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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.
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
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.
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
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.
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
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.
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
June 25, 2020: This week, we continue our retrospective on East Daley’s 2020 Dirty Little Secrets (DLS 2020) publication to evaluate how our view on risks and opportunities in commodity markets and midstream equities has changed since January. Last week, we examined the rebound in ethane markets, where we see a tighter balances and higher prices ahead (see our June 18 Snapshot: “Ethane – The Recovery isn’t Plastic”). This week, we review midstream equity performance, with a focus on legacy asset cash flow decline risk – also known as the East Daley Treadmill Incline Intensity (TII) score.
June 26, 2020: East Daley has observed growing crude egress capacity from the Denver-Julesburg basin following recent drilling cuts and well shut-ins. The DJ has experienced a 76% decline in rig activity YTD, while residue gas samples from the basin’s processing plants are down 11% so far in June vs. the January 2020 average. The DJ has several underutilized pipes that carry crude to Cushing, of which the Grand Mesa Pipeline appears most at risk following a June 14, 2020 chapter 11 bankruptcy filing by Extraction Oil & Gas (XOG). Grand Mesa, owned by NGL Energy Partners (NGL), has a 61.8 Mb/d MVC contract with XOG at a $4.31/bbl tariff, which equates to ~$97 million of annual revenue. XOG has filed to reject the rates as above market, and forecasts its volumes on Grand Mesa to be ~30 Mb/d for the remainder of 2020, down from their initial 2020 guidance of ~42 Mb/d. The current spot rate in the basin is ~$2.00/bbl, and if XOG wins the hearing scheduled for July 7, 2020 and renegotiates with Grand Mesa, NGL could see a revenue reduction of ~$75 million from reduced rates and volumes. FERC tariff filings show that other shippers on Grand Mesa pay between $5.02 and $5.67/bbl, so the pipe could face more contract breaches in the current environment. In addition to re-negotiated rates, Grand Mesa faces competition from other underutilized pipes, including White Cliffs and Saddlehorn. Both currently have spare capacity that could grow this year due to legacy contract roll-offs, plus a 100 Mb/d expansion on Saddlehorn due to start by YE2020. East Daley is forecasting 2020 volumes on Grand Mesa to average 94 Mb/d, which we expect to decline to 60 Mb/d in 2021. Ticker: NGL
June 10, 2020: Of all energy commodities, oil has been most impacted by new market conditions owing to pandemic-related changes to consumer behavior. Reduced transportation amid shut-in economic conditions slashed global oil demand by 29 MMb/d in April 2020, according to the International Energy Agency. Discord in the OPEC+ coalition has only heightened market uncertainty and price volatility. When DLS 2020 was published, East Daley predicted U.S. oil production would grow by 840 Mb/d in 2020 to 13 MMb/d amid a $60/bbl WTI price outlook and robust industry appetite for new midstream projects.
June 26, 2020:The Bison Pipeline is flowing gas once again after several years of inactivity as shippers take advantage of the downturn in Bakken production. Bison, owned by TC Pipelines (TCP), began flowing gas from the Powder River basin in early May 2020, the first activity reported since 2016. The uptick in throughput on Bison is mainly due to widespread oil well shut-ins in the Bakken, which has also reduced gas production and opened up some space on Northern Border Pipeline (TCP, OKE). Previously, the rise in Bakken and WCSB production had crowded out all flows on Northern Border from Bison. While immediate cash flows for the pipeline should remain largely unchanged due to MVC contracts that extend into 2021, there is potential upside in the future. Current 3year forward curve analysis shows netbacks to Cheyenne Hub (via WIC) at -$0.48/Mcf for PRB gas. This implies Bison could charge up to $0.40/Mcf and remain competitive by delivering gas on Northern Border into Ventura. However, this analysis assumes maximum tariff ($0.12/Mcf) capacity is available on Northern Border in the future, an assumption which may not hold once Bakken shut-ins come back online. A bullish scenario that assumes $0.40/Mcf rates at full capacity would net Bison ~$60 million a year in revenue, a huge upside from our previous forecast of zero revenue post-2021. Tickers: TCP, OKE
June 5, 2020: So much has changed since East Daley released DLS 2020, as two major “black swan” events roiled energy markets within a few short months. The combined impacts of prolonged OPEC+ discord and pandemic-related health concerns have sharply shifted prices for oil and natural gas. As Figure 1 shows, short- and long-term WTI futures have been hit hard by lower future demand expectations and lingering pessimism over the OPEC+ group’s ability to reign in supply. Oil has rebounded off the lows it hit in April 2020, but WTI futures still remain ~45% lower for the balance of 2020 and ~35% lower in 2021 compared to trading levels in January 2020. By contrast, the Henry Hub forward curve has been much more resilient. While near-term gas prices are lower, prices for 2021 delivery have risen nearly 30% since January 2020, and average 2022 Henry Hub futures are ~7% higher since the start of the year.
June 26, 2020: East Daley has previously highlighted risks to Ygrade supply and the overbuild of NGL fractionation capacity at Mont Belvieu in the recent downturn (see our June 12, 2020 Data Insights, “NGLs are Bigger in Texas”). Securing supply for fractionation assets could be a challenge for firms in 2020, with volume obtainment to be determined by midstream relationships, contract terms, and marketing operations. EnLink Midstream (ENLC) predominately operates fractionators in Louisiana and transports Y-grade to these assets via the Cajun Sibon Pipeline. For 2019, one-half of the volumes on Cajun Sibon were supplied from purchases at Mont Belvieu with the remainder supplied as NGL equity volumes from Midland processing plants and the Chisholm plant in Oklahoma. With recent shut-ins, deferred production, and rig attrition in the Permian and Anadarko basins, ENLC’s NGL equity volumes face declines in 2020. There is further risk to volumes as marketing purchases at Mont Belvieu could be hindered by the fractionation overbuild. The amount of impacted marketing volumes will largely be determined by the terms of marketing contacts. If the majority are long-term supply contracts, most volumes should be relatively safe from competitive pressures. However, if terms are shorter in duration, there could be additional downside for ENLC’s NGL business in 2020. The figure to the right outlines the percentage drop for the remainder of 2020 marketing volumes from volumes obtained by marketing operations in the first quarter. The sudden spike in 1Q2021 is primarily driven by the close of the Devon(DVN)/BKV transaction in North Texas, in which ENLC will obtain more NGL equity volumes in exchange for lower processing fees. Ticker: ENLC
May 29, 2020: Oil and gas markets have been unusually volatile in 2020 due to the demand-side shock caused by coronavirus. Midstream companies have navigated unprecedented conditions by frequently adjusting their operation plans to align with lower commodity prices and revised producer guidance. Amid the dislocation, some midstream operators have shifted resources to take advantage of unique opportunities while attempting to avoid emerging obstacles. The earnings outlook for these companies has likewise shifted, sometimes rapidly.
June 26, 2020: Market chatter is focused on when shut-in oil wells in the Permian may restart after a rebound in WTI prices near $40/bbl. East Daley’s Permian gas flow sample suggests that a trough in Permian production likely occurred in mid-May 2020, but that signs of a recovery are otherwise preliminary. Our Permian pipeline sample so far is up 2%, or 97 MMcf/d in June from the May 2020 average. The Permian sample declined by 16%, or 850 MMcf/d, between April 1 and May 8, 2020, suggesting widespread curtailments. Pipeline sample data from East Daley’s Company Dashboards show the asymmetric effects of shut-ins on Permian G&P systems, with some systems insulated from curtailments while others see severe impacts, depending on the respective strategies of system counterparties. Statements by executives at EOG (EOG), ConocoPhillips (COP), and Parsley (PE) suggest that producers are at least considering restarts. East Daley is also tracking daily Waha price spreads for signs of recovery. Waha gas prices have been historically weak since 2018 due to supply growth and takeaway constraints, but prices notably strengthened in May 2020 vs. Henry Hub as curtailments cut regional gas supply. However, the price discount for Waha gas has been growing once again, from $(0.08)/Mcf to $(0.26)/Mcf vs. Henry Hub from June 3 to June 8, 2020, suggesting more supply may be hitting the market as oil prices continue to rally. Tickers: EOG, PE
May 20, 2020: In a matter of months, the COVID-19 pandemic has upended oil markets and forced midstream investors to navigate volatility without historical precedent. As the main driver of U.S. crude production, the Permian basin lies at the center of this ever-changing landscape. Severe attrition in liquids demand paired with dramatic OPEC+ agreements and concerns over storage availability have contributed to precipitous declines in oil prices and triggered radical market-driven production curtailments from exploration & production companies (E&Ps).
June 19, 2020: On June 8, 2020 market reports indicated Chesapeake (CHK) was preparing to file for bankruptcy and hand control to lenders. This comes as no surprise after the company issued a going concern in November 2019. With bankruptcy, midstream companies with CHK counterparty exposure will be negatively affected. However, due to impacts of suppressed oil prices and demand, some systems like Crestwood’s (CEQP) Bucking Horse in the Powder River basin may have already seen most of the downside. In 2019, CHK averaged 5 rigs on CEQP’s system, which dropped to 1 rig in 2020. East Daley’s rig outlook for CEQP’s system calls for 1 rig through 2021, increasing to ~2 rigs by 2024. With this forecast, even before CHK indicated they would file for bankruptcy, East Daley had little incremental growth on the system. Although this system accounts for ~10% of CEQP’s EBITDA, most of that cash flow is from the 300+ existing CHK wells feeding the system. Based on other bankruptcies, East Daley assumes gas will continue to flow through the system as CHK goes through bankruptcy. CEQP has also indicated that their contract with CHK is new with good language that would make it very hard for them to reject during bankruptcy. Tickers: CEQP, CHK
May 13, 2020: Between March 17 and April 9, just before WTI futures yielded a historic negative settlement, Houston crude prices traded at a discount to WTI for the first time ever (Figure 1). Amid the frenzy of tumbling crude prices, regional spreads flipped to incentivize storage at Cushing over exports from the Gulf. As a result, northbound Permian pipes Basin, Centurion, and Sunrise benefitted from a temporary uplift in throughput. However, as East Daley noted in the April 1 Webinar: A Crude Reality – Flows and Spreads in a Volatile Market, if spreads continued to favor Cushing as a destination over Houston or Corpus, Cushing storage would fill to the brim before June. Spreads began to normalize as the May NYMEX WTI contract rolled and the June contract traded as the new front month, indicating the market was coming off its storage craze and instead looking for a more viable solution to alleviate the supply glut. Demand optionality makes the Gulf Coast a logical solution, but which port is set to come out ahead – Corpus or Houston? East Daley’s newly enhanced Crude Hub Model indicates the short-term winner thus far has been Corpus, but we see Corpus’ reign coming to an end as SPR leases and a third wave of Permian pipes crown Houston king for the foreseeable future.
