Admittedly the Utica has come with great hype and promise. Upon the release of Ohio’s 2012 production figures, many pundits were disappointed.  Seems many are convinced that it has not lived up to its billing.  They apparently had hopes for a huge oil bonanza here and were quite disappointed at the purported oil/gas ratios.  But is there really enough data to definitively form opinions, and is the data being interpreted correctly?  Let the debate begin.

Reuters was among the first and most vocal in condemning the Utica.  Their headlines included such as “Ohio’s Well Data Shatters Shale Oil Hopes” and “Is Ohio’s Secret Energy Boom Going Bust?”  They seemed genuinely delighted in proclaiming its demise.  Others were quick to follow suit.  The criticism was pretty well summed-up by the Motley Fool whose headline read “Is the Utica Just Full of Hot Air?”

It seems the disappointment lies in the interpretation of the data and the expectations for the play.  It may never rival the Bakken or the Eagle Ford, but those are some incredibly high standards.  Fact is, Aubrey McClendon and CHK are not the first to over-hype a new play and they certainly won’t be the last.   It is common practice in the industry, both to court investors and to prop up stock.  It’s not all propaganda either.  Areas disappointing thus far may still be productive…..technology to extract the volatile oil to the west is still being developed.  I am of the opinion that they did not so much intentionally misrepresent projections, but rather misjudged the type and quality of such.  One man’s crude is another man’s condensate.  More on that later…..

ODNR’s 2012 Production Report

Regarding the Utica, I am of the opinion that the data to form significant concrete conclusions is not yet available.  The 2012 production figures released in May 2013 offer only a glimpse into what is actually happening.  ODNR figures were submitted for 87 wells, 63 of which are commercially producing, 19 of which have been tested and are currently shut-in, and 3 which were dry and abandoned (sorry Devon).  None of these wells produced for the entire year and, in fact, 74 have little production history at all (less than 6 months).   CHK executives insist that the data does little to assess the quality of the play.  They also made further statements which were enlightening in their own right.

The fact is, ODNR provides production data in a very non-specific manner.  They simply give you the total amount of production, divided between what is described as being gas or oil.  They also provide the number of days in production.  Simple division does little to reflect what is actually happening, or what the future may hold.  Further, industry executives insist that most wells are running at nowhere near full capacity.  Lack of infrastructure has tainted expected production in a number of ways.  Not only are wells being choked back, but they are being drilled strategically where infrastructure takeaway capacity is available and not necessarily in areas which may look most attractive geologically.

What drillers have learned – both good and bad…..

It seems many are unimpressed with the prolific amount of gas being produced.  Never mind that J. Michael Stice, CEO of Chesapeake Midstream admits that “we are only focused on the wet gas window”.  They know the technology to extract oil from tight formations does not yet exist. They are specifically targeting LNG’s, not oil, and even when liquid production is not as anticipated, CHK reports results “much better than we originally thought”.  It is also worth mentioning that 17 of the 19 wells not yet placed into commercial production had incidental volumes of crude despite not being the specific target. You can believe that, with experience and technological improvements, drillers will soon find out how to maximize crude production and will tweak their fracking methods to accomplish just that. 

Perhaps the biggest flaw in criticizing the Utica is the fact that all natural gas is not created equal.   ODNR does not differentiate between dry or wet gas, nor do they provide any BTU values.  They make no effort whatsoever to delineate the amount, type, or quantity of NGL’s contained within what is being reported as gas.  We have already established that LNG’s trade at a value which more closely mimics the price of crude rather than that of dry gas.  They have their own separate and distinct market(s).

Speaking of dry gas, now trading at about $4.00, its price has more than doubled since I first began this report in 2010.  What was once attractive only to help induce the production of liquids has now become profitable in its own right.  Should prices continue to rise, or at least show some semblance of stability at today’s market price, you will surely see more rigs targeting both the Utica and Marcellus in Appalachia, happy to accept dry gas production as a lesser but still economic target.    CHK officials praised their dry Utica completions as being economically similar to their Bradford County, PA wells, interesting in that their investor presentations make it quite clear how proud they are of results there.

