

August 7, 2020: Private investment is bringing new life back to the Barnett shale.

According to East Daley’s Midstream Activity Tracker, Barnett rig activity increased from two to four rigs for the week ended July 26 due to drilling programs by private E&Ps, including Atoka Operating, JDL Operating, Felt Drilling, and Midville Energy. The Barnett averaged 7 rigs in FY2019 and 5 rigs in 1Q2020, but all drilling ceased by June amid market volatility and depressed gas prices. Gas recently climbed off seasonal lows, with Henry Hub this week passing $2.00/MMBtu, and East Daley expects higher prices ahead (see East Daley’s August 6 Snapshot, “Bandy About the Barrel Part II – Gas Supply in a $30-60/bbl Price Band”). Private investors are difficult to track, but East Daley forecasts rig activity can be sustained in the Barnett as gas prices climb. Midstream operators in the Barnett, including Kinder Morgan (KMI), Targa Resources (TRGP), Crestwood Equity CEQP), EnLink Midstream (ENLC), and Energy Transfer (ET), stand to benefit from the rebound in Barnett drilling, which should help offset natural declines from older wells. Tickers: KMI, TRGP, CEQP, ENLC, ET

Last Pipe Standing:

August 7, 2020: Several East Daley clients have inquired about potential upside for Equitrans Midstream’s (ETRN) Mountain Valley Pipeline (MVP) JV following the July 5 cancellation of the Atlantic Coast Pipeline (ACP).

MVP follows a similar route as ACP from Appalachia to Southeast markets and has a compression expansion opportunity for ~500 MMcf/d, which would generate ~$60 million of additional annual EBITDA for ETRN if the expansion were contracted at current MVP rates. East Daley believes MVP is unlikely to substitute for the loss of ACP since it travels too far west of ACP shippers’ existing plants. While possible to take MVP (~$0.73/Mcf) to Transcontinental (~$0.18/Mcf) or Columbia (~$0.23/Mcf) to reach the facilities, those pipes are already contracted at capacity. In its 2Q2020 earnings call, EQT said it was in discussions to sell a portion or potentially all its 1.3 Bcf/d capacity on MVP to other shippers. While minimizing MVCs is positive for EQT, it also pushes back the immediate need for an MVP expansion. However, East Daley models egress constraints occurring in the Northeast by 2024 without ACP, which may be the catalyst for an MVP expansion in the next few years. Tickers: ETRN, EQT

Bucking the Trend:

August 7, 2020: On August 6, DCP Midstream (DCP) reported 2Q2020 earnings that included a surprise beat in its Permian G&P segment.

DCP reported Permian G&P activity of 987 MMcf/d, 7% above East Daley’s estimate. The Delaware system accounts for 65% of DCP’s gathered Permian volumes and has shown notable resilience in the face of widespread shut-ins and rig attrition across the basin. East Daley’s pipe sample shows production on the DCP Delaware system fell 8% on average in May vs April, compared to a 12% M-o-M decline in our total Permian sample. The DCP system’s resilience is likely due to Devon Energy (DVN), which has curtailed less production vs. peers. East Daley’s G&P Allocation Model shows DVN as the top counterparty on DCP’s Delaware system, and is responsible for 50% of gathered volumes. DVN’s 2Q2020 earnings noted 10 Mb/d of company-wide curtailments, one-half of which were in the Delaware basin. DVN said it focused its entire 2Q2020 development activity on the Delaware basin, and guided that 70% of its capex will be dedicated to the Delaware in 2H2020. DVN’s rig activity has remained steady on DCP’s Permian system at the expense of other regions where the E&P operates. DVN’s operational shift presents downside to G&P systems in other basins that rely heavily on its production, including Meritage in the Powder River basin, and Anadarko systems operated by EnLink (ENLC) and MPLX LP (MPLX). Ticker: DCP, DVN, ENLC, MPLX

Northeast SWEPI-stakes:

August 7, 2020: National Fuel Gas (NFG) subsidiaries Seneca Resources and NFG Midstream this week completed the purchase of SWEPI’s (Shell) dry gas acreage and associated gathering infrastructure in Tioga County, PA.