June 19, 2020: Mont Belvieu is seeing robust expansion after NGL fractionators in 2018-2019 ran close to, and at times slightly above, nameplate capacity in c3+ towers. Fractionation capacity is expanding from projects sponsored by Targa Resources (TRGP), Energy Transfer (ET), Enterprise (EPD), ONEOK (OKE), and DCP Midstream (DCP). TRGP brought its Train 6 online in 2Q2019, adding 100 Mb/d of fractionation capacity, followed by two 110 Mb/d expansions in 1Q2020 and 3Q2020. ET and EPD brought new 150 Mb/d trains online in 1Q2020. Both companies are building additional trains, with EPD’s latest project expected in service by 3Q2020. While ET and EPD have reported their fractionators are fully contracted, this is not the case for all operators at Mount Belvieu. New NGL fractionation capacity increases re-contracting risk for spare fractionation volumes, especially in the current low-price environment where NGL volumes are likely to be lower than previously projected. East Daley believes the outlook for lower Y-grade production poses particular risk to TRGP, given that its fractionators are not fully contracted, and its legacy trains have contract roll-off risk. In 2Q2011 and 2Q2013, TRGP entered into 10-year fee-based contracts on expansions of 78 Mb/d and 100 MB/d, which we estimate will roll off in 2021 and 2023, respectively. These contract roll-offs pose circumstantial risk that is compounded by the lower Y-grade supply outlook comparing East Daley’s NGL Hub forecast in 4Q2019 vs. 1Q2020. Tickers: TRGP, ET, EPD, OKE, DCP
April 29, 2020: Over the last few years, many midstream companies have enjoyed the rush of retail therapy as blown out commodity price spreads have incentivized capex for new growth projects. In 2019 alone, the midstream names under East Daley’s coverage spent a collective ~$41 billion in growth capex, with nearly $19 billion allocated towards pipeline projects (Figure 1). As is usually the case with the infrastructure life cycle (Figure 2), more capacity means tighter spreads and more production until once again spreads blow out to trigger another round of infrastructure capital. But not this time.
June 19, 2020: East Daley believes the worst of Bakken shut-ins is already in the rear view, which would come as welcome news to the basin’s operators. Our Bakken gas sample has grown 8% since hitting a 2020 low of 1,284 MMcf/d in early May vs. 1,394 MMcf/d on June 10, 2020. The rebound has been particularly strong on the 150 MMcf/d Arrow system owned by Crestwood Equity Partners (CEQP), which includes 150 MMcf/d of processing at the Bear Den gas plant. The system averaged residue gas output of ~115 MMcf/d in March 2020 before widespread shut-ins hit activity. Output fell 61% to a trough of 45 MMcf/d from May 9–11, 2020, but has since recovered significantly to 75 MMcf/d on June 10, 2020, or 67% growth from early May. East Daley expects this rebound in the gas sample is coming from abated curtailments rather than new wells, as many completions crews in the basin have been dropped. WPX Energy (WPX) is one of the main producers on CEQP’s Bear Den, averaging ~2 rigs in May 2020 on the system. WPX disclosed plans in 1Q2020 earnings to exit 2020 with 1 rig in the Bakken, and to drop all completions crews as they build up 1 to 2 quarters of DUC well inventory. East Daley expects throughput on Bear Den to continue its recovery in the short and medium term as curtailed wells are brought back online. This trend will be challenged by natural declines over the long term until operators on the system return frac crews and work through the DUCs they are currently drilling. Tickers: CEQP, WPX
April 23, 2020: Twenty-three countries have recently agreed to withhold 9.7 MMb/d of crude oil from the market. However, some estimates peg the crude demand destruction from travel restrictions and work stoppages at 30 MMb/d and price has responded accordingly (refer to Figure 1). A significantly lower crude forward curve has had severe ramifications for U.S. producers in oil-centric basins like the Permian, Bakken, and DJ. East Daley has monitored updated producer guidance and estimates that the top 20 producers have cut in excess of $35 billion from 2020 capex cuts. Taking producer-revised growth capital budgets and rig count reductions, East Daley estimates 1 MMb of U.S. production will be taken off the table in 2020, with nearly 3 MMb/d of supply reduction in 2021 vs. our 4Q2019 U.S. production forecast.
June 5, 2020: A chronic gas processing shortage in the Bakken appears to be abating. The Bakken has been among the hardest-hit U.S. oil plays due to infrastructure constraints and depressed prices at Clearbrook. Production curtailments announced by Continental (CLR), Conoco (COP), and EOG Resources (EOG) follow recently added processing capacity, creating rare flexibility in processing options for Bakken producers. ONEOK (OKE), the largest Bakken G&P system operator, brought the Demicks Lake plant online in 4Q2019, boosting its system capacity by 200 MMcf/d to 1.26 Bcf/d. Gas inlet volumes on the OKE system averaged ~1.1 Bcf/d in 1Q2020, or ~47% of total basin inlet volumes, but daily residue gas samples tracked by East Daley show about a 32% reduction in OKE system activity in May 2020. CLR and Whiting (WILL) accounted for ~300 MMcf/d (~27%) of inlet volume on OKE’s Bakken system in 4Q2019. CLR said it has curtailed 70% of its total U.S. oil production, which East Daley believes is predominantly based in the Bakken, while WILL entered Chapter 11. Rig activity is also down on the OKE system, from an average 25 rigs in 1Q2020 to 5 active rigs in May 2020. North Dakota regulators said 13% of total gas production in the Bakken was flared in March 2020, of which 9% was due to infrastructure constraints, and East Daley expects flaring levels in the Bakken to fall significantly going forward as shut-in wells alleviate processing constraints. As a result, some new gas processing expected in the Bakken will be unnecessary in the short term until oil production and investment rebounds, an unusual break from historical basin trends. Tickers: OKE, CLR, WLL
April 24, 2020: The recent extreme price swings in crude oil markets has made production forecasting an arduous and almost daily task. Understanding the varying signals coming from the varying factors such as rig counts, well counts, initial production (IP) rates, and price curves provides ample opportunity for interpretation without adding in the additional complexity of producer capex, rig count, and volume guidance assumptions. In our webinar hosted on March 25 called Catching Snipes: Producer Guidance in a Volatile Market East Daley analysts laid out exactly what they were seeing using tools, data, and analysis provided in the Production Scenario Tools for each basin as well as the Production and Constraint Forecast Report. A replay of the webinar is available in the link above, but we also wanted to outline the analysis in a Snapshot to highlight our perspectives on production, incorporating important perspectives such as CAPEX revisions, production guidance, and other notes.
June 5, 2020: Oil markets are rebounding off April lows to the $30/bbl range in part because some of the worst disruptions feared from coronavirus did not, in fact, come to pass. Chief among these fears was overfill at Cushing as inventories surged 67% in March-April 2020. Yet in a stark reversal, Cushing inventories fell ~21% in May 2020. Market balance was restored as depressed basin-level prices prompted shut-ins and cut oversupply. Global demand has slowly returned as businesses and borders reopen. Moreover, the U.S. export trade re-opened as Houston prices returned to a premium over WTI, incentivizing a supply shift from the Midcontinent. As we approach summer, East Daley expects the demand for gasoline to continue to rise and, based on our Crude Hub model, we forecast crude storage at Cushing to return to pre-COVID levels by the end of 3Q2020. The WTI forward curve suggests oil prices will continue to slowly rise and with that we expect storage volumes to remain relatively flat around 30 Mb.
April 9, 2020: E&Ps have responded to persistent weakness in commodity prices by slashing spending budgets and scaling back development plans. An overall reduction in rig count and lower production will contribute to fierce competition between midstream companies for future volumes. These dynamics give producers leverage while amplifying rate risk for midstream companies that are charging above-market fees for their G&P services. In this Snapshot, we apply our blended rate methodology across the Eagle Ford and Permian and dive into counterparty risk factors for Energy Transfer (ET), Williams (WMB), and Western Gas (WES). We also explore counterparty risk from a bankruptcy perspective for all three companies.
June 5, 2020: Activity on DCP Midstream’s (DCP) Delaware G&P system has been more resilient than broader trends in the Permian, an important consideration for investors given that, according to East Daley’s Blueprint Models, the Delaware system accounts for 67% of DCP’s total Permian throughput. East Daley’s pipeline sample for the DCP Delaware system has declined only 10% from March 22 – May 31, 2020 vs. a 19% drop in our aggregate Permian sample. East Daley’s coverage of pipeline data from our Company Dashboards suggests that DCP’s Delaware system has avoided widespread well shut-ins evident on other Permian G&P systems. Rather, the DCP pipeline sample and counterparty mix indicate a natural decline profile from existing wells best explains the recent performance. DCP is the primary gatherer for Devon Energy’s (DVN) Delaware operations, and DVN gas volumes comprise ~30% of the system’s gathered total. Devon’s company-wide May curtailment guidance of 10 Mb/d is likely weighted toward its Powder River and Anadarko operations, sparing DCP’s system in the Delaware. A diverse mix of counterparties insulates DCP from wide-scale shut-ins from a few prominent customers. East Daley’s Blueprint Models estimate the Delaware system received 1Q2020 inlet volumes of 685 MMcf/d, or 67% of modeled throughput on DCP’s Permian systems. If operator activity remains subdued and DCP system volumes continue their current decline rate of 11%, East Daley models that DCP’s Permian gross margin will fall 19% by 3Q2020 vs our 1Q2020 model (see chart). In an upside scenario in which G&P system growth returns to 5% as exhibited in February 2020, we forecast DCP’s Permian gross margin would increase 11% by 3Q2020. Tickers: DCP, DVN
April 1, 2020: The recent extreme price swings in crude oil markets has made production forecasting an arduous and almost daily task. Understanding the varying signals coming from the varying factors such as rig counts, well counts, initial production (IP) rates, and price curves provides ample opportunity for interpretation without adding in the additional complexity of producer capex, rig count, and volume guidance assumptions. In our webinar hosted on March 25 called Catching Snipes: Producer Guidance in a Volatile Market East Daley analysts laid out exactly what they were seeing using tools, data, and analysis provided in the Production Scenario Tools for each basin as well as the Production and Constraint Forecast Report. A replay of the webinar is available in the link above, but we also wanted to outline the analysis in a Snapshot to highlight our perspectives on production, incorporating important perspectives such as CAPEX revisions, production guidance, and other notes.
