John H's Posts - GoMarcellusShale.com2024-03-29T08:02:26ZJohn Hhttps://gomarcellusshale.com/profile/jwhhttps://storage.ning.com/topology/rest/1.0/file/get/35533355?profile=original&width=48&height=48&crop=1%3A1https://gomarcellusshale.com/profiles/blog/feed?user=2x8f9hj5ufvms&xn_auth=noAlternate Fracking and Wastewater Treatment Methodstag:gomarcellusshale.com,2014-11-17:2274639:BlogPost:6409632014-11-17T20:36:47.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
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<p>In researching this subject, I discovered a January 16, 2011 article featured in OilOnLine which provides an interesting alternative to conventional fracking techniques. Virginia based PDN Mountaineer, LLC announded that they have partnered with Utah based Purestream Technology in incorporating their Trilogy system to treat and purify wastewater from their Marcellus operations. Purestream claims to be able to alleviate the environmental impact of hydraulic fracturing by…</p>
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<p>In researching this subject, I discovered a January 16, 2011 article featured in OilOnLine which provides an interesting alternative to conventional fracking techniques. Virginia based PDN Mountaineer, LLC announded that they have partnered with Utah based Purestream Technology in incorporating their Trilogy system to treat and purify wastewater from their Marcellus operations. Purestream claims to be able to alleviate the environmental impact of hydraulic fracturing by evaporating produced and flowback water at the ell site. They scrub air emissions, clean and evaporate wastewater and provide water, oil and condensate date tracing technology. A single Trilogy unit place at a well site can process up to 63,000 gallons per day, effectively removing contaminants from waste water and rendering it cleaner than drinking water. They claim it can be engineered and deployed to address specific issues facing any region or producer.</p>
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<p>Perhaps the answer lies in another fracking technique. We should soon know. The Akron Beacon Journal reported on January 30, 2012 that Chesapeake has just tried a new process on two wells drilled recently in Ohio (one in Portage County and the other undisclosed). According to the report, they are using a carbon dioxide foam which requires only a tenth of the amount of water used during typical hydraulic fracturing. It has been described as being similar to Alka Seltzer in that it fizzes, expands, and then shrinks back down.</p>
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<p>The Portage county well reportedly required less than a half million gallons of water, a refreshing change in that is is less expensive to the driller and less alarming to environmentalists. It appears, but is unconfirmed, that they are using Halliburton's RapidFrac system complete with disintegrating frack balls, which are used to plug the well bore at various stages and isolate different zones for fracking. They claim to be able to save the driller an incredible 2/3rds over normal costs incurred during conventional fracking efforts.</p>
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<p>The Times Reporter (New Philadelphia) claims to know further details about CHK's recent drilling efforts. They report CHK to be using an Aqua Renew facility via Rettew Flowback, a company based out of Lancaster, PA. They recycle flowback or brine water by treating and filtering it to remove silt and salts, allowing it to be reused for fracking purposes. The facility runs 16 houra a day and can treat between 10,500 and 12,600 gallons per hour. Chris Foreman, a company executive, explains that they can reclaim about 95% of the water, witht he rest being sludge which can be dumped at approved landfills. CHK promises to open more Aqua Renew sites as drilling expands. It's no wonder, as they have saved more than $6M annually using it during 2010, as per stockholder reports.</p>
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<p>I also discovered that this, or a very similar technique has been available since at least 2002. A 2008 article feature in Exploration and Production Magazine purports the method to be superior for a number of reasons. They claim it will enable "production optimization with minimal post-frack cleanup". It significantly reduces the amount of equipment needed and allows for a smaller pad site. Further, it allows the driller to use ultra lightweight proppants (ULWP's) in lieu of sand. ULWP's have much lower specific gravity than conventional proppants, which reduces the settling rate in water and provides unprecedented proppant transport and longer effective frack length. Consequently, the amount of proppant, as well as the amount of water used, is reduced drastically. They claim the process "virtually eliminates post-frack clean-up time and water disposal costs".</p>
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<p>The best new regarding this technique? It may actually provide twice the production with only a fraction of the water and sand/proppants required in conventional frack jobs. a 2008 study in Mingo County, West Virginia compared two wells drilled using carbon dioxide and ULWP's to a number of offset wells drilled using conventional hydrofracking. The results? One well produced at nearly twice the rate of comparable offsets. The other was even better, resulting in more than twice the cumulative production (based on a 30 day average cumulative production figure). These wells were drilled into the Upper and Lower Huron shales, which exist throughout much of Appalachia. This may well be the future of fracking, and may pave the way for a revolution in the entire industry.</p>