Chesapeake claims they have enough information (having drilled the bulk of Ohio’s Utica wells) to accurately predict estimated ultimate recovery (EUR’s) for their wells.  Projections range from 5 bcf to 10 bcf with the higher numbers being more gas and the lower having more liquid production.  Within the wet gas window reportedly lies 6-8 bcf a day of processable gas, in need of a home and infrastructure to bring it to market.  Obviously the liquid-rich wells will have a higher economic value per mcf.   Either way, CHK seems not nearly as pessimistic as Reuters.  They are currently operating 14 rigs here in Ohio and plan to continue their aggressive drilling program, enjoying the benefit of Total’s drilling carry, which will reportedly carry them at least through year end 2014.

But what exactly can they expect to produce?  I think it is a generally accepted fact that what has been purported to be the oil window to the west (tested primarily by Devon and Anadarko) will not be successful as commercial production in the near future.  ADK’s wells may be marginally profitable (if EVN’s John Walker is correct in saying that 200 bbls/day is the magic number) but they do little to inspire further drilling.  Does that mean prospects for the oil window are dead?  Hardly.

Drillers have confirmed the shale to be high in total organic content (TOC) and to be oil-rich.  However, there remains a myriad of problems to solve regarding pressure and permeability.  I liken it to trying to drink a thick milkshake with a very thin straw.  Despite one’s best efforts, the treat that you know is there may not be accessible to enjoy.  “I think everybody continues to believe that the Utica contains prospective amounts of crude oil, but there are technological issues and challenges that need to be addressed,” says Tom Stewart, Executive VP of the Ohio Oil and Gas Association.  “That’s a function of technology, and somebody will figure it out.”  How soon remains to be seen, but until then, we can only attempt to decipher the successes further east and see if we can accurately predict what our product(s) there will likely be.

Specifics regarding Utica production….

There is considerable variance with regard to production type reported by different publications.  Lots of folks have their own agenda to promote, or their own crusade to pursue.  To the extent it is possible, I will refer to actual earnings calls to stockholders which contain less spin and often provide the type of information folks wish they could get from ODNR.  Many times they will include specifics regarding product mix, percentage of components and even BTU equivalents.  Let us now examine and interpret the results reported via such sources.

In their first quarter 2013 report, Gulfport provided a pretty clear picture of their results.  Their first 14 Utica completions here in Ohio averaged an initial production rate of 807 bbls/day of condensate, 7.8 MMcf of natural gas per day and 946 bbls of NGL’s.  Converting to BOE/day this equates to 3,055 BOE/day.  Perhaps the naysayers should be reminded that anything over 1000 boe/day has been alternatively referred to as being either “excellent” or “prolific”.  Spin that haters…..

Further, they provided some pretty specific ratios regarding their production mix.  Averaged over their first 9 completions, Gulfport reports the following:  20.4% condensate; 32.6% NGL’s; and 47% gas.  The BTU equivalent of the gas was not provided, making it impossible to determine its true value or its potential to be converted to more valuable liquids.  However, even without such conversion, and working with the figures and ratios provided, one can hardly be disappointed.  Value your condensate at approximately 85% of crude (a low-end average between that cited by Seeking Alpha and that purported by the Oil & Gas Financial Journal) and you produce about $65,165 per day income from condensate alone.  At about $41 per barrel (as per Seeking Alpha) your income from NGL’s daily would be about $38,785.  Independent of dry gas, Gulfport is already averaging over $100,000 in daily production income per well.   And at $4.00, a well producing 7.8 MMcf of gas daily would likely be considered economically viable in its own right.  Note:  one should never assume any well will produce 365 days a year, so do not stretch the truth in expressing income per year.

NGL’s vs. condensate….