June 5, 2020: HollyFrontier (HFC) this week announced plans to convert its Cheyenne refinery into a 6 Mb/d renewable diesel plant by 1Q2022, removing 52 Mb/d of crude refining demand from the Guernsey market. The HFC announcement follows a notable supply drop in the Guernsey market due to a combination of shut-in production and declining rig counts in the Bakken and local Powder River basins. This has a created a much tighter crude spread outlook from Guernsey to Cushing, which mitigates the Cheyenne refinery’s supply cost advantage over larger Cushing refineries. While the Cheyenne Pipeline will no longer be able to supply the Cheyenne refinery, Cheyenne pipeline can retain value by shifting its deliveries to the DJ Basin’s Saddlehorn pipeline via Saddlehorn’s joint tariff with Cowboy pipeline. Other potential benefactors include Tallgrass’s Pony Express pipeline, which provides available crude egress out of Guernsey, and Magellan’s refined product pipeline system by filling the shortfall of supply in Cheyenne Refinery’s demand markets. Tickers: HEP, PAA, MMP, NBLX
March 26, 2020:The equity value of EnLink (Ticker: ENLC) has plummeted in the last year along with many other midstream names as investors sour on the entire sector. As East Daley has outlined extensively in our coverage of the company, EnLink has challenges in the form of contract roll-off expectations, declining rig counts in the Anadarko (amongst other places), and throughput declines. While they have several offsetting growth areas, our models for the last year have indicated they were not expected to grow enough to offset the loss of cash flow from the declining assets. However, it was not until the beginning of March when oil prices cratered to down to the mid-$30s and then again to the mid-$20s that the value of the debt began to really plummet. This begs the question, if EnLink is put under a stress test by building up the cash flow, well-by-well, contract-by-contract, asset-by-asset, will the company bend, or will it break? At what point do debt investors have more to fear than fear itself?
May 29, 2020: The new industry calculus for liquids vs. dry gas exposure appears to be playing out in the Northeast, where recent rig attrition has been more severe in the Southwest Marcellus-Utica region vs. Northeast Pennsylvania. Of the 10 rigs dropped in the Northeast since January 2020, 7 rigs (70%) had been drilling in the liquids-heavy SW Marcellus-Utica, where activity fell 22% from 31 to 24 rigs in January-May 2020. In contrast, rig activity in dry NE Pennsylvania fell only 2.5 rigs over this same period from 15 to 12.5 active rigs, a 16% decline. While gas prices are unfavorable, with Henry Hub averaging $1.70/MMbtu so far in May 2020, NGL prices have fared worse. A weighted NGL barrel from Mont Belvieu averaged $10.19/bbl in April 2020, about 50% lower than $19.80/bbl in January 2020. Northeast basin producers would see even lower NGL netbacks due to shipping costs. EQM Midstream (EQM) and Montage Resources (MR) have reported system curtailments in the SW Marcellus-Utica, with MR identifying Utica condensate pricing as a particular problem. Some SW Marcellus-Utica assets will fare better than others If NGL economics remain poor. MPLX Corp. (MPLX) primarily conducts SW Marcellus-Utica processing and may see pressure from a shift away from liquids. Other G&P systems like EQM’s Strikeforce and Poseidon gather significant dry volumes in addition to liquids-rich gas, so may see offsetting impacts were dry gas drilling to return in favor. Tickers: EQM, MPLX, MR
March 19, 2020:The S&P 500 is down more than 30% from its February high and the broad-based energy ETF, XLE is down some 55% over the same period. While one month returns across East Daley’s coverage has performed slightly better (-45% to -6%; simple average -32%), most midstream equities have shed values in excess of 75% over the last year. In the commodity markets, front-month crude oil futures are down another 40% since East Daley’s downside March 2 Snapshot: Market Fears Go Viral – The Varying Degrees of Midstream Immunity. This drastic shift in prices makes our previous downside modeling now seem like a bullish scenario.
May 29, 2020: The midstream sector, and the DJ Basin is no exception. East Daley’s new Company Dashboard product serves as a channel check for midstream companies with G&P assets in oil-focused basins. In the DJ basin, DCP noted “very strong” inlet volumes in its 1Q2020 earnings call, with flat volumes expected from 2019 to 2020. While East Daley’s DJ interstate residue sample indicates a 6% decline across the basin from 1Q2020 to 2Q2020, DCP’s residue sample is indeed flat at about 1.1 Bcf/d Q-o-Q. However, other sample data suggest DCP’s peers may not be so fortunate. Of the public companies we cover, SMLP’s sample volumes are down 30% (vs. 18% in East Daley’s model) and WES’s sample volumes are down 11% (vs. 12% in our model) so far Q-o-Q. The private processing plants are also taking a hit, with sample volumes suggesting Sterling, Outrigger II, Cureton, and Rimrock plant inlet volumes are down 40%, 39%, 13%, and 11%, respectively.Tickers: DCP, SMLP, WES
March 13, 2020: While the entire Energy sector has been butchered by coronavirus concerns and the OPEC price war, WES has fared even worse with the equity down a whopping 78% YTD. Likely contributing to the downside is the tailspin of anchor customer and ~50% owner OXY, which now has massive leverage issues after their ill-timed acquisition of Anadarko Petroleum (APC). With the ~10% market selloff on Thursday, WES’s equity price reached a new low of $5.05/share and is now among one of the worst preforming midstream companies (Figure 1). However, our modeling of a $30 WTI stress test through 2022 yields a far from disastrous outcome for WES. While the solvency of OXY under a $30 WTI scenario is a concern, WES is fairly resilient under scenarios where OXY survives due to their substantial minimum volume commitments and cost-of-service contracts.
May 29, 2020: Rig activity in the Power River basin has fallen to two active rigs as lower oil prices impact activity in the northern Rockies. Prior to the downturn, the Powder River basin averaged 23 rigs in 2019 and 18 rigs during January-February 2020 but drilling since has sharply declined. Activity fell to a low as one rig earlier in May, and only two rigs were operating as of last week: one by EOG Resources (EOG) and one by privately held Peak Powder River Resources. Both rigs are operating in southern Campbell County, WY, and both are modeled by East Daley to deliver on Meritage Midstream’s G&P system. Interstate gas meter flow samples can serve as a proxy for crude production and processing plant inlets, and these volumes have fallen sharply since March 2020 as apparent shut-ins curtail production. Total Power River gas plant inlets averaged 458 MMcf/d in 1Q202020, implying total plant inlets of ~378 MMcf/d in April and ~206 MMcf/d in May 2020, a 17% and 55% decrease from March 2020. The hardest-hit G&P system appears to be Tallgrass Energy’s (TGE) Douglas system, with flows 84% lower in May 2020 vs. March 2020, followed by Meritage Midstream (volumes down 54% in two months) and Crestwood (volumes 51% lower since March 2020). Western Midstream’s Hilight system had the smallest decline in flow samples, though volumes are still 39% lower over the same period. ,b>Tickers: CEQP, WES
March 2, 2020: Coronavirus fears have hammered the financial markets over the past few weeks leading to wild volatility and equity markets selling off over 10%. Energy stocks have not been spared with WTI prices losing 25% since early January and midstream companies under our coverage also losing an average of 25%. Leveraging East Daley’s asset-level models that were released in mid-January, highlights the dramatic shift from early January prices that are now quite stale given the recent plunge in commodities. Rapid declines in market sentiment often lead to more of a sell the rumor mentality, so our analysts reran our asset and commodity models under an extreme downside scenario to simulate the impact of a prolonged world recession on company cash-flow expectations. The analysis reveals a wide range of cash-flow impacts with some companies showing cash-flow declines as high as ~20% relative to our mid-January models while others show little or no change. In this highly volatile environment with the potential for panic selling, opportunities could arise as many investors sell first and ask questions later.
May 29, 2020:Williams (WMB) has abandoned its Northeast Supply Enhancement Project (NESE) following a second rejection by state regulators of key water permits. WMB said it would not refile NESE after New York and New Jersey regulators on May 16, 2020 again denied the project’s watercrossing permits. NESE was a top option by National Grid to meet growing demand in the New York metropolitan area, and its loss will raise the stakes for regional price volatility during peak demand periods. On May 8, 2020, National Grid filed a supplemental report that forecasts peak-day demand in New York City’s outer boroughs and Long Island could exceed supply as soon as 2022/2023 (see chart). The NESE project was the lowest cost option under National Grid’s long-term capacity study to meet peak regional demand, and the utility now will have to consider other options. One top alternative was TC Pipelines’ (TCP) Iroquois Enhancement by Compression (ExC) project, which would add 125,000 Dth/d of incremental capacity to Iroquois. East Daley estimates the ExC project would contribute $35 million in annual EBITDA. However, the project would only help fill the demand gap in the near term. Depending on Iroquois’ ability to enhance existing facilities, we could see an additional future project, and more potential upside for TCP. Tickers: TCP, WMB
March 12, 2020: Significant commodity and equity price declines have roiled the energy markets over the past couple of weeks. In this quickly evolving market, understanding midstream sensitivity to changes in the commodity prices is essential and modeling companies at an asset-level allows for more accurate stress testing when forecasting cash flows in times of duress. The recent stress on the energy space has even bled into the debt markets with several midstream issues declining in recent days. For example, ENBL and GEL debt has recently seen sharp declines despite East Daley’s analysis indicating their ability to quickly de-lever with a distribution cut if necessary.
May 22, 2020:The EIA has revised down its U.S. natural gas production outlook for the third consecutive month, bringing its near-term estimates closer to East Daley’s but far below our production forecast for 2021. In its new May Short-term Energy Outlook (STEO), the EIA forecasts U.S. dry gas production will average 90 Bcf/d in 2020 and 85 Bcf/d in 2021, a decline of 5 Bcf/d and 8 Bcf/d, respectively, since its March STEO. Our nearterm forecast accounts for the latest shut-in data, updated producer guidance, and the impact of lower associated gas production in oil-rich basins. East Daley’s views diverge with EIA on trends in 2021, when we expect U.S. natural gas production to average 9 Bcf/d higher. Over the 2-year period, East Daley is forecasting a ~3.1% increase in U.S. gas production compared to the EIA’s call for a ~9.1% decline. Despite near-term headwinds, East Daley is more bullish on U.S. natural gas demand, particularly the call on gas from the power sector. Beyond 2020, we believe Henry Hub prices will need to be much higher than the current forward strip in order to balance U.S. gas supply with demand. We forecast Henry Hub will average $3.35/Mcf in 2021, compared to a current strip of $2.70/Mcf and the EIA’s outlook for $3/Mcf.
March 13, 2020: Much of the focus in the last few days regarding COVID-19 and the drop in oil prices has been on the impact to public equities. However, behind the scenes private midstream companies are being impacted as well. In the Permian alone, private natural gas gathering and processing assets handle over 20% of volumes making them significant players in one of the most critical basins in the U.S. It is critical to understand how they are impacted because they are tied to an integrated grid that feeds public downstream assets, supports upstream producers, and competes with other operators for their share of the shrinking pie. Additionally, they are big players in capital allocation for investment firms that have flexibility to invest across the capital structure.
