Resources for 3rd Quarter 2020

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August 2020


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

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


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