Today’s report (week ended 7 June): EIA net change: +102 bcf, EA: +103 bcf
- Today’s print confirmed the looseness in balances that led the market to miss consensus forecasts in the previous two reports. While our estimate was within 1 bcf of the latest EIA-reported injection, our model recalibration following last week’s miss had rendered our balances 1 bcf/d looser to meet today’s figure. This suggests production is running higher than flow models and there is some degree of demand underperformance.
Next Thursday’s report (week ending 14 June): EA preliminary: +102 bcf
- Production will be up by 0.1 bcf/d w/w and power demand is forecast to be 0.3 bcf/d lower w/w, rendering our estimate for next week in line with this week’s report.
Production strain in Haynesville
The path to an end-October 3.75 tcf carryout is being paved by production growth, which has been up by an average of 6.3 bcf/d y/y so far in Q2 19. However, that strong output may be at risk. Sequential gains in some of the country’s largest basins have stalled this quarter. The focus for this trend has been Appalachia, where firms are targeting liquids-rich acreage amid low gas prices, and the Permian, where gas growth is constrained by a lack of pipeline capacity. Another basin in flux is the Haynesville, where receipts peaked just below 7.0 bcf/d in our pipeline flow sample in February but have declined by 0.1 bcf/d m/m in every month since.
Among public producers, the decline in Haynesville production has been expected given the guidance that was announced at the outset of the year. Foremost among those reducing their Haynesville investment is the region’s historically dominant company, Chesapeake. After drilling 30 wells in the basin in 2018, Chesapeake only plans to drill 19 this year. The company also took off one of the two rigs it was operating in Haynesville in H1 19.
Not all publicly traded firms have as sour an outlook on Haynesville. This week news broke that Comstock, already one of the largest public exploration and production companies (E&Ps) in the basin with 0.23 bcf/d in production in 2018, had agreed to a $1.1 billion acquisition of private Haynesville player Covey Park. According to well-level data, Covey was the fourth-largest producer in the region in Q1 19 (behind Indigo, Chesapeake, and Vine Oil and Gas) at 0.6 bcf/d.
Even before the Covey Park purchase, Comstock was already honing its focus on increasing Haynesville output. In its initial 2019 guidance, the firm called for a 50% y/y increase in regional output. Comstock is one of the few companies to see an increase in its approved permits for drilling in its Haynesville acreage so far in 2019, from up by 5 y/y to 32. The company is one of just three of the top 15 permit holders to see a y/y increase in permits in the first five months of 2019. It added a fifth rig in the basin in early June to help reach the 1.3 bcf/d midpoint of guidance for Haynesville production it set when announcing the merger.
|Fig 1: Approved Haynesville permits||Fig 2: Haynesville wells completed|
|Source: Drillinginfo, Energy Aspects||Source: Drillinginfo, Energy Aspects|
Comstock is likely hoping to use its expanded acreage to add to its overall lateral length and improve the vintage of Covey Park’s existing wells. Across Haynesville, private wells that came online in 2018 produced only 60% of the volume that those owned by their public rivals did during their first 12 months of operation. But, whatever advantage public producers gain from higher well productivity is undone by their lack of investment. Less than 20% of the 750 completed wells in Haynesville since the start of 2018 are the property of public corporations.
The recent gains from Comstock have not been enough to reverse a long-term decline from the share of Haynesville production captured by public E&Ps though. Chesapeake’s regional output was down by 75 mmcf/d y/y (9%) in Q1 19, according to its most recent 10-Q. Well-level production data point to declines continuing in Q2 19 for Chesapeake, ExxonMobil and BP (when accounting for BHP’s assets that BP acquired in late 2018). This matches our flow data pointing to small sequential declines in regional receipts.
Private producers have accounted for 59% of Haynesville production so far in 2019, up from 51% over the same period in 2018. The 2019 figure would be 56% but for QEP’s divesture of its Haynesville assets to private-backed Aethon late last year. Still, that shift points to investments private firms have taken in the basin, even beyond the major acquisitions such as Aethon’s. The largest Haynesville producer as of Q1 19 was Indigo at 1.0 bcf/d, overtaking Chesapeake, while Vine is third at 0.8 bcf/d (+0.5 bcf/d y/y). Aethon is now the largest permit holder in the region, with 73 permits approved so far in 2019 as it seeks to put the QEP acreage to work.
The looming question for whether the current Haynesville trend of stalled production continues is the ongoing slump in US gas prices, with contracts for the remainder of the injection season hovering in the $2.30s/mmbtu throughout this week. Industry-wide interest in investments to spur production is likely to be muted in the face of a Henry Hub curve with such limited upside. Permitting data shows that even the largest private producers are bracing for cutbacks. Indigo’s 25 approved permits are down by the same amount y/y, while the largest overall drop in the region is from private player Tanos Exploration, from 48 to 12 y/y. Low gas prices might also hurt new investment for private equity-backed E&Ps that need additional capital for the expansion of operations.
Of course, stagnant monthly production has not been able to stem the relentless pace of storage injections so far this spring. Every full week in May posted a triple-digit injection and 2019 has seen three of the five largest weekly injections in EIA history. Today’s report was in line with our expectations and the data are hinting at a structurally loose set of balances. Lower gas prices are doing some work in lifting power burn in the absence of weather, with a projected 32.2 bcf/d burn on 11 June. However, the 15-day forecast from this morning’s run only shows one day in the period (21 June) warmer than the 10-year average. At this point, our 3.75 tcf end-October outlook remains and a shift to warm weather in the 15-day forecast would be necessary to see a move above the current trading range.
|Fig 3: Weekly EIA storage change, bcf||Fig 4: Weather normalised y/y balances, bcf/d|
|Source: EIA, Energy Aspects||Source: EIA, Energy Aspects|