Underlying Shifts in the Natural Gas Market

Includes: GAZ, UNG
by: Papa Roach

It is often said that time heals all wounds, and this likely is applicable to commodity markets as well. The phrase used is “the cure for high prices are high prices; the cure for low prices are low prices”. No doubt, the North American natural gas market continues to baffle many investors for the continuity of low prices in an environment where every asset class and commodity has experienced large gains over a long term. I have even heard some say it is being “manipulated”, the M word that usually defines someone who is upside down in a market they do not fully understand, lashing out rather than properly educating themselves on the particular market in question.

The ongoing technology shock experienced in natural gas (hydraulic fracturing of shale, releasing large quantities of previously unproduceable gas) has been the main driving force behind a near three-year bear market, and we all continue to learn more each day. There are many underlying dynamics behind the large production growth of the period, some of which I will discuss. The main factor, however, has been a massive supply expansion into a market that has experienced very little in the way of demand growth, thus creating an oversupply situation with very little in the way of immediate demand side solutions. I do believe that things are finally starting to shift, slowly.

Looking at rig counts, we are seeing an ever-so-slight decline in gas rigs over the past several months, nothing material when looking at it as a whole, however, what is important now is where these rigs are drilling. The rapid drilling pace to fulfill HBP requirements in the prolific Haynesville shale play are indeed being completed and these rigs have been migrating out to other plays at an increasing pace, the drilling activity peaking in April and May of 2010 and now down roughly 25% from the highs and declining. Many of the rigs that have left are drilling in other plays for HBP purposes as well, securing the giant land grab these players executed over the past several years.

As I have previously written about, the massive supply growth experienced over the past couple of years is largely the result of a forced behavior to fulfill mineral lease contractual obligations. It is called HBP drilling (held by production), where the lease holder is required to drill a producing well within a set time frame, usually 3 years. This has dominated the drilling space and left almost no room for rig discipline; if you don’t do HBP drilling by a certain date, you may lose your lease (lost capital outlay), and have to renegotiate a new term or pay additional capital to extend if the mineral owner agrees.

Most of the Haynesville acreage was leased in 2008, meaning the initial three-year term is over this year; since it takes time and equipment to cover such a large area, there has been a steady drilling program in place now for the past couple of years to complete regardless of commodity price. Once a section (640 acres) has been HBP’d, that lease hold is held perpetually and pad drilling of additional wells have no time limits. This alone will allow the companies to exercise drilling discipline in the future where commodity price dictates drilling rather than being a forced behavior (drill it or lose it).

Not all shale is alike, and none are as prolific as the Haynesville (yet). Looking at the type curves for the other plays where these rigs are migrating to, the IP (initial production rate) is much lower and the EUR (estimated ultimate recovery) is much lower as well. The rapid growth experienced in supply from the HBP operations in Haynesville will not be repeated with these other plays. Haynesville IP rates are roughly 14 MMCF/day and decline an average of 75% in the first year, (much of that in the first six months). IP rates in these other plays are averaging under 5 MMCF/day and have a steady decline in the first year as well, meaning it takes roughly 3-4 new wells or more brought online to equate to a single Haynesville well on average.

Below is a good example of a type curve for Haynesville and Fayetteville, illustrating the stark differences:




Reading through company reports and guidance, many companies are now targeting the liquid rich and oily plays due to better economics than dry gas shale. What is important to understand here is the difference in top line reported production and bottom line dry gas. When a well in a wet play produces say 5 MMCF/day at the wellhead, the wet stream gets sent to processing to strip out the liquids, making it within pipeline quality specifications. As the stream is processed, it shrinks in quantity of BTUs and can be a substantial percentage of the initial wellhead volume in some cases, so 5 MMCF may ultimately become 3.5 to 4 MMCF of pipeline gas. I feel this will become more important to the overall supply side going forward as more drilling is directed towards liquid rich plays and away from dry gas (the dry gas reported production data point that many have paid little attention to will gain more importance to what the true market supply is).

