For the first time in years, we find ourselves bullish on natural gas price direction. There’s still some <$2/mmbtu pain to go as we enter the shoulder season, but by mid-2020, we see the confluence of rapidly slowing U.S. supply growth and ramping demand normalizing balances and setting up a 1H16-like period, when NYMEX jumped from <$2/mmbtu to $2.75-3/mmbtu within three months. The key to all of this lies in U.S. LNG exports and based on our outlook, we see the U.S. entering an undersupplied position in 4Q20 to support higher prices. Within, we provide our updated U.S. natural gas supply/demand model through 2025.
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PXD reported a solid 4Q update that included a capex beat and delivery on volume expectations while providing a 2020 outlook that’s slightly better than WR/Street on spending and production expectations. Further, PXD continued the dividend trend this week by announcing its second large dividend increase in six months that will bump the yield to 1.5%. We continue to see PXD as one of the best positioned E&Ps with its mix of dividend and volume growth, strong operational performance, low balance sheet, and deep inventory base. Reiterate Outperform.
Yesterday, the EIA Drilling Productivity Report (DPR) provided updated estimates across the key unconventional basins and is finally showing a crack in the rampant pace of natural gas growth over the past two years. In aggregate, the EIA’s updated forecast now shows a -0.1Bcfpd sequential decline from January to February and -0.17Bcfpd estimated decline from February to March. There’s still some growth from the Permian, but the March estimate shows back to back months of decline in Appalachia, with the Anadarko Basin also witnessing declines. It’s equally important to see the Haynesville flattening as well, especially after the 2-2.5Bcfpd annual growth trajectory the basin was on throughout 2019. Directionally, we see the trends as in line with our basin expectations, supportive for natural gas price and perhaps, the start of shut-in volumes in Appalachia. See page 3 for a breakdown of the EIA’s supply growth by region versus our estimates.
For the week, our E&P Index was -4.1% vs. the S&P500 +1.6% and WTI +3.4%.
While natural gas prices continue to fall, US LNG net exports continue to reach new highs. With Cameron and Freeport Train 1 now online, export volumes averaged 8.4Bcfpd in January, up 8% versus the December 2019 average and well above the 2019 annual average of 5.6Bcfpd. So far in February volumes have averaged 8.8Bcfpd as net exports continue to rise in the face of declining global prices. There’s an additional upward bias this year as Cameron Train 2 starts up, but exports need to be tightly watched as it is the only significant source of demand growth and key to balancing out the current oversupply situation. We currently forecast 7.7Bcfpd of LNG exports in 2020, which if hit, would be a big positive for domestic natural gas prices. The next big wave of projects will be in the 2023-24 time horizon, with FID on multiple projects also a positive sign for l-t domestic demand growth.
For the week, our E&P Index was -0.1% vs. the S&P500 +3.2%, and WTI -2.4%. After a brief moment in the sun on Wednesday (2/5/20), it was right back to business as usual for the sector Thursday and Friday as coronavirus fears picked back up again.
While a few more formal 2020 outlooks are still to come, it’s looking more likely that the publicly traded Northeast natural gas producers collectively point to flat volumes from 4Q19 levels. This is a new world for the basin as production has been on the rise since Marcellus activity started in 2004, but it’s the right move to combat the current <$2/mmbtu environment and persistent growth out of the Haynesville and Permian. Further, we believe the Northeast producers should already be thinking about extending the period of flat volumes into 2021 for two key reasons: 1) the world clearly doesn’t need more supply right now, with declining global prices putting downside risk in U.S. LNG export demand and 2) financial positions will weaken from a return to growth as spending would need to rise while 2020 hedge benefits roll off.
Last week we had the opportunity to meet with senior management at PE-backed Indigo Natural Resources, gaining some insight into the Haynesville Shale. It’s a basin that’s been somewhat of a black box in the domestic supply picture as it’s changed hands from public to private operators over the last 10 years, with new technology deployment and advantaged location pushing regional supply towards 12Bcfpd – double 2016 volumes (per the EIA DPR). However, after a multi-year period of 2+Bcfpd/annual growth, we see y-o-y volume gains slowing in 2020, with the rig count decline from 53 to 43 over the past six weeks (per Baker Hughes rig count) suggesting the basin is already starting to feel the impact of the lower price environment. Within, we provide some detail around Indigo and the Haynesville.
For the week, our E&Ps continued to slide, finishing -10.4% vs. the S&P500 -1.0% and WTI - 7.5%.
Driven by a warm winter to date and continuous supply growth, front month natural gas (NG1) price is now below $2/mmbtu and taken the 2020 curve down to $2.11/mmbtu. This is clearly hitting the Northeast producers the hardest, but there’s downward pressure on 2020 cash flow expectations across the sector to varying degrees. We expect this to come out on 4Q updates, particularly for the multi-basin oil producers that have exposure towards the DJ and Anadarko Basins. See page 3 for 2020 natural gas as a percent of production mix/total revenue and percent hedged volumes. COG at 100% natural gas of total volumes is most exposed to price swings as they’re unhedged, a stark difference to natural gas peers AR and EQT that are over 85% hedged. Amongst the oil-focused producers, PE/QEP/FANG have the least exposure to natural gas price from both a volume and revenue standpoint.
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