May 22, 2020:East Daley speculated in last week’s Data Insights that there was room for further erosion in rig activity on Energy Transfer’s (ET) Midland G&P system in the Permian. In our view, impacts of the downturn have not taken full effect on the Midland system due to lingering risk from counterparties like Exxon Mobil (XOM) and Concho Resources (CXO), which have announced plans to further cut 2020 capex. Turns out, our crystal ball isn’t broken. At the time of our note, drilling activity on ET’s Midland system totaled 16 rigs, down from an average of 22 rigs in 1Q2020. Since then, XOM has dropped 4 additional rigs, bringing total rigs on ET’s Midland system to 12 as of May 10. Given that XOM and CXO are the most active producers on the Midland system, East Daley believes that the attrition in rig counts isn’t quite over. We forecast a trough of 3-5 rigs on the Midland system by September 2020. As a result, we expect ET’s Permian G&P footprint to generate EBITDA of $86 million in 4Q2020, compared to our previous forecast for $88 million, where they would have maintained 16 rigs on the Midland system. Tickers: ET, XOM, CXO
March 6, 2020: The sharp decline in WTI prices since Coronavirus surfaced has created uncertainty around the ability for U.S. E&Ps to increase production in the next two years. Commodity markets are primarily concerned about a reduction in worldwide travel and consumption of petroleum products due to an economic slowdown, which has led WTI-to-Cushing spot prices to dip below $45/bbl recently from as high as $63/bbl in January. To assess an even further downside case, East Daley updated its February Production Scenario Tools in each basin to reflect a scenario where WTI crude averages $36/bbl in 2020. The impact of the reduction is a 3% (0.45 Mbbl/d) reduction U.S. crude supply and a 1.3% (1.3 Bcf/d) reduction in natural gas supply. However, as a result of the rapid run up in supply last year, both crude oil and natural gas production would still be higher on average Y-o-Y. The more dramatic impact for crude oil is a 12% drop in expectations in 2021 and 2022. Furthermore, the Northeast would likely benefit from a drastic drop in crude prices due to a drop in associated natural gas production. Earlier this week, East Daley released a Snapshot Market Fears Go Viral – The Varying Degrees of Midstream Immunity highlighting the varying degree of impact to midstream earnings as a result of a downside case for crude prices. Leveraging basin-level modeling and reports, today’s Snapshot digs into the impact on crude and natural gas production
May 22, 2020:Permian rig counts continue to fall despite a recent rebound in WTI prices. The retreat by drillers is impacting some legacy G&P assets more so than others, among them Lucid’s private South Carlsbad system in the northern Delaware basin. Rig activity on S. Carlsbad fell 72% from March 1–May 10 compared to a 56% drop in total Permian rig activity over this period. EOG Resources (EOG), Concho Resources (CXO), and Devon Energy (DVN) are the top drillers, contributing 55% of gathered gas volumes, and together have announced curtailments in May averaging 15% of their 1Q2020 Permian net oil production. Interstate pipeline samples indicate throughput on the S. Carlsbad system declined rapidly at the end of April, down 26% over 4 days between April 27 and May 1, suggesting the presence of shut-ins on Lucid’s system. EOG and DVN have steadily dropped rigs from S. Carlsbad since late March and, as of May 10, both have stopped drilling on the system. While EOG’s shut-ins are likely to be spread among its non-core systems, East Daley’s data supports that Lucid’s system is among those systems impacted. Factoring in EOG’s rig declines to our pre-COVID system-level model reduces our estimate for S. Carlsbad system volumes by 23%, or ~290 MMcf/d, by YE2021. Tickers: CXO, DVN, ENLC, EOG, SMLP
March 11, 2020: The recent reduction in the WTI forward strip is reshaping the U.S. natural gas market, which has faced negative price pressure in the past 12 months due to competition from associated gas production growth. In a low oil price environment, associated gas growth in oil basins will decline significantly alongside oil production from reduced drilling. Thus, at the current forward strip for gas and at a low WTI strip we see a notable decrease in U.S. gas supply in 2020 and beyond from previous estimates. East Daley’s natural gas forecast from February 2020 was balanced with demand, including growth from associated gas basins. However, stripping production growth from oil basins causes the supply/demand balance to be undersupplied in 2020-2024. In 2021-2023 the total U.S. gas supply is 4.1, 6.4, and 7.6 bcf/d short of demand respectively. We foresee this discrepancy between supply and demand driving natural gas prices higher and increasing gas supply out of the Northeast and Haynesville to fill a portion, if not all, of the supply needed to meet domestic demand and LNG exports.
May 22, 2020:EQT (EQT), the largest U.S. natural gas producer, has started reducing its Northeast output in SW Pennsylvania and Ohio by up to 1.4 Bcf/d, according to a regulatory filing by EQM Midstream (EQM) last week. According to East Daley’s pipeline sample for the southwest Marcellus, a loss of 1.5 Bcf/d occurred between May 13 – May 20. Our pipeline sample for EQM’s combined Pennsylvania, Strikeforce/Poseidon, and other systems accounts for only 1 Bcf/d of these reported losses. These same EQM G&P systems have seen steady drilling activity of 6 rigs for the past year. However, EQT’s shut-in volumes don’t just impact EQM. An additional 115 MMcf/d was lost between WMB’s Ohio Valley System and MPLX’s Leech Xpress Interconnect in the same oneweek time period, totaling 1.1 Bcf/d of possible EQT curtailments. Approximately 272 MMcf/d was lost on other systems, leaving up to 285 MMcf/d more that EQT could curtail over the next 45 days, according to the statement in EQM’s 8-K. All four of the G&P systems that have lost volumes from EQT’s curtailments therefore may lose additional volumes over the coming days. The 272 MMcf/d of additional non-EQT volumes lost according to East Daley’s pipeline sample indicates that EQT is not the only Northeast producer curtailing natural gas production during this time period. Tickers: EQM, EQT
March 9, 2020: Oil prices were hammered Sunday night as the failure of OPEC+ to reach an agreement on supply cuts led to an all-out price war between Saudi Arabia and Russia this weekend. At the time of this writing, oil is down a whopping 29%, bringing its two-day losses to ~38%. Energy companies across the board are likely to trade significantly lower on Monday given the massive price decline. However, some midstream companies should fare much better than others given their lack of exposure to oil price linked basins and assets. In order to capture the exposure, East Daley labels every asset in our models with a commodity type, asset type, and basin/hub tag. This information is summarized in our Risk Matrix product which shows EBITDA exposure to each category. Data from the Risk Matrix indicates that several midstream companies have relatively little exposure to the decline in oil prices and could be safe havens to ride out the oil price downturn.
May 15, 2020: Midland basin G&P systems owned by Targa Resources (TRGP) and Energy Transfer (ET) are seeing reduced drilling activity. TRGP’s West Texas system consists of five processing plants with a combined capacity of 1,775 MMcf/d, and averaged ~40 rigs in 1Q 2020. Pioneer Natural Resources (PXD) and Parsley Energy (PE) were the 1Q top drillers, but both companies have announced plans to reduce 2020 capex and are now driving rig declines. TRGP’s West Texas system dropped 14 rigs as of May 3, a ~65% decrease since 1Q2020. ET’s Midland system consists of three processing plants with a combined capacity of 620 MMcf/d. Exxon Mobil (XOM) and Concho Resources (CXO) were the top operators in 1Q2020 when the system averaged 22 rigs. Both companies have announced 2020 capex reductions, though rig activity on ET’s Midland system has been more resilient to date than on TRGP’s West Texas system. Activity on ET’s Midland system fell 16 rigs as of May 3, a ~27% decrease from 1Q2020. Rig declines on TRGP’s system may be outpacing those on ET’s but, based on recent producer guidance, East Daley expects the pace of declines on ET’s system to catch up. We forecast drilling activity on ET’s Midland system will decline to a trough of 3 – 5 rigs by September, a total rig decline of ~81% from 1Q2020. Tickers:TRGP, ET, PXD, PE, XOM, CXO
May 15, 2020: On May 5, an explosion occurred on TETCO’s (ENB) southbound 30-inch line. Despite the blast, East Daley’s Northeast pipeline sample shows production was not significantly impacted as most of the gas was re-routed to other pipes. TETCO’s pain has become other pipelines’ gain, as both REX (TGE) and NEXUS (ENB, DTE) added short- and medium-term contracts in the days following the explosion. XTO and Equinor Natural Gas, took out contracts for 25 MMcf/d and 20 MMcf/d, respectively, on NEXUS while REX added 8 new contracts, for total volumes of 245 MMcf/d. The new contracts will add some near-term upside for the REX and NEXUS systems that could extend longer, depending on the length of the TETCO outage. Tickers:DTE, ENB, TGE
May 15, 2020: Enterprise (EPD) may see a lift to 2Q2020 activity in the Piceance basin following an apparent outage at Williams’ (WMB) Willow Creek plant. WMB since May 5 has been rerouting ~250 MMcf/d of gas away from Willow Creek to EPD’s Meeker plant, according to real-time flow data on East Daley’s Company Dashboards. EPD’s Meeker plant boasts almost 900 MMcf/d of excess capacity based on recent throughput, more than enough to accommodate displaced Willow Creek volumes. Depending on the outage length at Willow Creek, EPD could see upside to 2Q2020 gas processing at Meeker and, potentially, NGL throughput on its MAPL system. A similar event at Willow Creek lasted about eight days in May 2019, which suggests this may only be short-term routine maintenance. In the event of a month-long outage at Willow Creek, we estimate the financial impact to be about $2.5 million. However, the interplay between these two processing facilities highlights the competition between EPD and WMB in many western Rockies basins, where processing plants tend to have far more interconnectivity. Tickers: EPD, WMB
May 15, 2020: East Daley is monitoring the impact on gas assets of widespread shut-ins across the Bakken, an event we expect to continue into 3Q2020 due to continued low oil prices. A case in point is Crestwood’s (CEQP) Bear Den plant, which since early March has seen a significant decline in residue gas output. Integrating East Daley’s new Company Dashboards into our Company Blueprint Models, we can track the real-time impact of product flows to midstream companies’ financials. Presuming shutins don’t worsen into June, we estimate a ~26% decline in Bear Den gas volumes from 1Q2020 to 2Q2020. The Bear Den plant is part of CEQP’s Arrow system, which also gathers oil and water. Assuming there is not a 1:1 correlation between oil, water, and gas, we applied a 20% decline to Arrow’s oil and water volumes in 2Q2020 to account for the effects of lower oil and associated gas volumes flowing through the system. The cumulative impact to East Daley’s FY2020 EBITDA forecast for the Arrow system is -8.6%, a downward shift from $283 million to $259 million.Tickers: CEQP