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<p>EQT's Senior Vice-President, Steve Schlotterbeck, acknowledges that "water continues to be a hot topic of conversation". They purport to be using anew and superior technique of their own. They claim it to be especially effective wherever a high silica content exists and the shale is brittle. They have used it on over 25 wells resulting in initial production rates 50-60% higher than those fracked using traditional methods (which reportedly leaves more than half the petrocarbons behind). They are still being pretty secretive about it, so it is unclear whether this is the same technique or an alternative to that discussed above.</p>Too Much Clay? Chill Out. Why Cryogenic Fracturing May Be the Answertag:gomarcellusshale.com,2014-11-03:2274639:BlogPost:6368102014-11-03T01:21:31.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
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<p>Almost without exception, today’s shale wells are stimulated using water-based fracturing fluids (slickwater). This technique is popular due to its ability to transport proppant effectively at a relatively inexpensive cost. However, it is a magnet for criticism from environmentalists, who are concerned about the incredible volume of water needed as well as the resulting contaminated wastewater which must be treated and disposed of properly. Water use is often cited as one of the…</p>
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<p>Almost without exception, today’s shale wells are stimulated using water-based fracturing fluids (slickwater). This technique is popular due to its ability to transport proppant effectively at a relatively inexpensive cost. However, it is a magnet for criticism from environmentalists, who are concerned about the incredible volume of water needed as well as the resulting contaminated wastewater which must be treated and disposed of properly. Water use is often cited as one of the primary reasons that there are more than 435 pending ballot measures seeking a moratorium of fracking in various parts of the US.</p>
<p>An answer may be close to being developed as we speak. Researchers at the Colorado School of Mines claim they have developed a method to unlock hydrocarbons trapped in shale with using any water at all. They are seeking to perfect Cryogenic fracturing, which replaces water with searing cold liquid nitrogen (or carbon dioxide). Used at temperatures below minus 321 Fahrenheit, it is pumped underground at high pressure. Once it comes into contact with the heated, pressurized shale, a reaction occurs which caused the shale to crack open and creates fissures through which the hydrocarbons can gush out. They liken it to pouring hot water onto a frozen car windshield, with the sharp and sudden temperature change causing the glass to crack. </p>
<p>There are several positive results from using this technique. First, the liquid nitrogen will evaporate underground eliminating the need for costly recovery and retreatment. Further, they claim it will form bigger fissures or canals through which hydrocarbons can be extracted, boosting oil and gas production. In theory, the below-freezing liquid should actually be more rather than less effective than water based methods.</p>
<p>Second, it may well solve problems with water-sensitive formations or those with an unwanted amount of clay. Slickwater fracking often causes water saturation around the fracture and clay swelling, hindering the ability to transport hydrocarbons from the fracture to the well bore. Some shale absorbs water very quickly and the entire formation may swell in size and hinder transport through the fissures we have created. Even in a best case scenario, using hydraulic fracturing results in a low recovery factor, caused largely by water trapping.</p>
<p>Technology in fracking in moving incredibly quickly, and methods successful in one play will be mimicked wherever the geology seems similar elsewhere. Cryogenic fracturing has evolved from failed fracturing attempts with gaseous nitrogen first introduced during the ‘70’s and ‘80’s. Critics claim nitrogen does not have a high enough viscosity to carry proppant efficiently, and that the fluid itself may prove to be more costly than producers prefer. Further, it requires special piping and equipment requirements which prove a challenge unto itself.</p>
<p>Obviously the new technology is not yet market ready or completed de-risked. Few technological advancements in this industry are. So much is learned by trial and effort, both success and failure. However, competitors are always paying attention and mimicking the success found by others and the techniques they employ. You best believe the industry has a close eye on what is happening in Colorado, with Pioneer Natural Resources having first crack at the new technology. Stay tuned…..</p>
<p> </p>Ohio's Triple Play?tag:gomarcellusshale.com,2014-08-07:2274639:BlogPost:6089462014-08-07T08:23:51.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">As early as 2011, Range Resources CEO John Pinkerton was already being quoted trying to control his enthusiasm for what he calls a “triple play” in Ohio. Mr.…</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">As early as 2011, Range Resources CEO John Pinkerton was already being quoted trying to control his enthusiasm for what he calls a “triple play” in Ohio. Mr. Pinkerton was referring to a combination of several shale plays which exists along with intermingled sandstone formations throughout Ohio. In the East, it is the Upper Devonian Shale, the Marcellus Shale, and the Utica Shale, in that order, according to depth. As you move westward, the Marcellus plays out, but is replaced by the Lower Huron.</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">Range is one of many exploration companies scouring the country for shale rich in oil and natural gas liquids rather than the gas-rich shale you usually read about. “The technology is pretty much the same” to drill for oil or gas in shale, said Marquette Research analyst Jason Gammel. “So if you can find an application that produced oil rather than gas, given how much of a premium oil trades to gas, that would be your preference.” The economics are vastly superior.