The top line production levels have finally leveled off from the long steady gains experienced over the last several years as well, even as rig counts have remained somewhat steady to slightly declining. This is what I believe is also evidence of the rig migration and Haynesville decline dynamics setting in. As of 2/24/11, Haynesville had 1,036 producing wells, meaning to keep a steady level of production from the play, you need an increasing number of new completions to stem the natural decline curve. It is still possible we see some more near-term supply growth from the play; however, I do think at these lower price levels we will soon see some sort of overall decline from the play until prices dictate an environment for pad drilling (additional wells on sections already held by the first well, not a forced behavior). In doing some background research, I stumbled on this interesting comment from a blog on Haynesville:

Reservoir engineers call shale play declines "power law" declines. Extremely steep during the initial phase where the gas produced is that of gas in the fractures. Then once that is depleted, the exposed surfaces of the fractures absorb the gas at a slower but steady rate, thus the decline 'curve' turns the corner very quickly so to speak. If it turns the corner at very low rates it may still produce for 40 years but the NPV (net present value) of such production is nigh zero.

There is also something we observed in the Fayetteville...namely, the fractures may interconnect and we have places where the initial well has the highest IP and EUR but each succeeding well appears to have already been partially depleted... in other words, one well could produce most of the gas from all the wells

In Arkansas the B-43 rules allow for 16 wells per section. In my humble opinion, they will need no more than 8 full cross section wells to deplete the wells. IF true, then McClendon's estimate of 30 BCF of gas per unit is likely much closer to 12 - 15 BCF. The Haynesville should produce more gas than that however. Both the (original) Barnett and the Fayetteville are marginally profitable at current prices.

I will not pretend to be a petroleum engineer here, but this comment is rather indicative that we are all still on a learning curve of shale plays and their dynamics. Nothing is yet written in stone and we must still step out of the box and allow for different outcomes to the initial shocks and expectations of a perpetually hyper-supplied market.

Looking at the recent price environment, what peaks my interest is how extremely bearish this market is, not only on the front end, but on the entire forward price curve. What I find noteworthy in this bearish environment is the action of price when we get under $4.00. It seems to easily achieve sub $4.00 pricing with each failure of rally attempts, however, it runs out of new sellers at each and every attempt to breach the $3.80 level. This is not a recent development either, this $3.80 level was the floor pricing last spring as well and was only broken in the fall with an expected warm winter forecast (that ultimately busted).

It appears that market participants are unwilling to increase short interest under these levels, at least for now, but are more than willing to hold on to the already established short positions and sell further into rally attempts. Additional shorts under these levels appear to be what some say is “attempting to pick up pennies in front of a steam roller”.

Touching on demand, as of this writing, natural gas was trading at a -17% discount to the same day last year, and CAPP coal is trading a +21% premium to a year ago. While this will not remain static, it creates a favorable economic environment for coal to gas demand in the power stack. Coal has some bullish fundamental shifts this year: increased demand overseas, large scale flooding problems in Australia and other mining issues in several other countries.

Unlike natural gas, the U.S. has the ability, and indeed, exports coal abroad when prices dictate favorable economics. While I do not trade coal in any form, it appears there are some year-over-year bullish factors for coal that may keep it at a premium to last year’s pricing for some time to come. It also appears evident that industrial demand has had some upticks in the last year, some of which are likely due to the huge discrepancy of natural gas pricing in the U.S. vs. prices in Europe and Asia, giving some local industry a base load fuel advantage for some products.

The next several years will also experience coal generation retirements and gas-to-liquids technology projects. I am only touching on these subjects lightly here, however, demand will increase - especially with the large global pricing discrepancy. One last point for demand as well, we are entering a cold phase of the PDO, a long term weather phenomenon that has implications for a colder phase for our weather in the next few years. Anyone interested in this should do their own research on the PDO (Pacific Decadal Oscillation). This would increase our winter heating loads and potentially create larger overall winter draw downs in storage.