The $541 million cash deal gives Seneca Resources ~450,000 net leasehold acres and ~350 producing wells. NFG Midstream will take the keys to ~150 miles of dry gas gathering and over 100 miles of water pipeline and related facilities. Since announced on May 4, 2020 the gas strip has begun to shift higher, but East Daley is calling for ~15% higher gas prices in 2021 and ~10% higher in 2022, primarily due to the lower associated gas volumes hitting the market (see East Daley’s August 6 Snapshot, “Bandy About the Barrel Part II – Gas Supply in a $30-60/bbl Price Band”). This bullish price outlook may help the package exceed NFG’s initial expectations for the gathering system to generate $35 million in EBITDA over the next 12 months. The system connects to Dominion Energy Transmission, Tennessee Gas Pipeline, Empire Pipeline and National Fuel Gas Supply, with most volumes going onto Dominion and Empire. Throughput has averaged 272 MMcf/d so far in 2020, which is lower than the 334 MMcf/d average in 2019. There is currently 559 MMcf/d of firm transport contracted off the gathering system, with 335 MMcf/d on Dominion and 224 MMcf/d on Empire. Due to its proximity to NFG’s existing Covington system, there is potential for the two gathering systems to be tied together. Covington has ~220 MMcf/d of capacity and connects into Tennessee Gas Pipeline. Ticker: NFG, EPD, ET, SMLP, TRGP, XOM

No Rigs for You!:

August 7, 2020: ExxonMobil (XOM) on July 31 announced plans to significantly pare back its drilling program in the Permian, a bad trend for G&P operators like Energy Transfer (ET) and Enterprise Products (EPD).

XOM said it expects to deploy 10-15 rigs by YE2020, a far cry from its ~55 active Permian rigs in early February. XOM had reduced its Permian rig activity to ~24 rigs by June, indicating it has already implemented much of the revised program. Most of XOM’s rig cuts to date have occurred on G&P systems owned by ET and private companies. However, XOM still has another 10-15 rigs to cut, which means more potential downside for midstream companies. ET and EPD are most exposed to additional cuts as they started 3Q2020 with a weekly average of 10 and eight XOM rigs on their Permian systems, respectively. Summit Midstream (SMLP), EnLink (ENLC), and Targa Resources (TRGP) also service XOM in the basin, but only had two or fewer rigs on their systems at the start of 3Q2020. XOM so far in 3Q2020 has cut an average three rigs each from Permian G&P systems owned by ET and EPD. SMLP has seen its XOM rigs increase to three, while ENLC and TRGP have seen XOM rigs stay flat. TRGP and ENLC both have diverse Permian portfolios, but XOM comprised 48% and 91% of rig activity on ET and EPD’s Permian G&P systems, respectively. Further rig cuts by XOM on acreage served by ET and EPD could lead to further deterioration in volumes and earnings in their G&P segments. Ticker: ENLC, EPD, ET, SMLP, TRGP, XOM

July 2020

Snapshots

Bandy About the Barrel – Oil Supply in a $30-$60 Price Band

July 30, 2020: Amid a turbulent year, oil has stabilized in the $40/bbl range. The oil market in 2020 was roiled first by discord in the expanded OPEC+ coalition, then by a massive hit to demand in April amid shut-in economic conditions that pushed WTI prices below $20/bbl.

Markets have rebounded since May on rising demand as global economic activity slowly returned, as well as through the restoration of physical balance as producers shut-in production. In response, WTI rose in July for the third straight month. East Daley’s latest July Production Scenario Tools incorporates recent stability in the forward outlook, with WTI priced at a slight contango in the $40/bbl price range through 2030. In recent trading, front-month WTI traded near $41/bbl. WTI future contracts do not cross the $50/bbl threshold until 2028.

DAPL: Living in Legal Limbo

July 23, 2020: The future status of the Dakota Access Pipeline (DAPL) remains uncertain after a federal appellate court temporarily blocked a shutdown ordered by a lower court that was due to begin in August.

The U.S. District Court for the District of Columbia on July 5 vacated the grant of an easement to DAPL, citing an inadequate environmental impact statement (EIS), and ordered the pipe shut down within 30 days. The U.S. Court of Appeals for the District of Columbia Circuit on July 14 issued an administrative stay that will remain in effect while DAPL operator Energy Transfer (ET) and pipe opponents file briefs. DAPL for now is operating normally while ET’s appeal is considered. The market impacts of the DAPL case will ultimately hinge on two decisions. First, the U.S. Court of Appeals will rule on the sufficiency of the U.S. Army Corps of Engineers’ (Corps) environmental review of DAPL based on guidelines set forth by the National Environmental Policy Act. The Corps has given a preliminary timeline of ~13 months to provide a revised EIS for DAPL were its review found to be insufficient. The second legal decision is procedural. Rather than idling the pipe, it is possible that ET is granted an additional stay that would allow DAPL to operate normally while a second EIS is prepared by the Corps. This outcome would effectively avoid market disruptions impacting Bakken companies.