May 15, 2020: Low oil prices and subsequently lower associated gas and NGL production in the Permian are causing project deferrals or outright cancelations, including MPLX’s BANGL pipeline and associated fracs and export docks. MPLX’s move points to a strategic shift in management’s thinking: Instead of pursuing higher-cost projects with pending FIDs, MPLX is preparing to maximize the value of projects like Whistler and Wink to Webster that have already reached FID. Prior to the downturn, East Daley estimated an 8x cost-to-EBITDA multiple for the project (pipeline + fracs); without the fracs, that multiple was closer to 12x based on our estimated FY2023 EBITDA for the asset. BANGL faces two problems: 1) Shin Oak (EPD, ALTM), Grand Prix (TRGP), and EPIC added nearly 1.3 MMb/d of NGL takeaway to a basin that already had ~290 Mb/d of underutilized pipeline capacity; and 2) prior to the recent downturn, MPLX’s Permian G&P system could only contribute ~220 Mb/d by 4Q2023 on the 500 Mb/d BANGL project (or 44% utilization), according to East Daley estimates, indicating a need for additional processing plants, third-party MVCs or acreage dedications. Our latest Permian NGL forecast calls for 1.8 MMb/d of production on average in 2020, a -12% reduction since our forecast from January. In light of this “new normal,” MPLX’s strategic shift appears to be a reasonably smart move.Tickers: MPLX, EPD, ALTM, TRGP
May 8, 2020: The EIA’s latest weekly refined product demand estimates indicate demand continues to climb from its April 10 low, but Y-o-Y comparisons suggest total demand destruction remains in excess of 30%. Gasoline is driving the uptick, improving by 1.6 MMb/d (6.7 MMb/d vs 5.1 MMb/d) over the last 4 weeks. The recovery in jet and distillate has been less pronounced, down 70% Y-o-Y and 20% Y-o-Y, respectively. Assuming the worst has passed, the shape of recovery for refined products will impact cash flows across midstream names. East Daley’s 1Q2020 Financial Blueprint Models assumed a Y-o-Y demand loss of 3% (1Q), 30% (2Q), 20% (3Q), and 10% (4Q) relative to 2019 throughput. Midstream companies are starting to disclose their downside scenarios in earnings and, so far, the numbers line up well with our forecasts. Magellan (MMP) said on their 1Q2020 call last week that they expect 2Q2020 volume losses of 25% (gasoline), 5% (distillate), and 70% (jet), followed by a one-month transition in 3Q2020 at half the decline before recovering (except jet) by year end. Cash flow implications provided by MMP’s management equate the risk to a $60-$70 million decline in DCF vs East Daley’s impact of ~$60 million in EBITDA. Companies like Kinder Morgan (KMI) and NuStar (NS) are forecasting more prolonged effects—very similar to East Daley’s volume scenario.Tickers: KMI, MMP, NS
May 8, 2020: Occidental Petroleum’s (OXY) pullback from the DJ will create new stress for the basin’s midstream operators. On May 5, OXY announced plans to shut-in wells and halt new drilling in the DJ basin for the remainder of 2020. OXY cut planned 2020 spending in the DJ to $300 million, a 67% decrease from its initial budget. As a result, OXY will shut about 9% of their U.S. wells, with roughly half of those shut-ins sourced to the DJ. OXY currently has ~49,000 onshore U.S. and GOM oil and gas wells, of which ~15,000 wells are located in the DJ. The 9% cut results in ~4,400 fewer wells across the U.S. and 2,200 fewer wells in the DJ specifically. East Daley projects the announced shut-ins will reduce OXY’s DJ crude production by ~15 Mb/d of oil and 135 MMcf/d of natural gas. Furthermore, based on analysis of OXY’s decline curves in the DJ, we forecast OXY’s crude production to naturally decline by ~30% by YE2020 with no new drilling. The shut-ins and natural declines should negatively impact Western Midstream Partners (WES), the primary gas processor for OXY in the DJ basin. East Daley forecasts a 10% reduction in G&P volumes on WES’s DJ system due to OXY’s shut-ins, reducing annual EBITDA by $60 million compared to our previous forecast. OXY also supplies the Saddlehorn crude pipeline, which has MVCs of 145 Mb/d in 2020, 165 Mb/d in 2021, and 175 Mb/d from 2022-24. OXY’s legacy shipping contracts will expire in 3Q2021, which may add pressure to Saddlehorn’s already below-MVC throughput. Tickers: OXY, WES, MMP, PAA, NB
May 8, 2020: Energy Transfer (ET) has requested permission from the Texas Railroad Commission to idle two pipelines for temporary storage use. ET has not publicly revealed the two pipelines, but East Daley believes West Texas Gulf (WTG) may be one of them. WTG is a common carrier pipeline that relies heavily on spot volumes. When the sum of MVCs leaving the Permian exceeds available Permian supply, spot barrels grow scarce, putting pipes like WTG at risk. According to East Daley’s Blueprint Financial Model, WTG needs to run at ~40% utilization or generate $42 million in annual revenue to be cash flow neutral. Were ET to negotiate a tariff similar to the storage rate on Enbridge’s (ENB) partially idled Line 3 pipeline ($1.20/bbl per month), ET would only bring in $5 million in annual revenue, assuming 80% storage utilization on the idled pipeline. In other words, ET would actually be better off keeping the pipeline cash flow neutral at 40% throughput rather than idling the line for temporary storage. Furthermore, it’s unclear whether idling Permian pipelines for storage is even necessary in PADD 3, where storage is only ~60% full as of May 1, according to EIA. Most storage facilities can recommission idled tanks and underground caverns to increase capacity, meaning a series of idled pipelines may not actually be necessary to alleviate any perceived storage constraints.Tickers: ET, ENB
May 8, 2020: As operators slash capex budgets and idle rigs, shutins become a crucial metric for evaluating downside risk to Permian midstream systems. To quantify the effect of shut-ins on G&P systems, East Daley assigns gas pipeline meter samples to individual plants, meaning we can monitor system-level volumes on a daily basis. The gas sample for ENLC’s Midland system fell ~20% from April 25 to May 1, from 267 MMcf/d to 217 MMcf/d, before rising slightly in early May. Concho Resources (CXO), the second-largest counterparty on ENLC’s Midland system, announced in April that it would begin voluntarily shutting marginal wells in response to low WTI prices. East Daley’s Production Scenario Tools show that IP rates for ENLC’s Midland system are considerably lower than other top Permian systems that gather CXO’s gas. In a separate analysis on blended G&P rates, East Daley found ENLC’s Permian G&P rates are among the highest in the basin, at $1.05/Mcf compared to an average basin rate of $0.78/Mcf (see the April 9 Snapshot – “Hunters & Gatherers”). These factors suggest that the wells referenced in the CXO statement are located on ENLC’s Midland system. We expect EBITDA on this asset to decline by $5.6 million, or ~30%, by 4Q2021 if volumes remain flat from the recent 20% drop. If WTI prices remain depressed and storage constraints endure, we expect pipeline sample data will reflect additional Permian shut-ins, a risk that East Daley can now quantify in real-time through our newly released Company Dashboards. Tickers: CXO, ENLC, EOG
May 1, 2020: Lack of latent pipeline capacity out of the Bakken and the Powder River tanked Clearbrook and Guernsey differentials during early April, which, combined with weak prices, has forced large amounts of wells to be shut in. East Daley tracks the daily gas flows for all G&P systems hitting interstate pipelines and the Bakken is now indicating there are significant shut-ins with sample volumes falling to a low of 1,537 MMcf/d on April 24, a 32% drop compared to March averages. Historically, Clearbrook and Guernsey have traded at a discount to WTI – Cushing, but with the shut-ins, that spread has vanished, and the two price hubs are currently trading at a slight premium, indicating pipelines are running below MVC levels. Enbridge’s (ENB) Bakken pipeline, Kinder Morgan’s (KMI) Double H, and DAPL (ET, MPLX, ENB, PSXP) are all vulnerable to declining volumes as spot barrels no longer buffer committed volumes. Additionally, Pony Express (Blackstone), Saddlehorn (MMP, NBLX, PAA), and Platte (ENB) are likely to see volume declines from barrels sourced from the Guernsey hub. Tickers: KMI, ENB, PAA, ET
May 1, 2020: The Explorer pipeline moves various refined products from Texas to Illinois/Indiana and is jointly owned by Shell Midstream (SHLX – 39%), MPLX (25%), Phillips 66 (PSX – 21%), and Energy Transfer (ET – 15%). One of the products running through the system is condensate, which ends up in Canada as a diluent for heavy oil sands transport. Recently, condensate spreads between Mont Belvieu and Edmonton have disappeared, making it uneconomic to ship north. Explorer does, however, have legacy contracts to ship condensate into Canada. These MVCs allow shippers to utilize delivery points supplying Pembina’s (PBA) Cochin pipeline as well as Enbridge’s (ENB) Southern Lights pipeline. The downside to these contracts is that if shippers do not move volumes, the deficiency payment ($1/bbl) is significantly below their contracted tariff ($2.80/bbl). As a result, Explorer takes a hit whenever spreads do not justify shipping. East Daley assumes these shippers will choose not to transport condensate into Canada in 2020, paying deficiency payments instead. This assumption, together with two contract expirations in 4Q2019 reduces total pipeline revenue by $56 million for FY2020 compared to FY2019. East Daley’s newly added coverage on SHLX includes a detailed breakout of contract risks on Explorer, including contract terms, tenure, and rates. Tickers: SHLX, MPLX, ET, PSX, PBA, ENB
May 1, 2020: Earlier this week CNX Midstream (CNXM) reduced FY2020 Adj. EBITDA guidance by 20%, making $208 million the new guidance midpoint, due to reduced throughput assumptions across their gathering systems. Third-party volume declines (likely HG Energy) due to suppressed NGL prices is likely a key contributor as well as CNX Resources (CNX) cutting their production forecast for 2020. East Daley’s residue gas sample provides great insight into current production across many of the Northeast systems. The 1Q2020 residue sample for key systems like the MPLX LP (MPLX) Majorsville/Houston/Harmon Creek (MHH) and CNXM Dry McQuay/Majorsville system remained relatively unchanged from 4Q2019 to 1Q2020, but the 2Q2020 sample shows changes are playing out. So far in 2Q2020, the MPLX MHH system is down 204 MMcf/d compared to the 1Q2020 sample, while the CNX Dry McQuay/Majorsville is up 99 MMcf/d Q-o-Q. This Q-o-Q shift likely indicates CNX is deferring wet gas production to the MPLX MHH system and instead focusing on the dry acreage in southwestern Pennsylvania. While this is likely downside for MPLX in 2Q2020, assuming volumes on the MHH system continue to trend down, they should see upside on the Sherwood system as volumes have continued to ramp up by 156 MMcf/d so far in 2Q2020. Tickers: CNXM, CNX, MPLX
May 1, 2020: TSpot and futures prices tell a very different story in the natural gas market currently. Henry Hub spot prices averaged just $1.75/MMbtu in April 2020, which is the lowest monthly average price since March 2016 due to significant oversupply, weak winter demand, and downward pressure on LNG exports. However, the futures curve has been steadily rising in 2H2020 and FY2021 in response to a weaker outlook for natural gas production from oil plays. By April 2021, East Daley projects associated gas production to decrease by more than 4.0 Bcf/d, excluding the risk of shut-ins. The loss in supply is driving our adjusted Henry Hub gas price forecast to an average $3.13/MMbtu in 2021, which is $0.40/MMcf/d (15%) above the current Henry Hub strip. Additionally, the risk of shut-in production from oil plays could add significant upside to the Henry Hub price curve this summer as U.S. cooling load starts. So far, shut-ins have been more prevalent in the Bakken, DJ Basin, and Powder River due to wider spreads in April. The Gulf of Mexico has also experienced a reduction in gas production. Furthermore, shut-ins are expected to become more prevalent in May based on a wider-spread impact to areas like the Permian, Anadarko, and Eagle Ford. East Daley predicts additional upside to the Henry Hub gas curve as U.S. gas production continues to decline.