Perhaps now is the time to discuss product mix.  The few reports regarding BTU equivalency (primarily from Rex) are quite promising.  They are reporting wells with gas production ranging from 1207-1216 BTU.  This will trade at about a 15% premium to lesser quality gas found elsewhere.  However, the single biggest component with regard to both value and confusion is condensate.  Speculation that GPOR was actually referring to pentene as condensate has been unproven.  Instead, it may well be an extremely light-weight oil with an API value in the 50’s or 60’s.  Analysts say it will trade at about a 15% discount to WTI but it also has some unique qualities and requirements of its own.  It is a separate and distinct product from what is typically referred to as an NGL.

One does not have to refine another product to create NGL’s.  NGL’s produced by Ohio’s Utica wells come straight from the gas stream and exist, in unknown proportions, as ethane, propane, butane, and reportedly pentene.  They have a variety of purposes including use as a feedstock for petrochemicals, as a heating fuel, and for gasoline blending.  It is a little known fact that gas costs more in the summer not because of demand or a conspiracy, but because they cannot cut it as much with butane during summer because of its reaction to the environmental temperature.

The other most valuable component of the Utica’s product mix has been described as condensate, and is the subject of much misunderstanding.  It is likely a very light sweet crude, with a high API gravity (typically 60 or above) and, although it can be refined, the use of condensate splitters typically will yield more favorable returns.  And, although much of the badly-needed infrastructure necessary to bring NGL’s to market is about to come on-line, condensate, as a product, creates its own challenges with regard to transportation to market.

Condensate exists in many shale plays (especially the Eagle Ford) but, because of the volume and API gravity of the crude being produced, it is typically not separated but instead blended without detriment to the resulting API of the finished product.  Some say Texans always want to express maximum crude production figures, and they do so in the Eagle Ford by simply ignoring any reports as to condensate.  Considering they can sell the product at a premium, they are surely maximizing profits as well.  At present, the Utica completions are not showing nearly enough pure crude to allow us to mimic Texans.  We will have to sell our product for what it is.

Most Utica producers have already begun installing condensate-processing equipment at the wellhead in the form of stabilizers.  The vapor pressure of the condensate must be reduced to specifications before it will be accepted by a pipeline provider.  These can be complicated mechanisms in their own right, and may include a distillation tower and separation system.  Many refer to these as splitters in that they reportedly can extract refined products such as kerosene, naphtha and distillate from raw condensate. 

Even after stabilization, producers often have a hard time finding a market for condensate without trading at a discount.  That portion of the Eagle Ford condensate not blended reportedly traded at about a $17 discount to West Texas Intermediate (WTI).   Refiners were reluctant to get involved with a product they could not easily process, and paid less as a reward for their inconvenience.  We may not experience such problems here.

Although condensate produced at the wellhead is often unattractive to refiners because it has too many light naphtha components for their liking, both refiners and processors here are investing early to take advantage of attractively priced condensate supplies.  Utica condensate is already reportedly trading at about a $13 discount, rather than the $17 discount reported in Texas, reflecting both the abundance of supply and the midstream players to process such.  The area’s largest refiner, Marathon Petroleum, recently announced plans to spend $300 MM over the next three years to build condensate splitters at both their Canton, OH and Catlettsburg, KY refineries.  They will have a combined capacity of 60 Mb/d of condensate.   

Gulfport has been reporting the most prolific condensate production and recently announced specific plans to process and market the product.  They intend to invest in their own splitter, and will reportedly ship to Chicago via both pipeline and rail.  There, it will be tied into another pipeline for transportation to Western Canada as a diluent for heavy Bituman crude, a necessary component to get that heavy product to flow.  Who can argue with Gulfport executives who purport it to be much cheaper and quicker to ship condensate to Canada from Ohio as opposed to South Texas?

Midstream’s $10B gamble…..

If this play is so damn disappointing, why are midstream companies committed to building nearly $10B in infrastructure here to support it?  Currently at least 9 projects involving processing, compression, refrigeration, or transportation are underway including MarkWest (Gulfport’s partner), Crosstex Energy, and Pennant Midstream, LLC.  They range in cost from $300 M to $1.5 B.  The MarkWest projects will likely have the biggest impact in that they have at least 2 facilities projected to be brought on-stream by year’s end.  In addition to the facilities themselves, MarkWest projects to have almost 2 ½ times the amount of gathering pipelines to transport product.

