During EnLink’s (NYSE:ENLC) Q1 earnings call, management reiterated their net EBTIDA guidance of $1,355MM at the midpoint. Their Q1 2023 net EBITDA came in at $323.7MM down slightly from Q4’s net EBITDA of $337.2MM. Volume growth across their assets was strong, but some of their assets suffered due to the lower commodity price environment despite their strong hedging program. The 37% price pull-back from the Jan 8th high of $13.45 presents a strong buying opportunity. As we always do, we’ll work through each of their asset segments to give a birds-eye view of what’s going on with their business starting with their fastest growing segment, the Permian.
As a reminder, figures on EnLink’s Segment Profit chart are in millions of dollars. Segment profit includes plant relocation expenses classified as operating expenses due to GAAP accounting rules, although for our purposes, they should be counted as CAPEX because they contribute to EnLink’s growth, so EnLink has conveniently included these in the chart. Likewise, segment profit also includes unrealized derivative gains and losses and since these expenses relate to future quarters, those expenses should also be removed to understand how the underlying business performed. For the Permian, segment profit, net of plant relocation expenses and unrealized derivative gains, came in at $90.1MM vs. $100.1MM in Q4 2022 (red box). You can see from the volume charts that the Permian continues to grow strongly:
The primary reason for the 10% decline in segment profit was due to lower natural gas prices which continued to suffer during the quarter and a $4MM lingering impact from weather and earthquake events that occurred in late Q4. To get a better sense of how commodity prices are affecting their segment profit in the Permian, we can apply a simple volume to segment profit ratio for their natural gas segment:
The ratio tells you how much natural gas volume (average volume of gas gathered and gas processed) is required to generate $1MM in segment profit. In the chart, the blue bars represent the ratio (left side of chart) and the orange line is the Henry Hub natural gas quarterly price (right side of chart). You can see that the segment profit has varied greatly with the price of natural gas. The ratio has an inverse relationship with the price of natural gas. It takes more volume to make $1MM in segment profit when natural gas prices are low versus when those prices are high.
When the price of natural gas peaked in Q2 and Q3 of 2022, the ratio reached an all-time low of 14.7 and 15.1 respectively. In other words, it only took 15,000 MMbtu/d to generate $1MM in segment profit during this time because natural gas prices were so high, whereas in Q1 2020 when natural gas prices were bottoming due to the outbreak of Covid, it took 30,000 MMbtu/d of volume to generate $1MM in segment profit. In part that was due to the exceptionally weak basis spreads in the Waha hub in Texas (the major hub in the Permian Basin), where natural gas prices hit negative numbers (a basis spread is the difference in price between one trading hub and another):
Waha Basis Spreads
Note, the price for natural gas in Waha will always sell at a discount to the price at Henry Hub in Erath, Louisiana because Waha is a supply center and Henry Hub is in the heart of a growing demand center. In the chart above, you can see where major new pipelines came into service in 2021 (PHP, Whistler and Double E), greatly increasing the take-away capacity and reducing the basis spread to Henry Hub. Recently, Waha natural gas prices have once again gone negative (you had to pay to “sell” spot gas) as too much supply has met with too little pipeline take-away capacity.
EnLink has taken a couple of measures to combat the weakness in natural gas prices. They have traditionally marketed their natural gas in Waha, but since they’ve grown their volumes, they addressed the weakness with firm transportation agreements. To combat the constraints, EnLink entered into a short-term firm transportation agreement on the Whistler Pipeline which will move some of the gas out of Midland into Agua Dulce near Corpus Christi (about 90MMcf/d or 72% of their Permian commodity price exposure). When the Matterhorn pipeline comes online in 2024, they will move those commodity sensitive volumes to that pipe. Although prices for natural gas have collapsed to the $2 per MMbtu range (Henry Hub) in early 2023, EnLink also hedged 96% of their 2023 exposure at higher prices such that a 50-cent rise or fall in natural gas prices only moves their profits up or down by $1MM.
Permian Predictions for 2023
In any case, the hedged price for natural gas in 2023 is still lower than the prices realized in 2022, hence they earned a lower amount of segment profit in the Permian despite the higher volume. Using the ratio mentioned above, we can also make predictions for Q2 through Q4. In Q1 the volume to segment profit ratio was 21 but $4MM in segment profit was lost due to earthquakes and weather. If we add that back, the ratio drops to 20. We can assume the hedged volumes will generate a ratio of 20 in Q2-Q4, and we can estimate the growth in volumes. Doing this, we can see the natural gas subsegment in the Permian will generate $346.7MM in segment profit in 2023 versus $356.7MM in 2022, down 3% despite an estimated rise in natural gas volumes of 23% YoY (Q4 2022 to Q4 2023). On the crude side, volumes look lackluster in Q1 but may increase as the year progresses.