Chevron-Noble Merger – Midstream Implications

July 22, 2020: On July 20, Chevron (CVX) announced a definitive agreement to acquire Noble Energy (NBL) for $5 billion, or $10.38/share based on CVX’s closing price on July 17, 2020.

Under the terms of the agreement, NBL shareholders will receive 0.1191 shares of CVX for each NBL share. The acquisition is expected to close in 4Q2020. The CVX-NBL merger has significant implications for the midstream sector given both companies have diverse U.S. onshore portfolios in the Permian and DJ basins, as well as NBL’s existing commitments to its Noble Midstream (NBLX) spinoff. This analysis looks specifically at the midstream impacts in the combined portfolio’s U.S. onshore acreage.

Knowing the Difference – Shipper Commitments on Crude vs. Natural Gas Pipelines

July 15, 2020: Over the last few years, U.S. oil and gas production has been marked by notable volume increases year after year to the benefit of many pipeline operators.

This period of substantial volume growth has not only underpinned new-build pipelines and various expansion projects but has also allowed legacy infrastructure to run at utilization rates well above contracted capacity. However, in the wake of the recent commodity price collapse, production has pulled back notably as producers shut in legacy volumes and defer much of their planned drilling and completion activity. As our outlook for production volumes has deteriorated, so too has our outlook for pipeline shipments across the country. Despite some recent recovery in prices, this new “normal” highlights some important nuances for commitment terms between shippers and pipeline companies. While pipeline contracts are intended to ensure throughput certainty, the differing nature of contracting terms between crude and natural gas pipelines can create very different outcomes for both shippers and pipeline operators. Understanding these differences is important to accurately assess a pipeline’s ability to retain cash flows through this and any other future commodity cycle downturns.

LNG Glut Puts U.S. Gas Market in Deep Freeze

July 8, 2020: A global supply glut of liquefied natural gas (LNG) is weighing heavily on U.S. gas market balances and posing downside risk to prices ahead of the 4Q2020-1Q2021 heating season.

The U.S. gas market had seemingly weathered pandemic disruptions this spring better than other commodities since consumption is more closely tied to temperature than transportation, while ongoing coal displacement continues to support power generation demand despite economic weakness. As it turns out, the Achilles heel for U.S. gas balances is growing exposure to overseas markets rather than any domestic factor. Feedgas for LNG export facilities on the Gulf and Atlantic coasts, many newly started, peaked at 8.6 Bcf/d in March 2020 and then began to wobble as gas prices in Europe and Asia, falling sharply since 4Q2019, converged with U.S. price levels (see Figure 1). Feedgas deliveries for LNG export facilities averaged 4.1 Bcf/d in June, a decline of 4.5 Bcf/d vs. March 2020 that dropped LNG export utilization to under 40%. Bloomberg reports that up to 45 U.S. LNG cargoes are due to be cancelled in July, representing potentially 5 Bcf/d of lost gas demand for the month. Henry Hub gas prices have fallen to 25-year lows under $1.50/MMBtu amid high storage levels and the sudden collapse in the call on domestic gas from LNG export facilities.

DAPL Ruling – Catalyst for Pipeline Constraints

July 7, 2020: On July 6, the U.S. District Court for the District of Columbia vacated the U.S. Army Corps of Engineers’ (Corps) grant of an easement to the Dakota Access Pipeline (DAPL) and has ordered the shut-down of DAPL within 30 days, by August 6.

According to the ruling, the pipeline shall remain idled until the Corps provides an Environmental Impact Statement (EIS) on the pipeline sufficient to satisfy the requirements set forth by the National Environmental Policy Act. The Corps has given a preliminary timeline of approximately thirteen months to provide the EIS for DAPL, indicating that DAPL will likely be down for over a year, which has significant implications for North America’s crude flow dynamics. There is additional risk that the process could take longer than the Corps’ proposed timeline considering the “mean time from initiation to completion of an EIS is 3.6 years across all federal agencies, and the Corps’ own average time is even longer,” according to the ruling. Assuming the District Court’s order holds, Bakken producers are set to face notable pipeline constraints in the near-term, leading to a discounting of Bakken crude that will incentivize incremental railing in order to alleviate the constraint.

