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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For the week, our E&P Index finished -3.4% vs. the S&P500 +2.0%, and WTI -0.9%.
Following EQT’s announcements on Monday (01/13/20), we’re reiterating our Outperform rating as we see new management delivering on its goals of improving asset base performance while de-risking the balance sheet. The Moody’s downgrade did increase EQT’s financial risk, but the operational update was positive as it showed improving asset performance and pushed FCF expectations higher. Additionally, the combination of the proposed debt offerings and the planned $1.5Bn debt reduction (via asset sales/FCF) should have the balance sheet in a stronger position come 2H20. Pricing and size are still to be determined, but we see the potential for this offering and the $1.5Bn debt reduction plan to push back or retire most of the $3.5Bn senior notes and term loans maturing through 2022.
For the week our E&P Index was -5.1% vs. the S&P500 +0.9% and WTI -6.2%. It was a roller coaster week, as WTI went from $63/bbl to $66/bbl within minutes Tuesday night, only to finish Wednesday <$60/bbl and bring out concerns that the next move is to $50/bbl. We’re not of that view and remain positive on crude oil for 2020, so we’d use the periods of volatility to add to high quality names. Top picks remain COP and PE and we prefer Large Cap over SMID Cap.
Reserve reporting season is around the corner and with 15+% y-o-y declines in expected SEC benchmark pricing and lower planned activity, the Northeast producers will be facing downward pressure on reserve bases from PUD writedowns. Last month CVX took a $5Bn+ impairment charge on its Appalachia assets and RRC reported today they expect to take a significant non-cash impairment on its Terryville assets that currently carry a $2.7Bn value. In addition to the expected Terryville writedown, RRC’s YE19 reserves removed 601Bcfe of PUDs due to lower planned activity and 18Bcfe from price declines. RRC’s total reserves increased 1% y-o-y despite these two revisions due to positive performance revisions. In Exhibit 2, we show the PDP vs. PUDs gas reserves split at YE18 for the rest of the gas-weighted E&Ps in our coverage group.
Happy Sunday. The first of a new decade that’s bound to bring a lot of change to the way we think about how energy is supplied, produced, and consumed. It also brings a new way of corporate thinking for the E&P sector, including a 10-year plan (COP) that has real merit to it and a true focus on returning capital to shareholders at a reasonable price ($50 WTI). To this end, we update our sector level and individual company questions for management ahead of conference and 2020 budgeting season that has a big focus on FCF and how capital will be returned to shareholders.
In 2019 Henry Hub averaged $2.53/mmbtu, well below the 2018 average of $3.07/mmbtu and the five-year average of $3.11/mmbtu. While 2019 started off strong with prices peaking in early January at $3.59/mmbtu, natural gas then fell to a low of $2.07/mmbtu in August and ended the year down 26%. The weak price performance was largely driven by increasing volumes from the associated basins, sending a market that was under supplied to an over supplied position. While production growth across the board has slowed, particularly from the Northeast gas producers, the 2020 forward curve now sits at $2.33/mmbtu down 17% from the beginning of 2019. We continue to forecast a near term natural gas price of $2.50/mmbtu through 2021 as the challenge of strong supply growth continues to dampen the upside case for price (ex-weather), but we do believe long-term there is an equally strong 2023-25 demand story driven by LNG exports that could support price above current levels.
For the holiday shortened week, our E&P Index was +1.1% vs. the S&P500 +0.6% and WTI +2.1%.
Over the last twelve months, we asked senior management from 10 E&Ps one question – if your company was private and you owned it, what would you change? We asked the question in person or over the phone, not giving time to get back to us with an answer. Executives spanned across E&Ps with different corporate makeups (large and small cap, single basin and multi-basin, unconventional and conventional), getting an array of answers with some that we liked better than others. We provide each of the answers anonymously inside.
2019 Scorecard Shows Rising Supply And Demand Forecasts. As 2019 winds down, we looked back at the changes in the Wolfe and EIA 2019/20 forecasts, seeing where the biggest moving pieces were relative to our expectations this time a year ago. Starting with the EIA, we show the change in 2019/2020 Lower48 dry gas production estimates in Exhibit 2, with the FY19 forecast revised upward by 2% from 89.9 Bcf/d to 91.1 Bcf/d over the course of 2019, while the FY20 forecast has increased by 3% from 92.2 Bcf/d to 95.1 Bcf/d over the same period. The EIA’s demand forecasts have also been revised upwards, at a higher rate than supply (Exhibit 3), with its FY19 demand estimate increased by 3%, while the FY20 demand forecast has climbed by 5%. Turning to our forecasts in Exhibits 4-7, FY19 supply and demand were revised upward by 6% and 5%, respectively, while our FY20 supply and demand estimates have been increased by 3% and 5%, respectively. Associated gas caused the increase in supply for both years while LNG exports drove the demand increases. Our take from this is that demand is growing faster than supply and if producer outlooks for lower 2020 supply growth come to fruition, this could lead to strengthening prices by 2H20. We remain at $2.50/mmbtu through 2021.
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