</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">What made the economics look truly outstanding in Ohio that early during Utica development was that much of the necessary infrastructure for transportation and development was already in place. It may actually live up to Pinkerton’s boast of being “one of the most economic plays in North America”, as he was recently quoted as saying in a transcript released by the Morningstar investment research firm. Ohio was already a myriad of criss-crossing and intersecting pipelines and home to at least five existing refineries capable of processing almost a million barrels per day, before ramp-up. Currently, there is about $10 B in infrastructure and midstream activities underway in Ohio, WV and SW PA.</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">Despite projects planned or underway, Ohio’s Utica production is still encountering similar logistical problems to that experienced in the Marcellus with wells being shut-in for lack of access to pipelines or appropriate transportation facilities. For now, let’s just establish the fact that Ohio is addressing its mid-stream needs aggressively and without delay.</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">Pinkerton believes, an incredible benefit can be derived from the already existing drilling pads, roads, permits, gathering and processing systems, etc. It is a little known fact that this is one of the huge benefits enjoyed by the Eagle Ford, which was actually discovered re-working an existing well in a field developed in the 1940’s. Pinkerton brags that “the incremental costs to develop the Upper Devonian and Utica will be reduced by approximately one-third versus developing those zones on a stand along basis. We believe this will allow us to continue to drive down the cost of entire play”. Makes sense to me.</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">Ohio also provides attractive geological opportunities in that it appears to have perhaps three commercially productive shale structures within its borders, some of which have overlapping borders. Combined, these structures contain estimated reserves of more than 20 trillion cu ft in its Utica Shale formation (<em style="font-style: italic;">20), our primary target, and over 2 trillion cu ft in the Lower Huron Shale (</em>21), which replaces the Marcellus in Central Ohio when it plays out. Where the Lower Huron does not exist, the Marcellus Shale does, extending westward into Ohio. There are no reserve estimates available for the formation vaguely referred to as the Upper Devonian shale, but Range Resources recently increased its Marcellus estimates 167% by including it in their reporting. The best news of all? Where they in fact exist and overlap, wherever one is “wet” the others shall be too (as per John Pinkerton, CEO of Range Resources).</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">The Marcellus was the source of much of the early publicity associated with natural gas exploration and fracking in the U.S. It purported contains “technically recoverable reserves” estimated to be as high as 489 TCF of natural gas. (*22) What percentage of these reserves lie within Ohio’s borders is yet to be determined, but there are already at least 27 Marcellus wells drilled and at least 44 wells permitted and ready to be spudded as of report date . ODNR’s July 19, 2014 permit report reflects 30 horizontal permits either pulled or already drilled in Monroe County alone.</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">In retrospect, much of the above has been proven true, with a few caveats. First of all, several E&P companies have found Monroe County to be productive for both Utica and Marcellus drilling. Magnum Hunter has been among the most aggressive in pursuing both, and have done so, with great success, from one well pad. Their Stalder wells in particular have featured multiple laterals from each formation, reportedly scoring quite significant liquid production from their Marcellus wells and high-volume, pipeline quality gas from the Utica.</p>
<p style="font: 16px/24px museo-sans, 'Helvetica Neue', Helvetica, Arial, sans-serif; margin: 0px 0px 18px; color: #4a4a4a; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; font-size-adjust: none; font-stretch: normal; background-color: #ffffff; -webkit-text-stroke-width: 0px;">This certainly backs up Pinkerton’s talk about saving money incrementally regarding sharing well pads and infrastructure. However, his comments regarding all structures being “wet” were obviously tempered with the understanding that the depth and thermal maturity of some otherwise productive Utica areas will be high-quality, high-production dry gas with attractive purity and BTU figures.</p>Jet Fuel and Diesel in Ohio?tag:gomarcellusshale.com,2014-08-04:2274639:BlogPost:6077282014-08-04T02:39:27.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p><br></br>In May of 2011, I read the first article about some shale gas being more valuable due to its specific mineralogy. Most LNG’s are sent to a cracker plant to be processed into ethane and used for the vast myriad of plastic products that our society seem unable to do without. There has been much competition and speculation for several years now regarding building just such a facility here in Appalachia.</p>
<p>However, some apparently think the mineral content and DNA of our LNG’s may be…</p>
<p><br/>In May of 2011, I read the first article about some shale gas being more valuable due to its specific mineralogy. Most LNG’s are sent to a cracker plant to be processed into ethane and used for the vast myriad of plastic products that our society seem unable to do without. There has been much competition and speculation for several years now regarding building just such a facility here in Appalachia.</p>
