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  • The Debate Over Shale Oil Reserve Estimates Suggests EOG Resources Might Be A Good Short [View article]
    Dear Michael,

    I read your note with interest. While I do not agree or disagree with you main point that EOG is a good short, I am a bit surprised by the rationales that you are using to support this and other recommendations.

    "Most oil and gas investors have never heard of Jan Arps or seen his commonly-used formula for calculating Estimated Ultimate Recovery..."

    First, even if your assertion were true on its surface, I don't think it is valid in its substance. Well performance, production declines and EURs are typically analyzed and estimated by reserve engineers. It is a large and well established discipline. Suggesting that all estimates are overstated needs some substantiation. Investors do benefit from the knowledge and established practices and analytic standards developed and enforced by the industry. So, in substance, investors not only have "heard" of Arps math, but are routinely using a vastly more elaborate set of methods and practices (even if they do not know about it) when they listen to investor presentations or read 10-Ks.

    It is true, some investors would not be able to perform this type of analysis like professional reserve engineers can (equally, few investors are good forensic accountants). Many investors do not have same access to raw well performance data. However, based on my experience, the majority of energy-focused institutional investors and analysts can understand what stands behind the estimates and can think of these estimates critically. Reading your note, I almost get an impression that steep initial declines from fracked wells is a recent news and that the concept of a decline curve was first discovered in the article in Businessweek from last week that you refer to.

    "My personal view is that the Arps formula produces unreliable results for fracking, and investors should approach the area with caution."

    I wholeheartedly agree that investors should approach any area in investments with caution and avoid judgement based on superficial understanding. However, I do not agree with how you depict the process of estimating reserves (and drilling economics). In practice, this process is not (or, at least, should not be) a simple mechanical application of some mathematical formula - this would be a very simplistic and inadequate view of how the estimation is done by the industry.

    "My approach is buy oil & gas companies with diversified resource bases at prices of 5 to 7 times cash flows and reasonable balance sheets."

    I am surprised you are advocating to pay that high of a multiple. Every situation is different of course, but aren't there many well-established energy companies with diversified resource bases that are trading well below 5 to 7 times cash flows? 7x multiple, in my experience, is a sign of a high growth expectation.

    Just my to cents.


    Apr 6 02:28 PM | 12 Likes Like |Link to Comment
  • Ultra Petroleum Could Double Within 3 Years [View article]

    Thank you for highlighting UPL, they are indeed an interesting company.

    Could you please substantiate your investment thesis a bit further.

    You have singled out UPL among many gas-focused stocks. Wouldn't many stocks double, triple, quadruple if gas prices went to $6? I would also note that many gas companies have been able to increase their production through the recent downcycle (COG, RRC, EQT, SWN, just to provide some names), their stocks have done well. During the same period, UPL has seen its production and stock price decline. Does it indicate that UPL has marginal assets and will continue to underperform in what is an extremely competitive industry with essentially unconstrained supply?

    It appears your thesis is hinged on natural gas price going up to $5 or $6. What will drive it so much higher? Supply and demand appear to have been balanced very nicely for the past six months or so, yet nat gas has been trading between $3.25 and $4.50. There is a view point that there is no shortage of drilling opportunities in natural gas to satisfy even a strong growth in demand. Cost of supply has also been drifting lower, not higher. In a competitive industry, operating margins should be defind by cost of marginal supply, not by demand. What am I missing here?

    What will happen to UPL if nat gas prices stayed where they are (sub $4)?

    Could you please explain your statement: "Ultra Petroleum is one of the low-cost producing natural gas drillers with all-in costs of $3.00 per MCF in 2012?" Are you using a correct/relevant metric? Why did UPL have to cut their production? What nat gas price would it take for UPL to break-even on its cost of capital at the field level and corporate level? Are they really a "low cost" producer?

    I am not arguing for or against your conclusions, I am just trying to understand your thesis.
    Jun 21 09:54 AM | 10 Likes Like |Link to Comment
  • SandRidge Energy: What Are The Assets Worth? [View article]
    JRF77 and Mjtroll1,

    Sorry for the acronyms.

    EUR per well = Estimated Ultimate Recovery per well (a key metric that characterizes expected reserves associated with a well and drives the rate of return on investment)

    HBP = Held By Production (acreage that the E&P operator controls beyond the initial lease term by way of drilling a producing well)

    NGL = Natural Gas Liquids

    PUD = Proved Undeveloped (in conjunction with reserves or drilling locations)

    And indeed, this is article is not meant to be an investment recommendation - just thoughts that I hope will be helpful to readers in developing their own, a lot more comprehensive analysis.
    Mar 4 11:49 AM | 8 Likes Like |Link to Comment
  • SandRidge Energy: Mississippian Well Results Update [View article]

    I agree, 50% IRR would be very attractive, wouldn't it?

    To validate drilling economics estimates one needs to have a very good read on production performance history by individual well. SD has a huge number of producing wells - compiling a reliable production history database is an expensive undertaking. I hope to have an answer soon on that front.