Party Like it is 2002 - Berkshire is Back for Midstream M&A

July 6, 2020: Berkshire Hathaway (BRK) put a portion of their ~$140 billion war chest of available cash to work over the weekend with the announced acquisition of Dominion Energy’s (D) gas transmission and storage business for a $9.7 billion (sale price includes assumed debt).

Assets sold under the agreement include the company's ownership interests in Dominion Energy Transmission, Questar Pipeline (including Overthrust and White River Hub), Carolina Gas Transmission, Iroquois Gas Transmission System (50% interest), legacy gathering and processing operations, farmout acreage, as well as a 25% operating interest in Cove Point LNG. The acquisition ends BRK’s nearly two-decade absence from large midstream M&A transactions, dating back to their purchases of Kern River Pipeline and Northern Natural Pipeline in 2002.

Everything We Know About Chesapeake and Their Midstream Contracts

July 2, 2020: Chesapeake Energy Corp. (CHK) filed its long-anticipated Chapter 11 bankruptcy on Sunday, June 28, giving additional insight into midstream contracts that could be rejected or renegotiated.

While details on some contracts like interstate natural gas pipelines are already public, the specifics on CHK’s G&P and liquids transport contracts have been more opaque. In addition to more robust contract details for less-heavily-regulated assets, the filing also disclosed insight into the initial contracts CHK is targeting to reject. After analyzing this information, East Daley believes CHK’s bankruptcy presents a greater risk to midstream counterparties offering above-market gas transportation rates and G&P agreements without wellhead interconnectivity. The specific breakdown of risks by asset type and midstream name are as follows.

Data Insights

Stop the Flow:

July 31, 2020: East Daley recently examined the impacts to Crestwood Equity Partners’ (CEQP) Bakken operations under a scenario in which the Dakota Access Pipeline (DAPL) is taken offline for further environmental review (see July 23 Snapshot, “DAPL Shutdown CEQP Analysis”).

East Daley expects oil, gas, and water gathering on CEQP’s Arrow G&P system would decline were DAPL forced to shut down through 3Q2021 due to the many producers connected to DAPL via Arrow. We would reduce our FY2021 forecast for oil gathering on Arrow by ~4 Mb/d (-4%), gas gathering by ~4 MMcf/d (-4%), and water gathering by ~3.4 Mb/d (-5%) were DAPL offline through 3Q2021. While we expect decreased throughput would hurt CEQP’s EBITDA next year, the impact would be more than offset by increased rail loadings on CEQP’s COLT Hub rail system, which we forecast would grow by ~67 Mb/d (+320%) in a DAPL shutdown scenario. CEQP normally accounts for ~20% of total barrels shipped out the Williston basin by rail, and we expect total rail volume would increase by over 300 Mb/d were DAPL offline. Increased railing would support CEQP’s EBITDA in case of a DAPL shutdown. East Daley models CEQP’s FY2021 EBITDA growing to $536 million in a shutdown scenario vs. $529 million were DAPL to remain online. Ticker: CEQP

Don’t Call it a Comeback:

July 31, 2020: ONEOK (OKE) in 2Q2020 reported its lowest quarterly earnings since 3Q2017.

Adj. EBITDA of $534 million was well below East Daley’s 2Q2020 estimate of $599 million. The variance was largely driven by underperformance in the G&P segment, which generated EBITDA of $89 million, or 52% lower Y-o-Y and the lowest since 3Q2015. OKE said it expects its “earnings run rate to be in line with our previous expectations” as volumes return to levels in early March. OKE’s prior expectations include a low-end Adj. EBITDA target of $2.6 billion for FY2020. With only $1.2 billion in the books for 1H2020, East Daley believes OKE may fall short of its $2.6 billion target based on our production outlook. Daily flow activity on OKE’s Bakken system shows G&P activity remains well below the average for the first two weeks of March, down 15%. East Daley uses the total Bakken flow sample as a proxy to forecast NGL volumes on OKE’s infrastructure. Aggregate Bakken G&P volume is 19% below early March, meaning OKE’s NGL receipts likely still lag March’s high-water mark. We model that total gas captured in the Bakken peaked in March at 2.7 Bcf/d with 3Q2020 and 4Q2020 to average 2.2 Bcf/d and 2.4 Bcf/d, respectively. Ticker: OKE

A Bear in the Bakken:

July 31, 2020: East Daley last week highlighted the risk to operators of gas G&P system in the Williston basin, including ONEOK (OKE), Targa (TRGP), and Crestwood Equity (CEQP), due to the bankruptcy of Bruin E&P (see “Bruin Bites the Dust” in July 24’s Data Insights).