<p>However, some apparently think the mineral content and DNA of our LNG’s may be more valuable being refined into jet fuel or diesel, which, along with proximity to pipelines, refineries, and to market, may put a premium on liquid production from the Utica here. That’s if you believe Baird Energy, a Vancouver energy-development company, who has proposed to build a $3.5B refinery in Columbiana County on 200 acres, which they purport will be able to produce at a rate of 2.1 million gallons per day, specifically targeting jet and diesel fuel. They had previously planned a coal-generated facility requiring $6.9 billion and 450 acres which would have not only produced less, at a much higher cost, but with 75% more carbon dioxide emissions. Utica gas designated for ethane will reportedly have access to every cracker plant currently in existence in America, when the proposed pipeline projects already mentioned are online by 2014.</p>
<p>Recent comments by University of West Virginia Professor Tim Carr seem to confirm the speculation proposed above. He offers that Gulfport’s categorization of condensate vs. NGL’s is unique. His interpretation is that whenever Gulfport announces well results, and spell out the amount of condensate being produced, the moniker is actually being used to refer to liquid natural gasoline (pentene), a product needing little refinement in order to be converted to vehicle-quality gasoline, diesel, or jet fuel. Short or high-quality pure crude, Carr cannot imagine a more valuable or lucrative product to see in one’s production mix.</p>
<p>More recently, Houston-based Velocys announced it had acquired Pinto Energy (also Houston-based) for a very specific purpose. Seems Velocys, with offices also in Columbus, is looking to get involved in Utica production and in an area some would find unlikely. With both BP and Halcon Resources throwing in the towel (at least for now) in Northern Ohio, it was interesting to see them announce Ashtabula County as the site for their development plans. Apparently they see it as the perfect location for a new high-tech but small-scale gas-to-liquids plants ultimately producing……you guessed it – jet fuel and diesel.</p>
<p>Pinto is a facility-development company, while Velocys is techno-driven with a strong focus on gas-to-liquid production. Their plans are to use the Fischer-Tropsch process to convert gas-to-liquids, making economical use of areas where gas is stranded, flared-off, or found to be in need of a market. It requires a reliable supply of fairly cheap gas in steady volume and is quite economical when gas prices are distressed, and less so when its market will sustain higher prices.</p>
<p>“There’s certainly a point at which gas prices get too high”, spokesperson Andrew Miller admits, but he seems confident they can secure long-term contracts at todays’ prices, which are reportedly quite profitable. Apparently many producers will roll the dice long-term with gas secured at today’s prices. It certainly looks attractive compared what they were getting when this play first began. A November 2013 report by New-York based Bernstein Research (an oil and gas investment analyst) says it may go so far as to be another energy revolution. Time will tell.</p>
<p>Velocys reportedly will spend $300 million to build and develop the plant, having already bought the 80 acre tract needed to construct the facility. They will reportedly produce about 2,800 barrels of diesel fuel each day, employing 30 employees full-time, once the facility is up and running.</p>Understanding the Basics of Ohio Geologytag:gomarcellusshale.com,2014-07-22:2274639:BlogPost:6034592014-07-22T05:17:47.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p><br></br>The Trenton Limestone:<br></br> <br></br>The Trenton Limestone and accompanying Black River rocks are important in that they serve as the source for much or all hydrocarbon formation in the Appalachian basin. Generally speaking, the Trenton Limestone serves as a cap rock for the underlying Black River source rocks. Because it is not as thick here in Ohio, it has allowed hydrocarbons formed by the Black River group to migrate naturally into the Utica/Pt. Pleasant. To the East, in West Virginia…</p>
<p><br/>The Trenton Limestone:<br/> <br/>The Trenton Limestone and accompanying Black River rocks are important in that they serve as the source for much or all hydrocarbon formation in the Appalachian basin. Generally speaking, the Trenton Limestone serves as a cap rock for the underlying Black River source rocks. Because it is not as thick here in Ohio, it has allowed hydrocarbons formed by the Black River group to migrate naturally into the Utica/Pt. Pleasant. To the East, in West Virginia and Pennsylvania, oil and LNG’s may be trapped deeper, or their thermal maturity may have been negatively impacted by the thicker Trenton preventing occurrence of such desirable migration into our porous Utica.<br/> <br/>Generally speaking, as hydrocarbons were formed in these source rocks millions of years ago, the process of migration occurred whereby oil and natural gas moved upward through adjacent formations, impeded and impacted by the porosity and permeability of structures located above them. Where significant porosity exists, the structure will absorb and contain the hydrocarbons, holding them in either a conventional or unconventional reservoir (shale). Where permeability allows, the oil or gas will continue to rise toward the surface, passing through one formation and continuing to move upward. Shale is typically low in permeability (the Utica is especially impermeable) and serves as a containment source that stops migration and creates a reservoir. Because it is high in porosity, the Utica is particularly adept at serving as a reservoir because it stops the hydrocarbons from continuing to migrate, and absorbs and holds them in containment. <br/> <br/>The stacked layers of shale and interbedded limestones existing in Ohio adjacent to the Utica, referred to alternately as either the Upper Devonian Shale or the Point Pleasant, serve further to