    Another issue is the way the return is calculated. Judging by SandRidge's budget, the play appears to be very capital intensive beyond the drill&complete cost per well. Those "overburdens" must be factored in carefully.

    I am waiting for the analyst day to hear the company's thoughts with regard to potential impact of open hole completions. May help a bit.
    Feb 18 12:15 PM | 7 Likes Like |Link to Comment
  • Halcón Resources: Latest Eagle Ford Well Results (Through January 2014) [View article]

    This means an average reader can know as much as a manger at a resource-rich hedge fund (who can hire a consultant, often for a lot of money, to source this same analysis).

    One month of data does not make a difference (there were no surprises in January), but I hope this note helps monitor the evolution of the play in real time. More updates to come.
    Mar 5 11:09 AM | 6 Likes Like |Link to Comment
  • WPX Energy Trades Below Tangible Book Value, Smart Investors Are Buying [View article]
    Thank you for highlighting the WPX story. The company indeed has an evniable set of assets, particularly in the Piceance.

    Could you please help me understand some of the numbers you have presented in the valuation analysis.

    - The NAV table states that the company has 4.1 Tcf of proved gas reserves. When I look at the latest 10-K (page 135), I only see 3,459 Bcf of proved gas reserves, of which only 2,228 is developed and the rest is PUDs. Further, your NAV attributes a "price" of $1.25 to proved gas reserves. While I can see how one can value flowing dry gas reserves in the Piceance at $1.25 per developed Mcf (although that would probably require $4.25/MMBtu Nymex assumption), I do not see how one would value undeveloped reserves at such a high multiple.

    I also have difficulty matching the NGL number from your NAV table to the 10K.

    Should not the NAV valuation reflect working capital deficit ($71 million at 3/31/13) and non-E&P assets and liabilities? Are those numbers rounded?

    Most importantly, the company had $287 million in G&A costs. If you NPV that, it would be a big number (for illustration, if one were to use a 8x multiple, this comes out well over $2 billion). So unless you are expecting the company to be sold soon - in which case I would question the 10% discount rate for any asset that is not already on production - should not your NAV reflect that fairly material overburden?

    I am not suggesting that the conclusion in the article is right or wrong. I am just having some difficulties understanding the numbers in your NAV section.
    Jun 14 09:38 AM | 6 Likes Like |Link to Comment
  • Bakken: The Downspacing Bounty And Birth Of 'Array Fracking' [View article]

    That's a great point. In fact a great deal of technical information trading does take place. Some of pilot projects have significant non-op interests. Companies also often cross-participate in assessment wells with other operators (have you noticed CLR's interest in COP's Sunline TF2 test?). Moreover, frac companies often help customers in adopting best practices. I am sure there will be a great deal of information dissemination across the play.
    Mar 5 04:00 PM | 6 Likes Like |Link to Comment
  • Marcellus Shale: Giant Well Parade In Susquehanna County [View article]

    Thank you for posting the two articles.

    Just to make sure my article above does not get misinterpreted: when writing on natural gas fundamentals, I explicitly avoid providing any opinion on stocks, positive or negative, since the scope of analysis is different. I do provide stock analysis but solely in research reports that specifically focus on valuation, catalysts, operating momentum, and many other pertinent factors.

    Just a few thoughts with regard to the articles you posted. Mark does a significant amount of numeric analysis, and I respect his hard work. I am afraid in this specific case I have to disagree with some elements of his math and, more importantly, with the well sample I believe Mark is using. If one were to focus on the "recent vintage" wells only (and those, in my opinion, better represent the development mode economics), IP rates are much higher than what Mark is factoring into his assumptions. Please take a look at the 2012 data in my note above. Cabot's average well placed in line in 2012 will very likely deliver over 3 Bcf of production in the very first year (based on Zeits Energy Analytics decline curve), - pretty much a full payout at $3.50 gas. A significant portion of the production beyond that point represents profit. So even if EURs are overstated (which in fact may ultimately prove to be the opposite), the operation should still be profitable simply based on very measurable early production rates.

    The second article, which is entitled "The Danger Zone: Cabot Oil & Gas," sort of surprised me. In fact, the article itself (if anyone even remotely thought of taking it seriously) would be a bit of a danger zone. The author does not seem to fully understand the mechanics of deferred tax liability in Oil & Gas, or the recent dynamics of asset write downs in the sector. The statements: "economic earnings are negative and declining" and "the valuation is sky high" are not substantiated by anything. In general, I was looking for some analysis to explain the title, but I could not find any. The article did time stamp the stock price: $50/share. Again, I do not agree or disagree with the view on the stock price, but I may not be alone feeling short-changed when a recommendation is provided without any substantiation.
    Feb 25 01:02 PM | 6 Likes Like |Link to Comment
  • Does The Marcellus Success Condemn Natural Gas Prices? [View article]

    No doubt, only a relatively small percentage of the Marcellus acreage will end up solidly economic ("sweet spots"). One can also dispute the EURs - not enough history of production - but those wells that produce more than 1.5 Bcf in their first year will likely end up very profitable. And there are many of those.