On the oil side, Bruin’s bankruptcy also creates imbursement risk for Bakken crude gatherers. Based on available state data, East Daley believes CEQP, TRGP, and Summit Midstream (SMLP) are the crude gatherers most exposed to Bruin’s bankruptcy. East Daley estimates CEQP, TRGP, and SMLP gathered 46%, 43%, and 9%, respectively of Bruin’s 2019 crude production of ~46 Mb/d. The remaining 3% was split between Kinder Morgan (KMI), Plains (PAA), and MPLX. Bruin will continue to operate during the bankruptcy process. East Daley estimates Bruin’s oil production in 2Q2020 fell 34% Q-o-Q due to curtailments. Tickers: CEQP, TRGP, SMLP, KMI, MPLX , and PAA

Easy Come, Easy (Contan)go:

July 31, 2020: Volatile oil prices in 2Q2020 caused havoc for many energy companies, but also appear to have been a gift for opportunistic storage operators.

Both Enbridge (ENB) and Enterprise Products (EPD) this week reported 2Q2020 Adj. EBITDA above consensus and East Daley’s estimates due to blowout earnings in their marketing segments. ENB and EPD both attributed outperformance to marketing operations, taking advantage of the steep contango and record low crude oil prices during April. EPD has ~41 MMb of crude storage, and its 2Q2020 crude marketing activities generated $184 million in gross margin vs. $4 million modeled by East Daley and -$35 million in 2Q2019. WTI prices briefly went negative in April and ranged from -$40/bbl to $40/bbl in 2Q2020. Were EPD able to capture $30 out of the $80/bbl price range, it would have required using ~6 MMb of storage capacity, assuming all gains came from storing crude during a period of price contango. Other companies with similar crude storage and marketing capabilities include Plains All American (PAA) and Energy Transfer (ET), which have 79 MMb and 64 MMb of crude storage capacity, respectively. East Daley is within 1% of consensus estimates for both PAA and ET for 2Q2020, but we have attributed a very small portion of EBITDA to crude marketing for both companies ($25 million to PAA and $0.8 million to ET. PAA and ET both report next week, and if the companies were able to leverage their marketing and storage assets in the same manner, there could be significant upside to our estimates. Tickers: ENB, EPD, PAA, ET

Ethane is Heating Up:

July 31, 2020: Enterprise Product Partners (EPD) reported record fractionation volume of 1.2 MMb/d in 2Q2020 earnings while exports fell ~6% Q-o-Q.

Increased NGL volume may come as a surprise to those monitoring declining gas production from major basins in 2Q2020. Gas samples in the Bakken, Permian, Eagle Ford and DJ basins were down ~25%, ~8%, ~12%, and ~7%, respectively vs. 1Q2020. Frac volume likely grew for two reasons. EPD brought its Train 10 into service at Mont Belvieu in March and likely pulled Y-grade from storage to feed its newest frac capacity. Rising ethane prices are also behind increased fractionation. Ethane has outperformed natural gas, increasing the incentive to strip ethane from the gas stream. EPD revealed expanded Y-grade production in the Permian and Rockies, and management cited favorable spreads from CIG to Conway as an incentive for higher NGL recovery in the Rockies. EPD’s higher fractionation volumes are a positive read-through for other NGL processors like Targa Resources (TRGP), Energy Transfer (ET), and DCP Midstream (DCP), which also can benefit from higher ethane prices and positive frac spreads in the Permian and DJ basins. Tickers: EPD, TRGP, DCP, ET

Open Waters:

July 24, 2020: Buckeye Partners on July 16 began operations at its South Texas Gateway (STG) export terminal in Corpus Christi, loading an Aframax with 789 Mb of crude for export to Europe.

The new STG facility can export up to 800 Mb/d from two deepwater docks and has 8.6 MMb of storage capacity. Despite deepwater dock access, Buckeye requires reverse lightering to fully load a VLCC at STG, adding to handling costs. Buckeye has said it could add a third deepwater dock and expand storage to a total of 10 MMb if needed. East Daley’s Crude Hub Model expects no shortage of export dock capacity at Corpus Christi and forecasts only 30% utilization by YE2024. Still, there are plans to build a deepwater terminal in Corpus Christi capable of fully loading VLCCs, including Trafigura and Phillips 66’s (PSX) proposed Bluewater terminal off the coast of Corpus that could load VLCC and ULCC vessels in a day, something no U.S. port besides LOOP is capable of. Another competing deepwater project is the Sea Port Oil Terminal (SPOT) offshore Houston proposed by Enterprise (EPD) and Enbridge (ENB), which saw some setbacks in its review process in June. Tickers: EPD, ENB, PSX, PSXP, BPL

Bruin Bites the Dust:

July 24, 2020: Bruin E&P is among the latest E&Ps to file for Chapter 11 bankruptcy.