absorb and contain whatever materials make it through the maze of permeability problems posed by the Utica. Upper Devonian shale may include not only the Utica, but any number of interbedded gray or black shales, including the Rhinestreet shale and Burkett shale. For general discussion purposes, we will address them as being one and the same, with the bulk of the discussion being directed more specifically to the Point Pleasant, which merges with the Utica as it enters Ohio, forming an attractive target for exploration. (Exhibit 7)<br/> <br/> <br/>The Point Pleasant Formation: <br/> <br/>The Point Pleasant formation has been described as marking the end of Middle Ordovician time. The Ordovician Period is characterized as the greatest submergence of the North American plate because shallow seas covered such an extensive area, including all of Ohio. In this environment, the Acadian mountain-building event occurred whereby sediments high in kerogen were shed from the highlands into a somewhat enclosed basin, lowering the amount of available oxygen. (Exhibit 8) As they were buried and subject to the pressure and temperatures of the earth’s crust and core, the environment became conducive for the formulation of petrocarbons, especially oil and natural gas liquids. (*12)<br/> <br/>The appropriate balance of hydrogen and carbon along with the corresponding favorable oxygen/carbon ratio (along with suitable temperature levels) created primarily type one or two kerogen content materials. Because they were formed from fossils containing mostly proteins and lipids, and to a lesser degree, from pollen, spores, or plant/animal decompositions, conditions became prime for oil or a mix of oil and wet gas. (*13) It is particularly important to recognize that the Utica and especially the Point Pleasant have both been identified as having high TOC (total organic content) and type one or two kerogen levels, two of the most important factors to realize if you are indeed searching for wet petrocarbons i.e. oil or natural gas liquids.<br/> <br/>The Point Pleasant is characterized as having “three westward-thinning tongues of calcareous strata separated by shalier eastward-thinning tongues.” It is further described as being 60% limestone and 40% shale, interbedded, gray to bluish gray in color and up to 200’ thick in parts of Ohio. A well log which I located from a Tuscarawas County well showed the Utica/Pt. Pleasant merged to create a 255’ core with an excellent TOC as high as 3.73%. (Exhibit 9) Pretty damn impressive. Chris Perry, chief geologist with ODNR, claims the Point Pleasant to be the sweet spot of the entire play, with the highest TOC and a propensity to be highly brittle and contain significant natural fractures. Further, he claims formation thickness of as little as 50 feet to be commercially productive.<br/> <br/>ODNR’s Larry Wickstrom (previously) offers that the formation lies just beneath and adjacent to the Utica making the formation “actually thicker and higher in total organic content. It is very unusual. It is a black organic-rich crystalline limestone interlayered with black organic-rich shale. The Utica is a wonderful rock, but it is even better with the Pt. Pleasant beneath it. Since it is interlayered with the Pt. Pleasant, it is more frackable.” He believe the Utica/Pt. Pleasant package covers most of Ohio, but to what extent it will be commercially productive remains to be seem.<br/> <br/>It is important to recognize it as being calcareous shale because it contains a high calcium carbonate content derived from ancient algae, which is the perfect content for petroleum formation. Consequently it is high in TOC and contains level one kerogen, making it a perfect source for formation of hydrocarbons, especially oil. The Point Pleasant and the Utica are both identified as having a much higher carbonate and lower mineral clay content than the Marcellus. It is exceptionally similar to the Eagle Ford. If only we are so lucky. Production and fracking techniques will likely be borrowed from experience gained in the Eagle Ford play. (*14)<br/> <br/>Now is the time to make a bold statement. The characteristics described in the preceding two paragraphs could easily be used to describe the Bakken. It is not a true shale play. Instead, it is various limestone and sandstone formations interbedden with shale. Consequently, it can achieve optimum production only through horizontal drilling and hydraulic fracturing. <br/> <br/>Gulfport Energy, who holds a quite substantial leasehold interest in Ohio and who has delivered many of the best wells here released the following prospectus as to their interest in the Utica shale here. They purport to have a drilling cost of less than or equal to the Bakken or the Eagle Ford. Further, and or more importance, they purport to have more oil in place, a higher recovery factor, better average formation thickness, and a much higher porosity then either the Bakken or the Eagle Ford. If they are only half right, this will truly be one of the best shale plays in America, based upon potentially productivity and the simple economics of the deal. Considering the results of their recent Belmont and Harrison County completions, it is no wonder that they recently paid $10,000 per acre to acquire 30,000 net acres from Windsor Ohio, LLC in Eastern Ohio, the highest price paid to that date so far in Ohio. Speculation is that it is concentrated primarily in Belmont and Monroe counties, although no specifics were released.<br/> <br/>Generally speaking, the Point Pleasant exists above the base of the Trenton limestone to the base of the Cincinnati group (Kope Formation). Of importance is noting that the source rocks of the Trenton limestone and the Point Pleasant formation have been credited with generating 75 billion bbl of oil. Of this, due to permeability of subsequent formations, some has migrated into the Silurian reservoirs, including the Clinton Sandstone. (*15)</p>