April 24, 2020: The Permian led all basins with 17 dropped rigs W-o-W. Despite more bad news for the largest U.S. basin, weekly rig drops have leveled off considerably since March 15, indicating a possible slowdown in Permian rig attrition. According to East Daley’s Midstream Activity Tracker, Targa Resources’ (TRGP) West Texas system lost 6.3 rigs Wo-W, which leaves the system at 30. As shown in the figure, if rigs continue to drop off into the future at the rate seen over the past 3 weeks, TRGP’s West Texas system would have only 23 rigs by April 19 (red line in figure). If rigs on this system stay flat at 23, inlet volumes would drop by ~990 MMcf/d by December 2024 versus a 46-rig scenario. If rig counts stay flat at 30 rigs on the system, our forecast suggests that inlet volumes will still decline by ~688 MMcf/d. An analysis of producer guidance suggests rigs on the system could fall further and remain in line with our extrapolated downside forecast. Several key producers, including Parsley Energy (PE), Laredo Petroleum (LPI), and Pioneer (PXD) have all announced capex and rig cuts in recent weeks. While the current market environment presents considerable uncertainty for investors, East Daley’s system-level Production Scenario Tools provide clients with a versatile methodology to evaluate custom scenarios on public and private systems across our basin coverage. Tickers: TRGP, PE, LPI, PXD
April 24, 2020: Altus Midstream (ALTM), a subsidiary of the Apache Corporation (APA), has drastically reduced residue gas volumes supplying receipt points on El Paso Natural Gas Pipeline. Receipts from Alpine High have fallen from as much as 359 MMcf/d in February, to 44 MMcf/d in April (-88%). The sharp drop comes amid rumors of a temporary disruption on Gulf Coast Express (GCX) and well shut-ins on Alpine High. El Paso hooks into Gulf Coast Express, to which APA has contracted capacity of 550,000 MMBtu/d. Given a temporary disruption, APA could be diverting gas to other sources until GCX is operational. Regarding the possibility of well shut-ins, East Daley believes it is highly probable given the recent asset impairments by both APA and ALTM. APA communicated that it had no future plans for drilling on Alpine High, which, given the current low-price environment, could lead APA to shut-in production. The drastic fall first observed in March and continued in April seems to suggest this possibility. Overall, well shut-ins would hit ALTM’s bottom line, as G&P operations consisted of 66% of 2019 EBITDA and was originally projected to consist of only 38% of EBITDA in 2020. Tickers: ALTM, APA
April 24, 2020: Oil sands formations contain a type of hydrocarbon known as bitumen, which is a low-quality crude and highly viscous. Bitumen production is split into two different categories: in situ and mining. In situ refers to oil sands buried at depths of at least 75 meters, while mining operations strip the bitumen from shallower deposits. Historically, there has been decreased bitumen production during the second quarter because of operational challenges with ice thawing, but a low oil price environment can exacerbate that short-term decline. Suncor Energy’s (SU) OSG mine dropped production by ~75% Q-o-Q from 1Q2016 to 2Q2016. Syncrude’s Mildred Lake mine dropped production by ~80% Q-o-Q, and the Syncrude Aurora Mine dropped production by ~60% Q-o-Q during the same time period. Even in a low oil price environment; however, these large mines were able to ramp up production quickly in the following quarters. Recently, SU announced partial closure of the Fort Hills mine to preserve cash. Before the closure, the mine was producing 170 Mb/d of crude bitumen. Although there haven’t been additional mine closure announcements, East Daley expects bitumen production to decline in 2Q2020 as it has historically during this quarter. Due to the higher upfront capex required to produce from oil sands mines, environmentalist concerns, government mandated curtailments, and Canadian oil prices currently <$10/bbl, we do not expect any new greenfield oil sand mine projects to come online or any significant growth from existing mines. This contrasts with the Canadian Association of Petroleum Producers (CAPP) 2019 forecast for bitumen, which calls for oil sands production to steadily grow to 3.2 MMb/d in 2020 and continue growing to 3.57 MMb/d by 2025. While East Daley predicts production to drop during 2Q2020, we do see recovery by year-end. However, our forecast hovers around 3 MMb/d for the mid-to-long term, or 200-600 Mb/d below CAPP’s estimates. Tickers: SU
April 17, 2020: Last week, Plains All American (PAA), became the newest entrant to the energy capex and distribution cut party. On April 7, the company announced a $750 million reduction from its 2020/2021 capital budget and a distribution cut of 50%. It’s not surprising to see the decreased capex outlook given the prior project deferral news from PAA’s Red Oak Pipeline partner, Phillips 66 (PSX). In anticipation of PAA’s capex reduction, Easy Daley eliminated the project and associated EBITDA from its 1Q2020 PAA Pre-Call Blueprint Financial Model and Board Report. Additionally, on our April 4 webinar, “PAA Stress Test”, we highlighted PAA’s forward leverage under the expected capex savings as well as additional spending cuts the company could employ. Although PAA’s annual leverage did not breach 5.0x in our updated forecast, it was still significantly higher than the company’s guided range of 3.0x-3.5x, which is why it’s not shocking to see PAA using additional measures in the form of distribution cuts to shore up its leverage outlook. The table above provides an update to our 1Q2020 Pre-Call model. After incorporating announced asset sales and a 50% distribution cut equating to annual savings of ~$525 million a year, the company’s forecasted leverage decreases from 4.9x in FY2021 to 4.4x. With another $195 million in asset sales pending, this number should continue to improve. For further detail on PAA’s outlook, see East Daley’s 1Q2020 PAA Pre-Call Board Report. Tickers: PAA, PSX
April 17, 2020: With crude prices low and rigs pulling out of oil basins across the U.S., some rigs might land where you would least expect them to – the Green River, Piceance, and Barnett. As discussed in East Daley’s March 11 Snapshot “Gas Production in a Low Oil Price World,” East Daley estimates the current forward strip for Henry Hub prices is an inadequate representation of supply/demand fundamentals. Rather than using the existing forward strip for our in-house basin-level gas production forecast, East Daley has overridden the futures market to reflect 22% higher prices in 2021 (see table below). This updated price forecast incentivizes enough gas production to meet domestic demand. As associated gas coming out of the oil basins of the U.S. decreases, the Northeast and Haynesville will be the quickest to react to fill the gas supply shortage, but they will not be the only basins to react. Our April Production Scenario Tool (PSTs) forecasts for the Green River and Piceance indicate slight growth for all of 2021 and some of 2022. The Green River, which has had 1 rig for the last month, will return to 12 rigs for 2021, while the Piceance, which has 2 rigs operating in it to date, is forecasted to grow to 6 rigs for 2021. We do not foresee production growth out of the Barnett at our adjusted forward curve, but we do expect a slow-down in the pace of declines as the basin benefits from 7 rigs over the next few years. In a low crude price environment, it turns out the beneficiaries won’t just be the big gas basins; upward gas price pressure will have a positive impact on large and small gas basins alike, creating an opportunity for upside for a number of small-basin midstream G&P companies, including Enterprise (EPD), MPLX, Western Gas (WES), and Williams (WMB). Tickers: EPD, MPLX, WES, WMB
April 17, 2020: In East Daley’s 1Q2020 Blueprint Financial Model for Rattler Midstream (RTLR), we forecast quarterly EBITDA to be $78 million, a $7 million increase Q-o-Q, which may seem like a bullish estimate considering recent events in commodity markets. Afterall, Diamondback Energy (FANG) announced a 1-3month frac holiday starting in March and that operations would be reduced to 3-5 completion crews for the months thereafter. Despite the recent cutbacks, however, East Daley forecasts SWD volumes to grow by 67 Mb/d Q-o-Q based on the lagged relationship between sourced water (freshwater) volumes and the resulting growth in saltwater disposal volumes for the quarter following. For 4Q2019, sourced water volumes were a record 478 Mb/d, which is estimated to yield higher growth in SWD volumes for 1Q2020. The downstream impact contributes to the modeled $5 million growth in SWD EBITDA for the first quarter. The relationship between the two types of assets, although somewhat obvious, warrants further investigation as not all acreage in the Permian is created equal. In general, FANG estimates that it takes 650 Mb of sourced water to complete wells in the Delaware and only 425 Mb for wells in the Midland. SWD to crude production ratios are also generally higher in the Delaware, yielding 4-6 barrels of saltwater for every one barrel of crude as compared to the Midland’s estimated 1-2 barrels. Given these relationships, East Daley expects that the spike in 4Q2019 sourced water volumes were a result of more well completions in the Delaware, which should translate into higher growth for SWD volumes in 1Q2020. Tickers: RTLR, FANG
April 17, 2020: Lower commodity prices have forced every basin across the U.S. to experience at least some rig attrition. Some basins have been hit harder than others, like the DJ, for example, with total rigs down ~50% since January 2020. The impact to midstream players in the basin is not, however, 1:1. According to East Daley’s proprietary Rig Allocation Model, the DJ rigs that are still active are almost all feeding DCP Midstream’s (DCP) G&P system. Shown to the left are rigs allocated to DCP and Western Gas’(WES) system. The graph also compares residue gas receipts from the plants within each system. The residue points show that DCP continues to benefit from increasing volumes into April while WES’ volumes are starting to decline. The graph also shows that the number of rigs allocated to WES’ system drop off a cliff in April. In our latest 1Q2020 Pre-call Blueprint Financial Model for WES, we assumed 5 rigs in April declining to 2 by July. If the current rig count holds, the EBITDA downside to our latest WES model would be ~$6 million for FY2020. In our latest DCP model, we assumed 6 rigs on the system through 1Q2020, declining to 2 by July. Adjusting rigs up to actuals through 1Q2020 and assuming flat rig counts through April, increases FY2020 EBITDA on the system by ~$15 million. However, after April, East Daley believes DCP is likely to lose a significant number of rigs due to continuing capex cuts across the sector. Tickers: DCP, WES