Regarding the facilities, their Harrison County plant (recently completed) will bring an interim 40 MMcf/d to market via refrigeration/processing.  Further, they recently announced that they have begun operation of another 125 MMcf/d cryogenic processing facility, one that can handle an additional 200 MMcf/d capacity at another Harrison County facility.  This plant will reportedly handle the Harrison, Guernsey and Belmont county production initiated by Gulfport (and likely others).  But they haven’t stopped there…..

Their second processing complex in Noble County was just completed which can handle 45 MMcf/d refrigeration natural gas processing.  By mid-year, they expect to bring another Noble County facility on-line to handle 200 MMcf/d of cryogenic processing.  These facilities will be connected to the Harrison County fractionation plant which will include 400,000 bbls/day of C2 + fractionation capacity.  The entire system will then be connected to its Houston fractionation plant.  Combined, they comprise the largest fractionation complexes in the northeast, and surely will allow Gulfport considerable access to market and the immediate ability to bring most completions on-line.  Gulfport executives have already expressed their pleasure at soon being able to move from “immediate production into sales”.  Watch and see how bringing these prolific wells on-line will affect production numbers to be released next March. 

Ohio, and Appalachia in general, are quite well-placed strategically for access to many markets.  The ATEX pipeline, scheduled for early 2014 completion, will open up a new ethane project in the Northeast.  Until its completion, producers will likely recover the minimum amount of ethane necessary to meet industry specifications.  Gulfport claims to have received considerable domestic and international inquiries regarding purchase of their Utica ethane and will soon have an alternate to the current Mariner West pipeline and Mont Belvieu facilities.  Between these two sources, they will certainly be able to fill any legitimate demand for that particular product.

They are also “seeing considerable interest and clarity in the near and long-term demand” for what they call their “purity products”.  With regard to propane, the Targa and Enterprise Gulf Coast propane export facility will handle take-away capabilities sufficient to stabilize the market for new NGL production.  MarkWest is also spearheading marketing of Gulfport’s propane supplies and are already exporting it internationally.  This is in addition to the condensate product to be marketed primarily through Canada, discussed above and evaluated previously.

Does anyone doubt the impact of a $10 B investment designed specifically and strategically to facilitate and stimulate this one particular play?  Production numbers will surely escalate rapidly with increased capacity and greater access to market.  “There are some really massive projects on the drawing table or having ditches dug,” according to one industry executive.  Stay tuned…..

Who will paint the picture for 2013 production??

Exploration companies generally share midstream’s enthusiasm for expansion and investment.  Among the most compelling statements came from Gulfport who’s CEO James Palm reported they were genuinely pleased with their Utica results, recently increasing their position by about 20% by adding 22,000 acres, and gladly paying $10,000 per acre to acquire such.   Considering he announced that they now have 9 wells on-line producing at a combined gross rate of over 10,000 boe/day, one can easily understand the investment.  He announced that production in 2012 had been less than expected due “primarily to the delays in the Utica midstream complex”, a problem that will be largely solved this year.  They plan to put at least 4 more wells on line by mid-year and reminded investors that they operated with only 2 rigs for much of 2012 but plan to expand to 7 rigs “as quickly as possible”.

What about Chesapeake?  They continue their aggressive drilling program in what they call their “core area” meaning Carroll, Harrison and Columbiana counties and stand to benefit greatly from completion of midstream facilities at both ends of their activity.  Capacity for them will be increased more than 5 fold by year end from 65 MMcf/day to about 330 MMcf/day.  This alone will skew production numbers in a totally different way from those reported last year.   Gulfport will have plenty of wells on line by year end, but few will have a complete calendar year of production history.  Once again, CHK will provide us with most of the pieces to our puzzle. 

Operating 14 rigs here now, CHK reports that they will have at least 4 times as many wells on line by year end as the 53 wells reported for 2012 .  Their Q-1 2013 report was also interesting in that it reported its Eagle Ford wells to be producing at average peak rates of about 950 boe/day vs. 1170 boe/day for its recent Utica completions.  Further, the Utica wells were reported as being an avg. 24 hour restricted rate, leaving open the possibility of even bigger results once midstream problems are resolved.  Say what you want about the quality of product – the Utica may not quite be the Eagle Ford, but it is quite close economically and nothing to be scoffed at.