With private equity commitments from ArcLight Capital, Bruin is a pure-play Bakken producer with 534 producing wells in Dunn, Williams, and McKenzie counties. Bruin in 2019 produced ~46 Mb/d of oil and ~97 MMcf/d of gas in the Bakken. Gas production held steady in 1Q2020 while oil production fell 20% to ~37 Mb/d. Bruin’s reported oil production in May fell to its lowest level since 2012, averaging ~16 Mb/d, and gas output fell to ~39 MMcf/d, likely as a result of curtailments. Bruin maintained 1 active rig from 2019 to 1Q2020 and then stopped drilling in March. East Daley’s allocation model shows ONEOK (OKE), Targa Resources (TRGP), and Crestwood Equity (CEQP) as the largest counterparties for gas processing. Bruin’s bankruptcy filing creates risk for counterparties, but many also have diverse portfolios to dampen the potential impact. East Daley’s Rig Allocation Tool shows Bruin accounting for only ~3% of inlet gas volume on OKE’s Bakken system and 9% of volumes on TRGP’s Badlands and CEQP’s Bear Den systems. Tickers: OKE, TRGP, CEQP

A Noble Truth:

July 24, 2020: Noble Midstream (NBLX) is in the spotlight following Chevron’s (CVX) bid to acquire Noble Energy (NBL) for $5 billion, sending shares up to 20% higher this week.

NBLX provides crude, gas, and water G&P services for parent NBL and other E&Ps in the DJ and Permian basins. NBLX’s G&P system in the northeast of the DJ gathered 23 MMcf/d in 4Q2019, with 65% of volume gathered for NBL. NBLX only accounts for 5% of NBL’s DJ gas gathering (71% is handled on DCP’s DJ system) but has sizable acreage dedications. Other E&Ps on the NBLX system include Bonanza Creek (BCEI), Bison Oil & Gas, and Whiting (WLL). Rig activity the past 5 years has been dominated by NBL, with some recent drilling by Bison. East Daley’s Production Scenario Tools expects limited additions of 10-15 new wells annually on the NBLX system, with volume set to decline. NBLX is benefiting from CVX’s improved counterparty profile, and potentially comments by CEO Mike Wirth suggesting CVX interest in the DJ. The basin has its own challenges for operators, including ongoing adoption of Colorado Senate Bill 181 and looming anti-fracking ballot measures in 2022, which CVX will have to consider. See East Daley’s July 22 Snapshot “CVX-NBL Merger – Midstream Implications” to learn more. Tickers: CVX, NBL, NLBX, DCP, BCEI, WLL

Blend Baby Blend:

July 24, 2020: When gasoline prices crashed in March along with other energy commodities, the seasonal business of butane blending went out of favor as margins collapsed.

However, as gasoline prices recover, East Daley is seeing adequate margins to support blending once again. Magellan Midstream Partners’ (MMP) management confirmed this trend last month at the J.P. Morgan Energy, Power, & Renewables Conference. MMP hedged all spring 2020 butane blending activities going into 2020, but its fall blending activities in 4Q2020 were still unhedged. MMP in March expected no margin available on fall blending and reiterated on its 1Q2020 earnings’ call that it would only blend if it could lock in positive margins. East Daley’s model suggests margins (RBOB – Butane) of $0.30-0.40/gal are required to cover logistics and storage costs for the two products. Margins were rangebound between $0.20/gal and ~$0.40/gal in of March and April but have since recovered to near $0.81/gal, along with RBOB gasoline prices (+211% off lows) and Mont Belvieu NC4 butane prices (+200% off lows). East Daley expects companies like MMP and NuStar (NS) that generate earnings from blending have begun locking in margins for the fall 2020 blending season, thus providing upside to earnings in 2H2020. Tickers: MMP, NS

Viper Pit:

July 24, 2020: Preliminary 2Q2020 updates confirm that many producers are restoring oil and gas volumes curtailed since March.

