The most recent round of earnings calls yielded few significant changes to 2019 production guidance. Among the firms we track, EQT made the biggest change, raising its projected output by just 30 mmcf/d (1%) from its original projection. Production of 35.8 bcf/d in Q1 19 in our sample was up y/y (+3.1 bcf/d, 10%), though it lagged the EIA’s figure for total US growth, including from E&Ps not in our sample (+9.9 bcf/d y/y, 13%). This points to continued output gains from private firms. Our subset of publicly traded E&Ps committed to capital discipline in 2019, with several (including EOG, Gulfport, and Noble) emphasising that they would not overspend previously budgeted Capex. Growth q/q from our survey was 0.2 bcf/d (0.5%) and low Waha gas prices caused by Permian takeaway constraints led to shut-ins early in Q2 19 that could stifle growth next quarter as well.
Our sample of producers only increased their Cal 19 hedges from 60 to 63% q/q as the year 2019 was already well hedged. The weighted-average swap price was $2.89/mmbtu, a q/q decline of $0.09/mmbtu. Cal 20 hedges saw even smaller q/q gains as projected production hedged only grew by 2 % q/q from 25% to 27%, a y/y decline of nearly 10 percentage points. The weighted-average swap price for Cal 20 was $2.88/mmbtu. The slow rate of hedging could be the result of producers’ willingness to wait for higher prices before executing further hedges.
Production results and 2019 guidance updates
The most recent round of earnings calls from US gas producers provided little in the way of guidance changes. Most companies are keeping output projections for 2019 in line with the initial expectations provided at the start of the year (see Insight: Q4 18 results – A well hedged year, 7 March 2019). In Appalachia, only one of the seven major producers we track in the region moved guidance, as higher-than-expected production in Q1 19 led to EQT upping its 2019 production projection by 30 mmcf/d (1%) over its initial 2019 estimate. That subsample of Appalachia producers, which represented 13.3 bcf/d of regional output in 2018, is guiding for growth of 1.1 bcf/d y/y in 2019 (see Fig 1). The 8% gain from these producers lags our projection for growth from the full region, as our balances point to 2.7 bcf/d of uplift (10%) y/y in Appalachia from a 28.3 bcf/d baseline.
The trend of our sample underperforming the EIA’s figure for overall growth is not limited to Appalachia production. Our full sample of 51 of the country’s largest publicly traded gas producers stood at 35.8 bcf/d for US production, which was up by 0.2 bcf/d q/q (0.5%) and by 3.1 bcf/d y/y (10%). Q1 19 gas production in the US was 89.1 bcf/d according to the EIA, with growth of 1% q/q and 13% y/y. This is the fourth straight quarter in which our sample trailed the country’s total increase, highlighting the significant volumetric contributions now coming from private producers.
Production from firms not in our survey, of 53.3 bcf/d in Q1 19, was up by 0.7 bcf/d q/q and 6.8 bcf/d y/y, and is largely representative of the gains made by smaller E&P and private firms. Ascent Resources is indicative of this trend. The private equity-backed producer detailed its 2019 guidance in a late Q1 19 press release, which called for gas output to rise from 1.25 bcf/d to 1.85 bcf/d y/y for full-year 2019. In the press release, Ascent Resources outlined plans to use the acreage purchased from CNX Resources in late 2018 and to increase lateral length in its Utica holdings to improve per well production rates. Including Ascent Resources in our subsample of key Appalachia producers would bring the subset’s estimated 2019 growth to just over 10% y/y, in line with our regional balances.
|Fig 1: Select Appalachia E&P guidance, bcf/d||Fig 2: Total US gas production, bcf/d|
|Source: Company websites, Energy Aspects||Source: Company websites, EIA, Energy Aspects|
Private producers do not face the same investor pressure to rein in spending as the publicly traded companies in our sample. Public E&Ps have been under pressure from shareholders to maintain capital discipline, with several reiterating their Capex guidance despite improving production economics on the back of high oil prices. While key firms such as Gulfport, Noble Energy, EOG and WPX committed to such restraint, we note that they did so after just one quarter of 2019 was complete, leaving plenty of time left in 2019 to reverse course on fiscal discipline and blow past previous spending guidance. Indeed, Gulfport’s insistence that it would not exceed its originally budgeted $600 million Capex for full-year 2019 came after it exceeded its Q1 19 budget of $250 million by $40 million.
Noble Energy’s projected spend of $2.5 billion in 2019 assumed WTI oil prices of $50/bbl. Even as WTI futures for the remainder of 2019 are over $60/bbl at the start of May, the company reaffirmed its spending guidance for 2019 and said it remains focussed on reducing its capital intensity. EOG likewise reiterated its initial projected 2019 Capex, of $6.3 billion. EOG’s gas production of 1.0 bcf/d in Q1 19 was up by 18% y/y, putting the company on pace to match its production guidance calling for 16% y/y growth.
