Deep in the SEC rules on oil and gas company reporting requirements and standards is the section that talks about disclosing “the standardized measure of oil and gas” (aka SMOG).  It’s a simple, if not more controversial topic than I ever would have expected, but it’s important when it comes to relative valuation and the ability for investors to assess the merits of the announced and soon to be announced deals. Those who push back on my “simple approach” to using SMOG say three things.

1.  Reserve auditors work for the company and are pushed to overstate.  True BUT all companies are subject to the same rules so as a relative value indicator, there remains merit.
2. You can build your own model and get a better value.  True BUT your assumptions on capex, opex, working interest, NRI, timing, type curves, yields and spacing are all wrong.  Isn’t it better to rely on what the company says?
3. I hate the word SMOG.  It’s dumb.  True.

But, as it is SEC required, we can expect to see it and we should use it to the best of our ability if we want to own (or short) oil and gas shares.  To me, one of the “great elements” about SMOG is it fixes price.  For many years, engineers and planning analysts have gamed the internal “force and rank” project screening criteria by adjusting on production dates to match higher prices in the future months and make it about price, rather than relative value.  As a result, the SEC requires that companies use the first day of each month… January 1, February 1 etc…. for the trailing 12 months and take the arithmetic average.  Last year, prices were roughly $55.27/bbl and $2.57/mcf.  This year…. they won’t even be close.  According to NSAI, here are the prices that will factor in this year:

With two data points left this year, the YTD average is $45.73/bbl and $2.15/mcf.  Although I have made the case since March that I felt oil would finish the year at $35/bbl and gas at $2.75/mcf, using today’s strip price for the November 1st and December 1st, would yield $44.59/bbl and $2.30/mcf.  When it comes to reserves management, let the games begin.

Where operators DO have discretion is in choosing operating costs (OPEX), capital costs (CAPEX), differentials (NGL, HH and WTI) and to a degree, what type curves they assign.  All this is done working within the rule which is along the lines of: use the average of the last 12 months, unless there is a reason to not… and if ever there was a year where the case will be made only to use capex from the last 2-3 months of the year, this is the year.  So when you look at those prices, gas $0.25/mcf lower than 2019 and oil $10+/bbl lower, there is not doubt PUD reserves are coming off.  The question is: how many?

Without getting into the complications of the 5 year rule, companies know they have a problem, and I have made the argument that in some part, it has driven the timing of the recent mergers.  Even IF reserves are “economic” (meet a 10% AT ROR at the flat price deck), their contribution to the PV-10 of the company will be minimal.  To get around this, companies will push CAPEX  and OPEX as low as possible to make commercial assumptions that help contribute to the PV-10.  But regardless, it will be ugly.  DUCs will make up the bulk of the undeveloped PV-10 because they don’t require drilling costs, and no matter what you assume on OPEX, PDP values are going to take a substantial hit as all that excess price goes straight to profit, with no incremental marginal cost.  Equally important will be that at $45 and 2.30 vs $55 and $2.55, economic cut offs will occur sooner in a wells life and materially impact the “reserves” number (less so the PV-10 due to timing).

It’s boring and nuanced, but a lot of companies are spending a lot of time on it, and come February, I’ll be breaking down the YE20 SMOG values less debt / share and trying to find out where, if anywhere, the value is for investors in 2021.  I’m not hopeful.