In February, EnLink forecasted a rise in Permian Segment profit to $460MM at the midpoint (including the crude segment) from $425MM in 2022. That forecast assumed a $4/MMbtu Henry Hub natural gas price and obviously we are below that. I don’t see EnLink achieving $460MM in the Permian in 2023 unless volumes rise significantly more than 23% (2023 exit rate). Given that we are long natural gas (the US market is oversupplied), and the rig count in the Permian basin has been flat for close to year, stronger volumes may not arrive.
The Permian is also struggling with natural gas takeaway capacity. However, some relief is on the way. Recently, Kinder Morgan’s (KMI) west bound El Paso line 2000 has returned to service following 1.5 years being out of service due to an August 15, 2021 pipeline rupture. That repair added 620MMcf/d of additional egress. In September 2023, Whistler will add 0.55Bcf/d in capacity which will fill almost immediately. Beyond that, the next pipeline that will add capacity is Kinder Morgan PHP with a 0.55Bcf/d capacity addition, occurring in December 2023. These additional volumes from PHP and Whistler are too little and too late in the year to drive meaningful overall natural gas volumes in the Permian in 2023.
Moving on to Louisiana, segment profit rose to $105.4MM when you exclude unrealized hedging losses (purple box in figure 1). This is a new record for Louisiana due to strong seasonal demand for NGLs in the winter months, strong margins due to a tight fractionation market and continued strength in the gas segment. Volumes on their systems remained strong in Q1 albeit lower than in Q4:
In Enlink: Set to Grow in 2023, we theorized that recent capacity additions from competing pipelines in Louisiana would cool the growth in natural gas volumes, and I believe we are starting to see that in Q1. Volumes on their gas transportation dropped by 420,000 MMBtu/d helping to deflate the record natural gas segment profits from a peak of $30.1MM in Q3 of 2022 to $20MM in Q1 in of 2023. In addition, many of the marketing opportunities they saw in 2022 won’t be repeated in 2023. EnLink’s outlook for Louisiana given in February showed a segment profit decline of 8% to $345MM for 2023. The strong showing in Louisiana in Q1 shows resiliency. If that resiliency continues, we will see their Louisiana segment outperform that guidance.
Oklahoma benefited from EnLink’s recent acquisition of the Tall Oaks Midcon system which closed in December of Q4. Segment profit (net of unrealized derivative losses) came in at $96.1MM vs. $103.8MM in Q4 (yellow box in figure 1). Although the Midcon system added $4-5MM in segment profit, Oklahoma was affected by lower realized natural gas prices and a $2MM weather event that occurred in December of 2022, causing lingering issues on their system in Q1. Those issues were resolved early in the quarter, so we won’t see the effects in Q2. EnLink is still projecting double digit volumetric growth in Oklahoma based on producer plans. The STACK region has also shown remarkable resilience in the first 4.5 months of the year as operators continue to decommission rigs in other regions to address the oversupplied gas market.
The chart is Baker Hughes (BKR) rig count listed by producing region, and the red font shows the basins where EnLink operates. For example, the Permian is EnLink’s #1 producing region and it has lost no rigs because it is insensitive to natural gas prices. Prices for natural gas can go negative in the Permian, and the producers will still make a profit with crude and condensate well north of $40/barrel (a price where most producers break-even in the Permian).
The chart aggregates the rig data from the various Anadarko sub-basins in Oklahoma, but excludes the Cana Woodford basin (STACK, SCOOP and Merge) which is listed separately. Because Cana Woodford has a higher liquids ratio (more NGLs, crude and condensate) than some of the gassier regions, it is more resilient to lower natural gas prices with crude at $70/bbl+. Also, as the Permian struggles with natural gas take-away capacity and volume growth slows in that basin, drilling CAPEX dollars will remain resilient in some of the Tier 2 basins (Eagle Ford oil region, DJ-Niobrara, Cana Woodford and the Williston). Nearly all EnLink’s Oklahoma segment profit is generated in the Cana Woodford (STACK & Merge) region. They are only marginally affected by the weakness in the greater Anadarko area. However, if oil were to hit $50/barrel (not the base case) and natural gas were to drift below $2/MMbtu, then all bets are off, and the Cana Woodford region would most likely begin losing rigs as we saw in 2019.