April 3, 2020: Rapidly falling oil prices have caused many E&P companies to announce reductions in capex and to suspend drilling activity across the U.S. East Daley’s Midstream Activity Tracker shows the Eagle Ford has already seen rigs decline from 88 in the beginning of March to 68 as of March 22. One of the E&P companies to announce cutbacks on drilling in the Eagle Ford is Murphy Oil Corporation (MUR), who stated they will release all of their rigs and frac crews in the shale play with no activity planned for 2H2020. Callon Petroleum (CPE) is another company to announce reductions in drilling activity with plans to only run one rig in the Eagle Ford in 2H2020. East Daley’s Production Allocation Tool shows that MUR averaged 3 rigs on DCP Midstream’s (DCP) Eagle Ford system in 1Q2020, while CPE averaged 2 rigs on the system’s throughout the quarter. With MUR and CPE combining to reduce 4 rigs on the system, and assuming other operators will follow suit, we predict the total rig count on the system to fall from 14 rigs to 6 rigs by the end of 2Q2020 before starting to recover. As oil prices rebound in the coming years, we predict rigs on the system to slowly rebound back to ~10 rigs by the end of 2021. The decrease in rigs will force inlet volumes on the system to decline to 645 MMcf/d in 4Q2020, representing a 68 MMcf/d decrease Y-o-Y compared to 4Q2019. Our forecast will drop the EBITDA on the system from ~$41 million in 4Q2019 to ~$36 million in 4Q2020. The declines continue through 2021, where we predict inlet volumes to be below 600 MMcf/d and EBITDA to be ~$33 million in 4Q2021. Tickers: MUR, CPE, DCP
April 3, 2020: Recently Targa Resources (TRGP) announced a 90% cut to their distribution in accordance with the new lower commodity price environment. TRGP’s core asset base is located in the Permian basin where East Daley expects associated gas production to notably decline over of the next few years. We have already seen core operators on TRGP’s WestTX system like Pioneer (PXD), Laredo (LPI), and Parsley (PE) announce capex cuts and rig reductions for the remainder of 2020 with the cuts likely to continue if prices remain depressed. East Daley’s 4Q2019 Post-Call TRGP Blueprint Model assumed 42 rigs on the system moving forward, which translated into an additional 2 unannounced plants (beyond the already announced Gateway Plant) being needed to meet production growth on the system. The 1Q2020 Pre-Call TRGP Blueprint Model assumes an average of 21 rigs on the system through YE2023 and only the Gateway plant needed to meet growth on the system. This new volume assumption along with the decrease in liquids prices (due to the system having POP exposure) translates into gross margin on the system dropping by $27 million/quarter (on average) through YE2023. While this is material downside to TRGP’s G&P segment, there is even more downside as the NGL volumes from the newly announced plants would have likely been transported on Grand Prix and provided incremental volumes to TRGP’s fractionation complex and export dock. Tickers: TRGP, PXD, LPI, PE
April 3, 2020: On March 31, Diamondback Energy (FANG) released its third operational update in response to persistent volatility in crude prices. The press release provided further downward revisions of production, rig counts, and capex compared to original FY2020 guidance. FANG intends to cut rigs over time, ending 2020 with 8 rigs (down from 22 currently). This rig reduction is reflected in lower crude production, which is now expected to range from 183 – 193 Mb/d, down 17% from original FY2020 guidance and flat Y-o-Y at the midpoint. Production will be skewed toward the first half of the year, with 4Q2020 production guided to 175Mb/d, which FANG expects to maintain throughout 2021 with 6-8 operated rigs, 4-5 completion crews, and 20-30% lower capex than original FY2020 guidance. East Daley’s Production Allocation Tool gives insight into FANG rig movements among both public and private systems. The tool shows EnLink’s (ENLC) Midland system gained 3.3 FANG rigs from 3/1/20 – 3/22/20 at the expense of WTG’s private North Midland system, which lost 3.3 rigs in the same time period. These systems have average IP rates of 658 Mcf/d and 678 Mcf/d, respectively. In the Delaware basin, the private Vaquero system gained 1.2 FANG rigs from 3/1/20 – 3/22/20 at the expense of Brazos’s private midstream system, which lost 1.5 rigs over the same time period. Our modeled average IP rates for these systems are 3,852 Mcf/d and 2,144 Mcf/d, respectively, indicating that FANG is shifting rigs to its acreage with higher IP rates in the Delaware. As the year goes on and rig cuts become more pronounced, this trend is likely to continue. Tickers: FANG, ENLC
March 27, 2020: EnLink Midstream’s (ENLC) Delaware G&P system consists of 180 miles of gathering pipeline and the Lobo processing facilities, which have a total processing capacity of 375 MMcf/d. The system is a joint venture between ENLC and Natural Gas Partners and was purchased from Matador Resources Company (MTDR) in 2016. EOG Resources (EOG), MTDR, and XTO, a subsidiary of Exxon, are all anchor customers on the Delaware G&P system. Due to the sharp drop in oil prices, MTDR has stated they are releasing their drilling rig operating in Loving County by the end of March, which is the dedicated acreage supplying ENLC’s Lobo plant. This is not to be unexpected, as other producers have deferred production due to dismal prices in Waha during 1H2019. Producers have again deferred production in response to the poor pricing environment. Residue receipts from ENLC’s Lobo plant have dropped by approximately 9% Q-o-Q, which is an indication of less completion activity by ENLC’s customers. This will likely reduce 1Q2020 segment profit for the Delaware G&P system by approximately $1.2 million Q-o-Q. All is not lost for ENLC’s Permian segment however, as ENLC’s Midland system has yielded growth of approximately 9% and an expected 13% for 4Q2019 and 1Q2020 respectively. This is due to the recent expansion of the Riptide processing plant and continued debottlenecking initiatives undertaken by management. Tickers: ENLC, MTDR, EOG, XOM
March 27, 2020: As a result of current commodity prices and the broad sell-off in energy related securities, Magellan Midstream Partners (MMP) released their bi-annual analyst day report ahead of schedule. Along with the 53-page deck, the company also released a 2020 DCF sensitivity analysis providing a range of possible effects from COVID-19. Because MMP’s business is primarily focused on refined products, it’s no surprise the biggest risks to 2020 earnings are those exposed to refined product prices (i.e. gasoline, butane). Based on lower refined products demand, lower blending margins, loss of uncommitted crude shipments, and upside from cost savings and storage assets, the resulting analysis indicated a range of ($180) to ($95) million decline for 2020 DCF. Subsequent to MMP’s analysis, East Daley has run its own scenario through our MMP Financial Blueprint Model. We took the current forward curve for RBOB and butane futures and estimated a decline in refined products demand of (3%) 1Q; (30%) 2Q, (20%) 3Q; and (10%) 4Q. Based on MMP guidance, we assume spring blending margins are completely hedged and risks to those earnings will not come until 2H2020. The table to the left compares the results of MMP’s most exposed assets, the refined products pipeline and the butane blending business. MMP’s DCF results are included below our analysis for reference. Tickers: MMP
March 27, 2020: While total U.S. rigs have fallen by 28 rigs from February to the middle of March, drilling in the ArkLaTex basin is following an opposite trend. On February 2, ArkLaTex had 40 rigs drilling, which was the lowest rig count in the basin since 2016. Since the beginning of February, the basin has seen a rebound in drilling activity, and had 48 rigs drilling as of March 15. The operators who contributed to this increase in drilling include Aethon Energy (9 to 12 rigs), Sabine Oil and Gas (2 to 3 rigs), Rockcliff Energy (3 to 4 rigs), Hawkwood Energy (0 to 1 rig), Zarvona Energy (0 to 1 rig), and Forza Operating (0 to 1 rig). It is likely that these operators are increasing drilling activity because they forecast associated gas production from the oil rich U.S. basins to decrease, as a result of the lower oil prices and reduced spending from U.S. operators. Kinder Morgan’s (KMI) KinderHawk plant has seen an additional rig on its system from Aethon’s increased activity. Williams’ (WMB) Access system picked up volumes from Rockcliff’s additional activity. The private system, Arclight – Midcoast, has seen the majority of the increased activity, gaining new rigs on its system from Hawkwood Energy, Zarvona Energy, and Forza Operating. Tickers: KMI, WMB
March 27, 2020: On March 17, WPX Energy followed suit with operators around the country by releasing an operational update in response to recent drops in oil prices. In the statement, WPX announced a 25% CAPEX cut of $400 million, bringing FY2020 capex down to $1,330 million. During the 2016 price downturn, total WPX rigs in the basin dropped approximately 50%. East Daley’s Production Allocation Tool currently assigns 7 WPX rigs to the WPX/Howard system, up 50% from average WPX rigs on the system for 4Q2019. The chart to the right shows total historical WPX rigs in the basin compared with rigs assigned to the WPX/Howard system. So far in 2020, 61% of WPX’s rigs fed gas volumes to the WPX/Howard system. If rig cuts in the coming months align with producer guidance and the proportion of WPX’s total rigs on its Howard system remains constant, gas volumes will be reduced on the system by an average of 8% for FY2020 and 38% for FY2021 compared to our previous forecast.
March 20, 2020: These past weeks have been inundated with headlines about decreased capital budgets for E&P companies. The pressure of depressed commodity prices is forcing small, medium, and large companies alike to cut back on capital spending plans for 2020, including Devon (DVN). At a ~$500 million planned reduction, DVN’s cutback primarily focuses on less profitable basins like the STACK and Powder River. Among midstream companies, EnLink (ENLC), DCP, and Tallgrass (TGE), are a few of the operators that will feel the effects – some more so than others. For example, TGE’s Interstate Gas Transmission only has a small ~3.6 MMcf/d FT agreement with DVN, likely not materially impacting the bottom line. It’s a similar story for DCP. Processing volumes on their MIDCON system show DVN volumes at only ~27 MMcf/d (1Q2019). However, ENLC’s concentrated asset position in the Anadarko makes the company most exposed to DVN’s reduced capital plan. Based on throughput data, their COK system shows total DVN processing volumes of 350 MMcf/d (1Q2019). During 2019, DVN originally planned to add two rigs back on ENLC’s system but it’s likely the timing of these additional rigs will be pushed back to the longer-term (sometime in 2021). The figure above adjusts ENLC’s COK system throughput based on the additional rigs being pushed back to 2Q2021. Tickers: ENLC, DCP, TGE
March 20, 2020: As oil prices plunge, the reaction of producers will be quick, but actual declines, forgoing shut-in prices, will be slower to follow. Each month, East Daley publishes production forecasts for U.S. basins based on the forward strip for WTI and Henry Hub. Based on the WTI forward strip from March 9, 2020, crude production is expected to remain flat from FY2019 to FY2020 versus our outlook in February that called for 7% growth across that same time frame. The Henry Hub forward strip pulled on March 9, 2020 did not capture the growth in gas prices that will be necessary to back-fill the related losses of associated natural gas production in crude basins. The East Daley adjusted forward strip is $0.44/MMbtu higher for the year 2020 than the forward strip used in February’s model and $0.56 higher than the March 9, 2020 strip for gas prices. For 2021-2023, the East Daley adjusted gas price is higher than the February forward strip by $0.82/MMbtu, $0.73/MMbtu, and $0.68/MMbtu, respectively. At these prices we expect FY2020 natural gas production to average 3% higher than the full year average in 2021, which is in line with demand for U.S. gas and total dry gas volumes in our February model. Our March Production Scenario Tools (PSTs) are available by basin for download on the East Daley client portal.
