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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.
April 24, 2020: Despite some short-term demand destruction from COVID-19 and global LNG overhangs, the tailwinds of U.S. natural gas demand growth remain intact driven by long-term growth in LNG exports, exports to Mexico, and power generation. Near-term, the major impact from COVID-19 has led us to adjust down our forecast for industrial demand by 0.7 Bcf/d in 2020. However, our latest demand forecast still calls for growth of 3.5 Bcf/d, 2.5 Bcf/d, and 2.0 Bcf/d for 2020, 2021 and 2022, respectively. The growing demand comes in the face of an almost certain decline in associated gas supply (assuming no change in the oil strip) from oil basins where East Daley estimates 2.6 Bcf/d of declines from early 2020 production by YE2021. Rising demand and falling associated gas leave the U.S. with a supply imbalance that will require higher natural gas prices to incentivize growth from dry gas basins like the Haynesville and Northeast. East Daley forecasts natural gas prices will need to reach a yearly average of $3.09/Mcf by 2021 in order to balance the market.
May 4, 2020: U.S. natural gas production from oil basins has declined by more than 3.1 Bcf/d since late-March 2020, largely due to shut-ins and the suspension of well completions in oil basins. Figure 1 below shows the decline in gas production volumes and the percentage of decline specific to that basin. Assuming that oil and gas production remain correlated, applying those same percentage reductions to oil production indicates that U.S. crude production has declined by 1.28 MMbbl/d since late-March.
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 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.
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: 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.
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 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.
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 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.
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 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.
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
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?
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
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.
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
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.
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
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.
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 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.
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 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.
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 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.
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 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
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 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.
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