<p>The Clinton Formation<br/> <br/>The Clinton formation has long been the most prolific producing formation in Ohio, with production as far back as 1887. Over 100,000 Clinton wells have been drilled in Ohio. It experienced a renaissance in the 1950’s with the introduction of hydraulic fracturing. During the late 70’s and early 80’s, the Clinton ran rampant. During the peak year of 1981, there were 6085 wells drilled in Ohio, of which 76% were completed in the Clinton sandstone. Because it is interbedded with shale, it responds well to artificial stimulation. Using this technique, the Clinton success ratio increased to 85% completions. (*16) This was 30 years ago! The Clinton is famous in Ohio and for good reason. Let me tell you why that is newsworthy.<br/> <br/>Despite its prolific history and reputation, the Clinton has been proven to hold only those hydrocarbons which escaped through permeable sections of the Utica/Point Pleasant. In fact, of the 75 billion bbl of oil generated by lower source rocks, only 400 million bbl of in-place oil can be accounted for, including all Clinton production going back 125 years and encompassing thousands of wells. Obviously, there is a huge amount stored in the lower reservoirs (i.e. Utica and Pt. Pleasant) waiting to be discovered. That is our target.<br/> <br/>Further, studies of well logs from these many wells have allowed us to pinpoint very specific areas which have an extremely high propensity for oil. Interpreting these well logs give us targets with which we can search with almost absolute certainty - at least, with as much certainty as you can achieve in this business. A recent study by the Ohio Department of Natural Resources tried to come up with an approximation of the recoverable reserves relating to the Utica Shale only, and estimated that the formation might hold from 1.96 to 8.2 billion barrels of oil equivalent just from Ohio alone. Yes, that’s billion, with a capital B, and does not even take into account the accompanying Pt. Pleasant or Upper Devonian Shale formations. Of recent interest was a quote from Terry Engelder, among the country’s most respected geologists (credited with discovering the Marcellus) purporting these estimates to be, in his estimate, artificially low.<br/> <br/>In researching this project, I located a study proposed to geologists and petroleum engineers at the 2011 Winter Meeting of the Ohio Oil and Gas Association. It was prepared by Martin Shumway, CPG, PE with MacKenzie Land & Exploration, Ltd. It considers all costs associated with establishing production – lease, drilling, pipeline and operating costs, etc. and uses township boundaries as geographic areas for analysis. It uses a controlled data base of over 15,000 Clinton wells reporting production since 2005. 168 townships were included in the report.<br/> <br/>Exhibit 10 is a map from the study showing Clinton wells used in the study superimposed on central and Eastern Ohio. Wells reflected in green are oil producers. The red wells are primarily dry gas. What we can learn here is where the most profitable Clinton wells are, especially which ones likely contain oil only because it has been allowed to bleed through the Utica or Pt. Pleasant containment because of lesser permeability in that area. It is a reasonable assumption that much more oil lies beneath the Clinton, trapped in the Utica/Pt. Pleasant due to the excellent porosity of the formations. <br/> <br/>We can now identify target areas by shale thickness, TOC levels, kerogen content, structure depth, thermal maturity levels, and known oil reservoirs. Again, proper due diligence in terms of research increases our level of success exponentially. I am confident in my research. It all comes from reputable sources that do not have a dog in this hunt, and no secret agenda to promote. What was once speculation is now becoming cold hard facts, and exactly the kind producers so eagerly anticipated.</p>
<p><br/>• My blogs are all original in nature and may make reference to bibliographical references or exhibits not necessarily contained here. Almost all are excerpts are from copyrighted material entitled “The Utica Pt. Pleasant Play in Ohio”</p>E&P Companies Like Ohio for More than Just Geological Reasonstag:gomarcellusshale.com,2014-06-22:2274639:BlogPost:5946472014-06-22T20:07:13.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p>Drillers like Ohio for more than just geological reasons. Ohio is ideally located to take advantage of development and commercial networks in both the Midwest and on a national scale. Ohio is within 600 miles of 60% of the US population and more than half of the Canadian population. It has considerable existing infrastructure and one of the most favorable tax/business climates in America. Ohio has zero tax on inventory or corporate income, no tax on investments for inventory or equipment, no…</p>
<p>Drillers like Ohio for more than just geological reasons. Ohio is ideally located to take advantage of development and commercial networks in both the Midwest and on a national scale. Ohio is within 600 miles of 60% of the US population and more than half of the Canadian population. It has considerable existing infrastructure and one of the most favorable tax/business climates in America. Ohio has zero tax on inventory or corporate income, no tax on investments for inventory or equipment, no tax on products sold to customers out-of-state, and an ambitious entrepreneurship reward system which allows companies to take the first $1 M in profits absolutely tax free.</p>
<p>Development in the Utica shale has taken off more rapidly than other plays because rigs capable of drilling horizontal wells, frack crews, production infrastructure and other support services are already in place. Access to the Ohio River is a big plus too, both as a source of frack water and for transportation.</p>