Viper Energy (VNOM), a mineral rights holder and a subsidiary of Diamondback Energy (FANG), reported on July 14 that “nearly all” curtailed production on its Permian acreage had been restored. Of FANG’s 1Q2020 completions, 85% were on VNOM acreage. East Daley models EnLink (ENLC) as the top gatherer of FANG’s produced gas in the Midland basin, while private operators Vaquero and Brazos are the top gas processors for FANG in the Delaware. FANG was the top producer in 1Q2020 on all three G&P systems, which all overlap with VNOM acreage leased by FANG. This suggests that much of FANG’s 1Q2020 curtailment activity, and subsequent recovery, took place there. Between June 1 and June 6, ENLC, Vaquero, and Brazos samples increased by 40%, 25%, and 54%, respectively. FANG is the only common producer on all three G&P systems. With its production restored, VNOM reports that FANG recently brought three completion crews back to work and is expected to focus 2H2020 activity on VNOM acreage, providing potential upside for midstream companies serving FANG. Tickers: ENLC, FANG, VNOM

A Noble Effort:

July 17, 2020: Midstream operators in the Permian and DJ basins should see a near-term bump from Noble Energy’s (NBL) plan to restore shut-in production this month.

In an operational update, NBL on July 9 said it curtailed 32 Mboe/d of its onshore production in 2Q2020, including 11 Mb/d of shut-in crude, and planned to restore most curtailed output by the end of July. The curtailment represents 10% of 113 Mb/d of U.S. oil production NBL reported in 2Q2020. East Daley’s Production Scenario Tools tracks most NBL rigs in 1Q2020 as active on Energy Transfer’s (ET) Delaware system and DCP Midstream’s (DCP) DJ system, comprising 1.7 of NBL’s 2.0 rigs in the Delaware and 2.0 of its 2.6 rigs in the DJ. In the DJ, Noble has drilled on Western Midstream’s (WES) G&P system and Williams’ (WMB) Discovery system. East Daley’s July Production Scenario Tools estimates curtailments will end in August 2020 in both basins, with crude production in 2020 projected to decline 7% and 15% Y-o-Y in the Delaware and DJ basins, respectively. This drop can be attributed to shut-in production and a significant decline in drilling. In June 2020, NBL only had 1 rig operating in the DJ basin vs. an average 1.4 rigs in the DJ in 2019 and 3.7 rigs in the Delaware last year. Lower rig activity is expected in these two basins for the rest of the year, with 86 rigs projected in the Delaware at YE2020 (vs. a high of 231 rigs in February 2020) and 9 rigs in the DJ at YE2020 (vs. 22 rigs in February). Tickers: DCP, ET, NBL, WES, WMB

Alpine Highs:

July 17, 2020: Altus Midstream (ALTM) is seeing impacts from Apache Corp’s (APA) marketing efforts on its Alpine High system. In East Daley’s 2Q2020 Pre-Call Board Report, G&P volume on Alpine High is projected to decline 28% Q-o-Q from 572 MMcf/d to ~410 MMcf/d in 2Q2020.

Interstate receipts indicate that APA has been curtailing production in response to low commodity prices. A primary factor influencing system activity appears to be the spread between Permian and Henry Hub gas prices. During its 1Q2020 earnings call, ALTM management stated they were working closely with APA to manage throughput on a “daily” basis in response to commodity prices, and as a result, anticipated a “lumpy G&P profile” during the year. Pricing data and management commentary affirm East Daley’s earlier hypothesis that APA is marketing third-party gas when Permian gas is heavily discounted and daily spreads between Permian and Henry Hub prices are wide. When spreads fall below ~$0.70/MMBtu, it appears APA has restored curtailed production on Alpine High rather than buying gas on the market. The only deviation in this trend occurred in late May, when Kinder Morgan (KMI) shut down the receipt point servicing Alpine High for maintenance. ALTM’s G&P segment EBITDA is projected to decline 10% Q-o-Q, to $41 Million vs. $46 million due to volume curtailments. The decline Q-o-Q is slightly offset by increased contributions from ALTM’s equity investments. APA marketing likely will continue to be heavily influenced by Permian prices and spreads. Tickers: ALTM, APA, KMI

From All Sides:

July 17, 2020: EnLink Midstream (ENLC) has seen variability in its overall segment profit for Oklahoma.