Bottom line, I think we are at/near the end of the almost three-year bear market in natural gas prices. This market miraculously dodged a couple of lethal bullets over the last year with bullish weather outcomes that were able to largely avoid an absolute price meltdown. While we haven’t experienced decline setting in at this present time, I do think it is approaching soon; it will start out subtle and increase with time as these plays are being shifted around further. While this may not be outright bullish in the here and now, I do think it’s becoming futile to remain outright bearish in a script that is nearing the end of the program, especially at the lower price range; risk/reward is reversing in a seemingly endless sub $4.00 environment.

The biggest opportunity I see is the overly-depressed curve that is extremely flat in price on a historical basis. I see value looking out to 2012 futures and beyond as risks of flattening to decreasing supply coupled with increasing demand start to price risks back into the market. I don’t expect this market to change overnight, hit the ground running and never look back. However, as legacy positions start to shift around, there will likely be decent volatility at times and some larger moves in forward spreads as shape re-enters this market to some degree.

The two largest headwinds at this point are the economy and a cooler than normal summer. This “expanding” economy baffles me at times so I won’t attempt to go there. The current summer outlook is for a warmer than normal summer, but then again, we had a very warm winter forecast too. So busts happen. I just hope not in a back-to-back fashion.

For those that trade in the world of equities, scaling into longer term E&P companies will likely reward quite well as energy commodities track higher. I would take a look at a combination of these as a basket: CHK, HK, STR, QEP, UNG, SD, XOM, CVX, DVN, EOG, MMR, PXP, ECA, SWN, RRC, APC, BP, BHP, EPD, EP.

As an afterthought, I would highly recommend reading the latest transcript from Chesapeake Energy, focusing on Aubrey McClendon's comments:

Number six, finally, we believe that drilling for natural gas in North America will continue to decline during the remainder of this year and in 2012, especially once acreage in many of the large natural gas shale plays becomes held by production or HBP, especially in the Haynesville.

We estimate that the marginal cost of gas supply in the U.S. is around $5.50 per Mcf. Today, drilling economics are being largely ignored as the industry races to hold acreage acquired in the great shale gas landgrab of 2008. As that HBP process comes to an end this year, we believe that natural gas production growth should stop until prices settle in at a long-term price range of $6 to $7 per Mcf. There's one more factor here at work that I'd like to highlight.

And I think we can agree that there's almost unanimous consensus among investors and analysts in North American natural gas prices will never increase above a certain long-term ceiling price. For some of you that's $4.50 per Mcf, for others, that's $5 per Mcf and perhaps for others, it's $5.50. We certainly understand the reason for this low current ceiling price unanimity. However, I'd like to remind you that Chesapeake, along with virtually every other natural gas producer both big and small, in both public and private, is responding to the huge return on investment gap that exists between drilling oil wells today versus drilling natural gas wells and we are responding by transitioning our drilling programs as rapidly as we can from gas to oil. To remind you the obvious, we can drill a natural gas well and receive around $4 per unit of production or we can drill an oil well and receive around $15 per unit of production.

We believe that once the industry drilling rigs move away from natural gas plays. To oil rig plays, oil plays for the rigs will be drilling wells that produce $15 units in a much more competitive rate of returns, we think the natural gas curve will have to increase to make natural gas drilling competitive with oil well drilling. I do find it curious as investors and analysts believe that somehow, a potential increase in natural gas prices from, say, $4 to $5 or maybe even a $6 per Mcf will somehow bring those rigs back from drilling oil projects where the revenue level will be $15. I guess, today, I should say, $16 or $17 per Mcf. So to me, this is the greatest misconception about the natural gas market today that somehow an increase of $1 or $2 per Mcf in the price of natural gas in the years ahead is going to create a sufficient financial incentive to cause the return of hundreds of rigs from drilling and more valuable oil plays to drilling in less valuable natural gas plays. I can assure you that it will simply not happen without a substantial rise in natural gas prices.

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.