<p>Ohio also has a quite favorable political and regulatory climate. Even before Gov. Kasich took office, Ohio was already described as having "laws among the most lenient in the nation" and with less regulation, leases can be obtained more affordably. Despite his determination to pass a severance tax on oil and gas production (which exists in one form or another in neighboring states, often labeled as an "impact fee"), Governor Kasich has generally been a friend to the industry and has been genuinely enthusiastic in promoting drilling here. "We need to be particularly mindful of the important role that exploration can have...in expanding Ohio's economic future and in carbon mitigation and maintaining clean air," he was recently quoted as saying.</p>
<p>Even his pet legislation, State Bill 315, which he described as being "the toughest law on fracking fluid in the nation", was generally well-received by industry participants. It requires operators to disclose where they intend to acquire fracking water as well as the rate and volume at which they will withdraw it. It also requires disclosure of all chemicals used during the process, although not the specific amounts of each.</p>
<p>Kasich knows his political future is largely linked to development of the Utica here. It is no secret that it has been instrumental in propping up Ohio's economy, adding jobs and revenue that would otherwise seem improbable. And, despite industry reluctance with regard to the severance tax, Kasich will surely prevail on that subject. It's simply a matter of how much the tax well be. Regardless, Kasich is likely to be re-elected and his popularity will likely soar once it passes. Why? He intends to give Ohio residents an across-the-board cut on state income taxes. Who wouldn't welcome that?</p>Economics for a Typical Utica Completion in Ohiotag:gomarcellusshale.com,2014-06-08:2274639:BlogPost:5887792014-06-08T20:30:00.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri"><a href="http://storage.ning.com/topology/rest/1.0/file/get/72918990?profile=original" target="_self"><img class="align-right" src="http://storage.ning.com/topology/rest/1.0/file/get/72918990?profile=RESIZE_320x320" width="300"></img></a> CEO Frank Tsuru of Houston-based M3Midstream is investing over $1B across Eastern Ohio in a </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">rush to get into the Utica ballgame. His enthusiasm is generated by the incredible profit …</font></span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri"><a href="http://storage.ning.com/topology/rest/1.0/file/get/72918990?profile=original" target="_self"><img width="300" src="http://storage.ning.com/topology/rest/1.0/file/get/72918990?profile=RESIZE_320x320" width="300" class="align-right"/></a>CEO Frank Tsuru of Houston-based M3Midstream is investing over $1B across Eastern Ohio in a </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">rush to get into the Utica ballgame. His enthusiasm is generated by the incredible profit </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">margins which his company projects for Utica operators. He claims that based upon well results </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">to date, producers will achieve an internal rate of return of 91% over the life of the well(s). </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Incredibly, he claims that dwarfs even “the next-best shale play, the Eagle Ford in south Texas”. </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Producers there, according to Mr. Tsuru, have an average rate of return of about 60%. These </font></span><span style="font-family: Calibri; font-size: 12pt;">numbers all obviously tower over those of dry gas shale plays, including the Haynesville, </span><span style="font-family: Calibri; font-size: 12pt;">currently returning only 4% internally, and an area with little to no drilling activity.</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Now that we have established some basic parameters regarding completion cost and </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">production figures, we can comment intelligently about the economics of a typical Utica </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">completion in Ohio. For the purposes of our analysis, we will have to establish the following </font></span><span style="font-family: Calibri; font-size: 12pt;">two assumptions: 1) well cost of about $6.5 M each (from CHK stockholder reports), and 2) sustained production of 750 boe per day on average (a quite conservative figure, one that allows some consideration towards expected decline curves).</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Without a lesson in detailed accounting, including that specific to the industry, let us evaluate </font></span><span style="font-family: Calibri; font-size: 12pt;">the value of a typical completion. One way is to determine the value of a figure known as </span><span style="font-family: Calibri; font-size: 12pt;">PV-10% per well. This is a term specific to the industry which reflects the NPV (net present </span><span style="font-family: Calibri; font-size: 12pt;">value) of an asset or activity after discounting expected cash flows (before taxes or interest) by </span><span style="font-family: Calibri; font-size: 12pt;">10% per year. This is one manner in which the SEC allows exploration companies to disclose </span><span style="font-family: Calibri; font-size: 12pt;">the estimated value of their reserves as of a particular stated date. Alternatively, it may be </span><span style="font-family: Calibri; font-size: 12pt;">used to determine the effective ROI (return on investment).</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Let us analyze comments made by Cimarex Energy to their investors during a July 12, 2012 </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">presentation. They were reporting on two recent Bone Springs (Permian Basin) completions </font></span><span style="font-family: Calibri; font-size: 12pt;">which they described as having the highest rate of return of any assets in the entire company’s </span><span style="font-family: Calibri; font-size: 12pt;">portfolio, claiming the results compare favorably to the Bakken and Eagle Ford, once drilling </span><span style="font-family: Calibri; font-size: 12pt;">costs are taken into effect. Based upon this analysis, they are reportedly aggressively adding to </span><span style="font-family: Calibri; font-size: 12pt;">their acreage position there.