March 20, 2020: Expanding on the above Data Insight titled Tight Pockets, East Daley has tracked producer revisions to capital guidance and in the past two weeks alone, over 15 E&Ps have released supplemental updates regarding changes to capital expenditures, rig utilization, and production volumes from original FY2020 guidance. Reductions in any of these three metrics have implications for midstream counterparties. Cimarex Energy (XEC) was one of the 15 producers who slashed capex in 2020, cutting guidance 40% from $1.3 billion to $720 million. XEC operates in the Delaware basin and primarily feeds the MPLX – Permian, ET – Delaware, and Caprock – Permian systems. Throughout 1Q2020, XEC had been operating 10-12 rigs with as many as 5-6 rigs on the MPLX Permian system during late January. Assuming XEC responds by dropping rigs in the Delaware, MPLX is likely to feel the brunt of the impact. East Daley’s 4Q2019 MPLX Blueprint Financial Model assumed 5 rigs moving forward on the MPLX Permian system, which translated into $60 million of EBITDA by YE2023. If rigs on the system drop to 2 by mid-2020, EBITDA on the MPLX Permian system is expected to decline by $25 million to only $35 million for FY2023. Tickers: XEC, MPLX
March 13, 2020:ONEOK, INC. (OKE) owns the largest market share for gas processing in the Bakken. This month their Bakken system alone saw residue gas volumes greater than 900 MMcf/d, or ~42% of the total residue gas in the basin. Over the past few weeks however, one of the key contributors on the system has slowed down drilling operations in the area. In the month of February, Exxon Mobil (XOM) averaged over 10 rigs in the basin, but the most recent rig count shows they are currently operating 8 rigs. In addition to Exxon dropping rigs in the basin, our proprietary allocation model shows that Exxon has shifted 2 of its rigs from OKE’s Bakken system to its own system: XOM – Nesson. After analyzing the trend set by XOM, we revised our System Level PST for OKE – Bakken to model production based on a total of 24 rigs throughout 2020; down from our previous model which predicted 29 rigs throughout the same time period. Our revision dropped gas inlet volumes for YE2020 form 1,540 MMcf/d down to 1,437 MMcf/d, representing a 103 MMcf/d decrease. This decrease in volumes align with our downside blueprint model that was released last week which shows EBITDA falling $240 million compared to our original blueprint model. With our down scenario being met with only XOM dropping rigs, it suggests that if other operators in the basin follow suit to Exxon there could be further downside risk to OKE’s Bakken system. Tickers: OKE, XOM
March 13, 2020:As oil prices have trended downward in recent weeks (days?), adjustments to the WTI forward strip have followed suit. Thus far, the future of gas prices has been far less certain. The strip that ranged from $50.77-$53.78 into mid-2023 on February 24 now ranges from $30.93- $46.37 for the same period. Near term, the gas forward strip saw downward movement of 8% of 1H2020 between 2/24 and 3/9, only to correct upwards by 5% a few days later. The latest forward strip hit $2.63 for the beginning of 2021, which is in-line with EDC’s expectation that, at $36/bbl oil, associated gas volumes are bound to decrease and cause gas prices to rise. The upward movement of the gas strip is reflective of the relationship between gas prices and associated gas coming out of oil basins. The lag in a response is telling of the market’s uncertainty regarding the impact of low oil prices on gas prices and production volumes. By the second half of 2021, when the oil forward strip reaches $39, the forward strips for gas converge. This implies that at $39/bbl oil, the supply/demand for U.S. gas is balanced back to what it was at $50/bbl. Because it is unlikely that associated gas volumes from oil basins will reach previous volumes at that price, the forward strip may be reflective of an assumed decrease in LNG export volumes in the future. East Daley’s take on the fall of associated gas volumes in a low oil environment and subsequent backfill from the Northeast and Haynesville is explored in our recent Snapshot, Gas Production in a Low Oil World. Check out the basin-level Production Scenario Tools for EDC’s downside case, which is comprehensive of low oil and gas prices.
March 13, 2020:During their 4Q2019 earnings’ call, Rattler Midstream (RTLR) announced their newly formed JV partnership with ArcLight Capital Partners. The 50/50 JV consists of an existing gathering system spanning 84 miles in the Midland basin and the 40 MMcf/d Yellow Rose processing plant. The JV also intends to spend an additional $100 million ($50 million net to RTLR) to build an additional 60 MMcf/d processing plant to support Diamondback Energy’s (FANG) growth plans. Before the recent crash in oil prices, RTLR anticipated the plant becoming operational mid-2021. According to East Daley’s production allocation tool, FANG is unsurprisingly the primary producer on the existing system with smaller volume contributions from OVINTIV (OVV) and Colgate Energy. Plant data shows that Yellow Rose received roughly 7,121 Mcf/d during 2018. FANG averaged approximately 1.2 rigs on the Amarillo acreage during 2019. Using IP rates of 500 MMcf/d and a total drill time of 22 days, East Daley estimates that Yellow Rose volumes averaged 10 MMcf/d for 2019. Assuming FANG continues to utilize a one rig program on the Rattler Amarillo JV system, inlet volumes are expected to average 11 MMcf/d for 2020. The reason for the sluggish growth is that IP rates are relatively low is this area compared to other areas in the Permian. Regardless, the JV is estimated to yield an additional $1 million in EBITDA in FY2020, net to RTLR. Tickers: RTLR, FANG, OVV
March 6, 2020: The 1 MMb/d Cushing-toGulf Coast pipeline, Red Oak, formed by Plains All American (PAA) and Phillips 66 (PSX), will have the ability to source crude from Cushing and the Permian. The $2.5 billion project will leverage mostly new pipe infrastructure between origin and destination markets as well as existing infrastructure via a capacity lease on PAA’s Permian to Wichita Falls Sunrise II pipeline. With the recent filing of PAA’s 2019 10-K, the company has divulged that 260 Mb/d of Sunrise II’s capacity will be leased to Red Oak over a term of 33 years. Valued at $155 million, the lease will decrease PAA’s cash contribution towards Red Oak and utilize a portion of its legacy infrastructure which faces risk to lose volumes as new Permian to Gulf Coast capacity comes online between now and 2021. In fact, since the startup of Cactus II, EPIC, and Gray Oak, throughput data filed with Texas regulators has already shown a decline for pipelines making northbound shipments from the Permianto-Cushing (e.g. Basin, Centurion, and Sunrise). East Daley expects this trend to continue. Outside of refinery demand for Permian crude, other shippers are not incentivized to ship to Cushing with Midland trading at a premium to WTI. Moreover, the forward markets’ consistent ~$1.30/bbl premium implies no change in this dynamic for the foreseeable future. From a strategic standpoint, the lease agreement makes sense by insuring a portion of Sunrise II from potential revenue downfalls. However, both Red Oak and Sunrise still run the risk of being underutilized, regardless of commitment levels. By 2021, East Daley forecasts significant capacity overbuilds leaving both Cushing and the Permian, making it tough to justify Permian barrels flowing north to Red Oak when shippers are expected to have plenty of space on direct southbound lines to the Gulf Coast. Tickers: PAA, PSX
March 6, 2020:Crestwood (CEQP) recently announced a new gathering and processing agreement with Occidental (OXY) in the Powder River Basin. In the news release, CEQP guided to 45-50 new well connects in 2020. In their 4Q2020 earnings released in February, they guided to 50 well connects between Chesapeake (CHK) and Panther Energy, which implies that OXY’s incremental well connects most likely replaced Panther Energy or a portion of CHK’s new well connects. East Daley currently models 44 connects in 2020, if CEQP hits the high end of this guidance, it would be an incremental $3 million to East Daley’s 2020 CEQP EBITDA forecast. The more interesting portion of this announcement was OXY not supporting their counterparty in the basin, Western Gas (WES). Although WES has gathering lines feeding their Hilight processing plant in the areas OXY has been drilling, in November, OXY wells fed 0% of Hilight’s inlet volumes. The top five producers/systems feeding the plant in November are shown to the left. The top three include EOG Resources (EOG), Thunder Creek Gas (Meritage), and Vermilion Energy (VET). With OXY already sending its gas elsewhere, there will be little downside to WES and only incremental upside to CEQP. Tickers: CEQP, OXY, WES, EOG, CHK
March 6, 2020:Residue gas volumes reached record high levels in March for gas processing systems in the Williston basin. The average total residue volume reported for March shows a 17% increase compared to FY2019, increasing from 1,807 MMcf/d to 2,170 MMcf/d. The North Dakota Pipeline Authority (NDPA) stated in its February update that December flaring percentages fell to 16% of total gas production, down from 17% in the months prior. With new expansions like ONEOK’s (OKE) Demicks Lake II and the Kinder Morgan’s (KMI) Roosevelt expansion, along with the OKE Elk Creek Pipeline, new wells brought online are more likely connected to a processing system instead of being forced to flare. The processing plants with the biggest changes in throughput from FY2019 to March 2020 include Targa (TRGP) – Badlands (up 120 MMcf/d), OKE – Bakken (up 80 MMcf/d), KMI – Bakken (up 58 MMcf/d), and Oasis (OMP) – Wild Basin (up 44 MMcf/d). In addition to the increased processing capacity, drilling activity has also increased. So far in 2020, the rig count in the basin has averaged 63.5 rigs, up from the 4Q2019 average (59.6 rigs) and FY2019 average (60.5 rigs). It is likely that E&Ps have been biding their time to fully develop their acreage until the new processing capacities are online, and aside from virus scares, will continue to ramp production in the near- and long-term future. Tickers: OKE, KMI, OMP
March 6, 2020:EnLink Midstream (ENLC) provided updated 2020 guidance for their Oklahoma segment during their 4Q2019 earnings’ call and press release. Volumes are anticipated to decline in 2020 due to “moderated” drilling activity by producers. Using EIA completion data, an estimated 44% of new well connections in 4Q2019 were attributable to DUC inventories in the Anadarko. This is unsurprising as 2020 declines were previously called out in East Daley’s 2Q2019 Post-Call Board Report and subsequent board reports for ENLC. Further contributing to the declines, East Daley’s most recent Midstream Activity Tracker allocates five rigs to ENLC’s COK system, consisting of regionally focused producers such as Citizen III, Paloma Partners IV, and Camino Natural Resources. This is a drastic change from the 24 rigs on ENLC’s system in late 2018. Devon Energy (DVN) is anticipated to resume drilling activity starting in 2Q2020 in conjunction with its JV agreement with Dow (DOW). However, the wells drilled under the two-rig program are not anticipated to contribute additional volumes until 2021. East Daley models a 13% throughput decline on ENLC’s COK system from 2019 to 2020 as a result. Declines on the system begin to slow, however, in 2021 and 2022 as DVN resumes drilling and ENLC gets the full benefit of the additional rigs on its system. As for 2020, ENLC is still expected to collect the $55-$65 million from an MVC commitment which will help mitigate losses until its expiration at the end of the year. Tickers: ENLC, DVN