Cost control was also an issue for firms that went through recent divestitures and acquisitions, even as such moves have limited total production. Chesapeake will only run three rigs for its natural gas assets in H2 19, down from an initial plan of five rigs, as it focusses spending in its newly acquired Eagle Ford properties while moving away from the Haynesville and Marcellus. Chesapeake’s Q1 19 gas production of 2.02 bcf/d was down by 0.43 bcf/d y/y. Encana’s earnings call concentrated on its cost reductions of $1 million per well (13%) in the Anadarko assets it acquired when it bought Newfield Exploration in 2018. The cost reductions are to be achieved through improved cycle time via higher pump rates, and by self-sourcing sand and chemicals. Encana’s production in the region has not been helped by its cost-cutting though, as its US assets produced just 0.37 bcf/d in Q1 19, lower than the 0.54 bcf/d that Newfield Exploration’s Anadarko acreage and Encana’s existing Permian assets produced combined in Q1 18.
Looking ahead, infrastructure bottlenecks are likely to put a damper on Permian production in Q2 19 after Waha prices went negative in early April. Chevron, Matador and Apache all noted early Q2 19 shut-ins of gas production. Apache noted that deferrals cost it 0.23 bcf/d of gross wellhead gas at Alpine High in April, and that even after it brought production back online, it was giving the gas away, receiving prices close to $0/mmbtu. Chief financial officer Stephen Riney noted on Apache’s earnings call that Alpine High ‘is an enormous rich gas play and the key to value creation is full recovery and monetisation of the NGL stream’.
All three companies mentioned price relief at Waha would likely not arrive until the scheduled start-up of Kinder Morgan’s 2.0 bcf/d Gulf Coast Express (GCX) pipeline in Q4 19. While Q2 19 output will likely see a dampening effect from the Permian shut-ins, our balances do not show discernible growth from the basin until GCX comes online. Much will depend on how timely GCX enters service and how quickly it fills once it is running. With flaring in the Permian already above 0.5 bcf/d as producers find workarounds for permitted volumes and the potential for local demand to account for a larger share of regional output, producers may not be in a rush to fill GCX’s total capacity as soon as possible.
Hedging and financial outlook
The percentage of production hedged for balance of 2019 increased as Q1 19 drew to a close. From our sample of producers, 63% of projected 2019 production has been hedged, a q/q increase of 3% and a y/y increase of 7%. The small increase q/q was expected as we had noted 2019 was already a well-hedged year thanks to the late Q4 18 price rally (see Insight: Q4 18 results—A well-hedged year, 7 March 2019).
Nevertheless, on a y/y basis, the much higher percentage could also be driven by producers expecting the base of production to be higher y/y and are therefore shielding more production from downside price risks.
The volume-weighted average price for 2019 swaps was $2.89/mmbtu, a q/q decline of $0.09/mmbtu. The fall in price came mainly from Antero monetising some of its hedges in the last quarter, dropping its average swap price from $3.41/mmbtu to $3.34/mmbtu. Antero is still the producer with the highest hedged price of the sample and its production remains 100% hedged as new hedges were executed to replace the old ones. Additional hedges at lower prices by Cabot Energy also contributed to the lower weighted-average price. Cabot Energy’s percentage of production hedged increased from 25% to 30% q/q, with its swap price falling from $3.16/mmbtu to $2.84/mmbtu.
In addition to swaps, nearly half of our sample producers also engaged options structures, such as costless collars in particular, to protect cashflows. The weighted-average floor price was $2.55/mmbtu, and the weighted-average ceiling price was $3.24/mmbtu. Matador still has the most bullish Cal 19 price view q/q, with a ceiling of $3.80/mmbtu, while SM Energy is still on the opposite side of the spectrum with a ceiling price of $2.83/mmbtu. From the downside perspective, SilverBow has the highest floor price of $3.12/mmbtu while Comstock Resources has the lowest floor price of $2.47/mmbtu.
Based on the current Cal 19 price of about $2.67/mmbtu and the hedged levels for the producers from our sample, all of the producers’ hedges are in the money. The producer with the lowest Cal 19 hedge price via swaps is Encana, locking in a price of $2.75/mmbtu.
As for Cal 20 hedges, 27% of projected 2020 production has been hedged, a q/q increase of 2%. Still, only approximately half of our sample has entered some kind of swap or options transaction. With only 27% of production hedged, it is lower than 37% hedged at this point last year. This much slower rate of hedging is surprising given the Cal 20 swap price has not fallen from the start of the year. Throughout Q1 19, the Cal 20 futures strip was bound between $2.60-2.80/mmbtu, with prices trading near the upper range for most of the period. The weighted-average price of swaps was $2.88/mmbtu, a q/q decrease of $0.01/mmbtu. We expect the hedging percentage to pick up next quarter as Y+1 production is usually hedged by at least 50% by year-end.
Antero and Comstock Resources lead the pack, with the highest swap price of $3.00/mmbtu, while the average price hedged (excluding those two producers) was $2.84/mmbtu. Also noteworthy is that CNX is the most well-hedged producer for Cal 20, at 88% of projected production hedged, while Antero, which typically hedges 100% of its production, only has 59% of its projected 2020 production hedged. As for options hedges, only five producers reported having entered some kind of collar structure, with an average floor price of $2.52/mmbtu and average ceiling price of $3.12/mmbtu.
|Fig 3: 2019 hedging positions, mmbtu/d|
|Source: Company websites, Energy Aspects|