During 1Q2020, margins declined by ~7% Q-o-Q which is likely attributed to a decrease in NGL prices. OK is one of the NGL supply basins for ENLC’s fractionation assets in Louisiana. In addition to declining G&P revenues, ENLC is also expected to see a decline in the quantity of NGL equity volume supplied by its Chisholm processing plant in OK, and due to a declining production profile in the Anadarko basin is estimated to have less NGLs to market. Overall, ENLC likely is impacted by both reduced G&P volumes in its OK segment and reduced revenues from NGLs due to poor pricing and declining production on its Chisholm footprint. Estimated marketing volumes are derived by dividing reported sales by the average NGL price for the period. The ratio changed slightly in 2Q2019 when the Thunderbird processing plant became operational. ENLC does not receive NGL equity volumes from Thunderbird, which is why we see the slight shift in the ratio during 2Q2019. It is no secret that rig attrition has impacted volumes in 2019 and 1Q2020, but the combination of both reduced volume forecasts and reduced marketing revenues will impact the segment’s profitability going forward. Ticker: ENLC

Opening the Taps:

July 17, 2020: Midstream counterparties of Continental Resources (CLR) are benefiting from the apparent return of its curtailed production in the Williston basin.

On June 18, 2020, CLR said they expected total company production to increase 53% from June to July, providing midpoint guidance of 155 Mboe/d in June and 238 Mboe/d in July. East Daley models that ONEOK (OKE) and Kinder Morgan (KMI) gather 34% and 12%, respectively, of CLR’s Bakken gas production on their core G&P systems in the play. So far in July, OKE’s Bakken pipe sample has increased 15% vs. the June average and KMI’s Bakken sample has jumped by 57%. In addition to CLR, Bakken E&P ConocoPhillips (COP) has also announced abatements to its well curtailments. Both systems saw a significant drop in gas throughput in 2Q2020, with OKE’s gas sample down 24% and KMI’s gas sample down 36% Q-o-Q. East Daley’s Company Blueprint Models forecasts throughput will continue recovering in July on the KMI and OKE system, but will face natural declines thereafter due to limited completion activity. Unless E&Ps announce changes in the scheduled completion activity for 2H2020, East Daley does not forecast any growth from new well connects on OKE’s or KMI’s core Bakken systems for the rest of 2020. Tickers: CLR, COP, KMI, OKE

Waha Points the Way:

July 10, 2020: As WTI prices stabilize near $40/bbl, Permian operators are restoring much of the estimated 850 Mb/d of crude shut-in since May, a reality being captured in weakening Waha spot gas prices.

From June 24 to July 5, East Daley’s Permian pipeline sample surged 15%, or 680 MMcf/d, as operators returned curtailed wells across the basin. The rush of restored gas production caused the Waha price discount to Henry Hub to widen by 78%, from $0.13/MMBtu to $0.60/MMBtu, over the same period. Conversely, Waha spreads tightened considerably from April 27 to May 1, trading from $1.09/MMBtu to $0.19/MMBtu behind Henry Hub, when our Permian gas sample dropped 12%, or 605 MMcf/d. East Daley’s Permian pipeline sample aggregates real-time flow data from individual plants on 40 G&P systems across the Midland and Delaware basins. Peak daily gas flows so far in July have reached 95% of March highs, indicating most curtailed production appears to have been restored. The correlation between Waha basis and sample volumes presents opportunities for investors informed with real-time data to act before the market to evaluate the impacts of well performance on Permian gas volumes.

Dabbling into DAPL:

July 10, 2020: The outlook for the Dakota Access Pipeline (DAPL) remains in legal limbo following a federal judge’s order to shut down the pipe by August 6, 2020 due to an inadequate environmental impact statement.

DAPL operator Energy Transfer (ET) is pressing the U.S. District Court judge to freeze the order until an appellate court can review the case. DAPL is otherwise operating normally for now. East Daley’s recent Snapshot, “DAPL Ruling – Catalyst for Pipeline Constraints” analyzes how the economics of rail shipping would clear Bakken oil prices were DAPL to ultimately shut down. East Daley estimates that transitioning from shipping on DAPL to shipping by rail would reduce netbacks for Bakken producers by ~$3/bbl. Lower realized oil prices would also ripple through basin activity. Were DAPL closed until 4Q2021 to provide time for the U.S. Army Corps of Engineers to update its environmental review, East Daley estimates Bakken oil and gas production would decline up to 46 Mb/d and 82 MMcf/d, respectively vs. our July Production Scenario Tool. After 4Q2021, East Daley would expect DAPL to return to standard operations and rig counts to recover, narrowing the gap in forecasted production. While DAPL shutting down has significant implications for earnings generated by Bakken egress pipelines, East Daley believes the overall impact to basin production would not be as substantial.Ticker: ET

There and Back Again:

July 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

Keep Calm and Frac On:

July 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

Lower for Longer:

July 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

And Then There was One:

July 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