North Texas (Barnett) region’s segment profit is forecasted to come in flat YoY in 2023 due primarily to a full-year contribution from the July 1st acquisition of the Crestwood system in the southern Barnett region, and the ongoing new well and refrack activity from their main producer in the region, BKV. We are seeing some weakness in that basin, but that weakness was already baked into the forecast. Segment profit net of unrealized derivative gains came in at $76.6MM in 2023 versus $80.4MM in Q4 (pink box in figure 1). The lower segment profit was driven by lower realized natural gas prices which have a relatively small impact in the Barnett and lower volumes as the relentless decline in that mature basin resumes:
Rigs have come down to 2 rigs from a peak of 4 rigs in early August of 2022. Because the Barnett is a very gassy region, it is sensitive to the weakness in the natural gas market.
We entered 2023 grossly oversupplied in natural gas in North American and the market responded by driving natural gas prices down to $2/MMbtu (Henry Hub). It seems E&P companies are a victim of their own success. Given how many rigs we had running in the various regions at the start of 2023, we were on a trajectory that would have exceeded the nation’s 4 Tcf storage capacity by the end of the 2023 injection season:
The only solution was for producers to either build DUCs (drilled but uncompleted wells) or drop rigs. They chose to drop rigs and by May 12th, 2023, they eliminated 51 rigs, primarily in the gassy Tier 2/Tier 3 basins (greater Anadarko region, Eagle Ford Gas, etc.). The Haynesville has dropped 15 rigs and the Utica has dropped 3 rigs. The Marcellas region hasn’t lost a single rig because the producers in that region are heavily hedged at significantly higher prices. If we see continued weakness in the natural gas markets or if storage fills up prematurely, we could lose some rigs there.
The 51 rigs most likely won’t return until 2025 because we have modest levels of new demand coming online in 2023. The Freeport LNG facility in Texas, which had been out of commission since June of 2022 due to a fire, came back online and the market quickly absorbed that 2.28 Bcf/d in demand with ease. We also have the New Fortress Altimira FLNG project coming online in offshore Texas in July 2023 which will add 0.4 Bcf/d of demand, a relatively small amount. Beyond this incremental demand, there are no new LNG facilities coming online in 2023.
With these macro themes playing out in the North American gas market this year, growth across their overall footprint in 2023 will be modest. We can chalk 2023 to a rest and digest year after the massive 22% run up in EBITDA in 2022. In a future article, we’ll discuss the growing list of projects driving continued growth for EnLink in 2024 and beyond.
Nose Dive in EnLink’s Unit Price Presents an Opportunity
In the meantime, EnLink’s unit price is showing weakness.
Each candle represents two weeks of trading data. You can see we’ve fallen through the lower trendline, a line that has held since early 2020. In addition, EnLink is trading well below its 200-day moving average (yellow line) and the 50-day moving average (purple line) is in a sharp downward slope. Normally, when EnLink’s unit price falls this hard and this fast, it signals the start of a reversal in the trend. The reversal, if it comes, will most likely take several quarters to evolve. With both large institutional investors adding to their positions in Q1 and EnLink continuing an aggressive buyback program, I suspect the unit price will reverse course to retest the highs.
In the quarter, EnLink’s common unit repurchase program scooped up another 2.2MM publicly traded units and an equal amount from their majority owner, GIP. The lower prices in Q2, increase EnLink’s buying power. What is clear from the chart is that at best, EnLink is forming a near-term top with a trading range of 8.46 to 13.58 with pricing essentially moving sideways throughout 2023, although EnLink’s unit price may oscillate between the highs and lows.
Investors can take advantage of the volatility by trimming their position near the highs and buying back at lower prices. Buying more at the lows can be accomplished by selling expensive puts or buying the units outright. Conversely, as we enter the highs, positions can be trimmed by selling calls or selling units outright.
Long term we have a series of LNG terminals that will come online in 2024-2032 timeframe that will drastically increase the need for EnLink’s assets. We’ll save the details of those projects and EnLink’s long-term outlook for the next article. Suffice it to say, EnLink is simply a steal in the sub-$9 price range.