Exploration companies are currently operating 32 drilling rigs in Ohio, up from 19 at this time last year.  Most expect that number to continue to climb.  There are only so many available and plenty of competition to acquire such, especially with both oil and gas trading higher recently.  During the same time period, WV’s rig count stayed stable at 23 total while PA saw its number of working rigs fall by almost a third.  It seems industry experts, especially those writing the big  checks, seem much more optimistic about prospects for the Utica than Reuters.  So what can we really expect? 

Certain facts cannot be denied.  Chesapeake alone has completed almost 200 wells which are not yet online.  Additionally, they plan to expand production by at least 6 fold, happy to be accommodated by infrastructure now, or about to be completed.  Only a handful of their wells thus far have been described at producing at greater than “a very constrained rate”.  Conference calls and notices to stockholders repeat their plans to ramp-up substantially and promise huge production growth.  They have budgeted about $2.25B for drilling here during 2013, more than any other region where they are active, short of the Eagle Ford.   

Gulfport is even more heavily leveraged toward the Utica, budgeting 83% of its $420 million FY2013 CAPEX program to Utica developments.  They expect to more than triple their production growth to approximately 21,233 BOE/day by year end.  Investors have taken note of their prolific wells here, pushing their stock up over 160% in just over six months.  I don’t think any pundit would argue that this is exclusively due to their Utica completions.  They have little going elsewhere.

Additionally, well results will likely improve both from greater understanding of the geology and from lessons learned in varying current fracking techniques.  Gulfport is already experimenting with different lateral lengths, number of stages, and type of sand and/or proppant used.  These variations will all occur on wells drilled from the same pad, alleviating any differences with regard to geology. Chesapeake claims they have reduced their cost to drill to about $5.9 M on average.  As much as has been learned thus far, the bulk of the learning curve is likely still ahead of us.

Industry experts claim we are likely recovering no more than 15% of the reserves using existing technology.  The likelihood is that technology will soon be evolved which will allow companies to go back and re-stimulate many of these wells, significantly improving  the recovery factor and predicted EUR’s for each.  Further, I am of the opinion that technology will be developed within the next few years allowing commercial production of the oil window, which has disappointed thus far.  If you look at how technology has changed in the industry over the last five years, it is certainly not beyond the realm of possibility.  It will be interesting to see how many producers pick up the five or three year option which many of their leases provide for.

State officials project there will be 362 or more Utica wells completed and online for 2014 reporting.  By year-end 2014, the figure will grow to more than 660 producing wells.  As many as 1000 wells will reportedly be online and producing by year end 2015.   By then, much of the mystery and debate about the Utica and its future will already be decided.  Each person must form their own opinion.  Perhaps I am an optimist.  Perhaps I am just slightly better informed.  Time will tell.

Nevertheless, I am inclined to agree with those who are betting on the Utica’s success.  The amount of midstream development occurring here to facilitate production may be unparalleled currently in America.  They have made it clear that they are in close contact with drillers and expect to have massive amounts of product to deal with.  Their partnership with drillers gives them a unique insight not afforded to other industry participants.  Allen Brooks, a well-known consultant, probably put it best when he said, “You don’t see many pipelines that are built and then abandoned in few years.  When people build pipelines, they’re confident that the resources are there and they’re betting the play will be productive.”  I am betting with them on this one. 

The Utica may never measure up to the Bakken or the Eagle Ford.  It may fall well short of the $5B value Aubrey attributed to it.  It may never produce 1.5 Billion bbls/day as once projected.  However, one doesn’t have to be the best to be quite great indeed.  My belief is that most well-managed operators will find the play to be quite lucrative, and that some companies, such as Gulfport, will earn a spot on the map because of it.   I would challenge even the most ardent disbelievers to show me evidence otherwise. 

Further, affiant sayeth naught!