    The primary reason for the decline in the Marcellus rig count is the inability by the infrastructure to keep up with the upstream deliverability. What's the point to in punching incremental holes while the off-teke has been all spoken for? Rig productivity is also a factor: anecdotal evidence suggests that the same rig count produces 20% more lateral footage than a year ago. Some rigs have migrated to delineate the Marcellus in West Virginia or Utica and other zones in Ohio - often get omitted from the rig count.
    Dec 20 11:20 AM | 6 Likes Like |Link to Comment
  • Comstock Resources - Oil And Gas Turnaround Play With A 40% Upside [View article]
    Drill Capital,
    Thank you for the article and for highlighting Comstock. Their story and valuation are indeed interesting.
    Your $30 price target sounds exciting. Just a word of caution. It appears your DCF valuation relies heavily on the assumption of sustained growth. Implicitly, this approach gives credit for assets that the company does not have yet. As you correctly stated, the company’s core asset in the Eagle Ford has a relatively short inventory life. Production from that asset will go in decline after full drill-out (your model suggests continued growth). I don’t think a DCF approach works well in this situation. A drill-out approach seems to be more appropriate.
    I would also be careful equating the Burleson County prospect to the well delineated, high-return development asset Comstock has in S Tx Eagle Ford. The expected economics for these two situations are drastically different at this point. Just my opinion, but it is a bit pre-mature to call the East Texas acreage a “recently Acquired East Eagle Ford Inventory.” It may become inventory once fully delineated and proven economic. Right now it is still acreage with one producing. This is not just an abstract concept. You are valuing the E Tx EF + TMS at $417 million, while the company paid less than $120 million for these two prospects (a winning bid in both cases) just a few months ago and has not drilled a single well yet. I wonder, what drives the instantaneous $300 million value gain? At minimum, I would think of this valuation as a range.
    Just my 2 cents, or whatever it’s worth : ).
    Again, thank you for the interesting, thought-provoking article.
    Mar 29 01:50 AM | 5 Likes Like |Link to Comment
  • Carrizo Oil & Gas: Oil-Focused Portfolio With Assets In All The Right Places [View article]

    I find a comparison to PXD and EOG a bit difficult. EOG has very low well costs and, allegedly, a cutting edge in completion technology that produces better wells on average. That is worth something. PXD has a vast drilling inventory. I would need to do the work to put some metrics on those factors.

    By contrast, Carrizo's "story" looks more execution-driven. The company does not seem to have a massive drilling inventory but they have enough for now and their operating track record is strong. The company has done a great job securing a sweet-spot presence in the Barnett. A decade of drilling experience in the Barnett should count for something. Now they are building position while operating. So far results are good.
    Nov 22 01:48 PM | 5 Likes Like |Link to Comment
  • Halcon Resources: Eagle Ford And Utica Promise Upside [View article]
    Send in the clowns,

    Thank you for the color. Very valuable.


    Oct 7 04:33 PM | 5 Likes Like |Link to Comment
  • Marcellus, Mississippian, Permian: What Is The Acreage Worth? - Economic Analysis [View article]

    Sorry if I have caused any confusion. Let me try again. I think of the "shortfall" as capital needs in excess of internally generated cash flow; for the entire year it can be as high as ~$3.5 bn (that was my read from the call based on updated cash flow guidance). The $135 million in net proceeds from the divestiture of Marcellus properties is ~2.5% of the midpoint of CHK's total target for the year ($5.5 bn). Hence, the amount is "hardly enough to move the needle" in the context of this much larger asset sales target. Am I wrong?

    You are absolutely right, the company has made progress in generating proceeds from property sales and I am sure will report more transactions. I really don't think the sentence you are referring to contains anything to contradict that (certainly was not meant to).
    May 8 12:06 AM | 5 Likes Like |Link to Comment
  • Marcellus Shale: 10 Bcf Per Day In 2013 [View article]

    I very much agree, however the takeaway capacity limit has proven to be a rapidly moving target. 10 Bcf/d is a significant volume to accommodate.
    Mar 11 09:15 PM | 5 Likes Like |Link to Comment
  • Marcellus Shale: Giant Well Parade In Susquehanna County [View article]
    Just to add two cents to Fossilfuel's very valid comment. Mark's analysis seems to mix together Cabot's various plays and does not seem to reflect the timing of well tie-ins (just imagine that all the wells came on production at the end of the quarter - only a fraction of production rate would be captured by Mark's formula). Consequently, the result is "noisy" and should be interpreted as such. Mark is also effectively using an exponential decline curve for the early portion of wells' production trajectory - I don't think this is a good mathematical approximation. Many wells actually ramp up their volumes as they "clean up," plateau for some time if on a restricted flow, and then decline hyperbolically. So Mark implicitly defines the "IP" and then uses it in his further analysis, again leading to "noisy" results. Mark seems to be using a simple exponential formula - a big assumption generally not supported by empirical data. Finally, I would focus the analysis on well IRRs (or IRRs at the project level), not earnings - I think of E&P as an NPV-based business.
    Feb 25 05:52 PM | 5 Likes Like |Link to Comment