</span><span style="font-family: Calibri; font-size: 12pt;"> </span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">The two wells analyzed during their presentation produced at 600 boe/d (at a cost of $6.5 M to </font></span><span style="font-family: Calibri; font-size: 12pt;">drill) and 850 boe/d (at a cost of $7.5-$8.0 M to drill) respectively. If our figures regarding </span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">assumptions for completion costs and average production rates are reasonably accurate, it is </font></span><span style="font-family: Calibri; font-size: 12pt;">clear that our economics would be even more impressive. Perhaps 125% superior or more, </span><span style="font-family: Calibri; font-size: 12pt;">depending. These wells did have a large percentage of production labeled as “oil” but no details </span><span style="font-family: Calibri; font-size: 12pt;">regarding specific production mixes.</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">During the same presentation, Cimarex also reported on two recent Wolfcamp Shale </font></span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">completions. At a cost to drill of about $8-$8.5 M and production of 250 bbl/day oil and 340 </font></span><span style="font-family: Calibri; font-size: 12pt;">bbl/day NGL’s (apparently averaged between the two wells), their completions translated into a </span><span style="font-family: Calibri; font-size: 12pt;">roughly 20-30% after-tax rate of return, a figure management seemed quite proud of. Again, </span><span style="font-family: Calibri; font-size: 12pt;">our average Utica completion will certainly meet or exceed these figures, especially after </span><span style="font-family: Calibri; font-size: 12pt;">adjusting for difference in production (higher) and drilling costs (lower). The production mix </span><span style="font-family: Calibri; font-size: 12pt;">reported to be 47% gas, 23% oil, and 30 NGL’s should also be comparable, and not require us to </span><span style="font-family: Calibri; font-size: 12pt;">make complex adjustments in comparing the two prospects.</span><span style="font-family: Calibri; font-size: 12pt;"> </span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Conclusion? If Cimarex considers these to be the highlights of their entire portfolio, they would </font></span><span style="font-family: Calibri; font-size: 12pt;">be damn proud to be possessing Utica holdings. Believe me, their expectations regarding </span><span style="font-family: Calibri; font-size: 12pt;">return on investment and as to stockholder profits are similar to every other participant in the </span><span style="font-family: Calibri; font-size: 12pt;">industry. No wonder 7 of the top 9 largest E&P companies are already represented here. You </span><span style="font-family: Calibri; font-size: 12pt;">can be assured they are all quite aware of recent ODNR estimates showing Utica potential of as </span><span style="font-family: Calibri; font-size: 12pt;">much as 5.5 B bbl oil and up to 15.7 tcf of natural gas (assuming a 5% recovery factor). An </span><span style="font-family: Calibri; font-size: 12pt;">Energy Analysts International, Inc. associate was quoted by Business First on 9/14/12 as having </span><span style="font-family: Calibri; font-size: 12pt;">predicted the Utica to become the third-largest continental production formation, potentially </span><span style="font-family: Calibri; font-size: 12pt;">pumping as many as 500,000 boe/day, a figure equating to 1% of total recoverable US </span><span style="font-family: Calibri; font-size: 12pt;">resources. Note: the USGS (U.S. Geological Survey) released a report dated 10/9/12 which </span><span style="font-family: Calibri; font-size: 12pt;">estimated “recoverable” Utica reserves to be in excess of 38 trillion cubic feet of natural gas </span><span style="font-family: Calibri; font-size: 12pt;">and over a billion barrels of undiscovered oil. As per Keith Kohl, chief pundit for Energy and </span><span style="font-family: Calibri; font-size: 12pt;">Capital, “this figure is likely low-balling the true amount of potential barrels in the play”.</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><b><font face="Times New Roman">Crunching Numbers for Gulfport’s Wagner 1-28H (Harrison County)</font></b></span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">In 2013 Gulfport Energy hit what was at that times being praised as the most prolific </font></span><span style="font-family: Calibri; font-size: 12pt;">Utica completion to date. Their Wagner 1-28H in Harrison County was labeled by industry </span><span style="font-family: Calibri; font-size: 12pt;">pundits as the “alpha dog” of the entire play , with production exceeding that even of </span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">CHK’s Buell well. The fact that both are in Harrison County speaks volumes as to the geology </font></span><span style="font-family: Calibri; font-size: 12pt;">there. As per their recent earnings call to stockholders, “the Wagner 1-28H was recently </span><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">brought online from its resting period and tested at a gross peak rate of 17.1 MMCF per day of </font></span><span style="font-family: Calibri; font-size: 12pt;">natural gas and 432 barrels of condensate per day. Based upon composition analysis, the gas </span><span style="font-family: Calibri; font-size: 12pt;">being produced is 1,214 BTU rich gas. Assuming full ethane recovery, the composition is </span><span style="font-family: Calibri; font-size: 12pt;">expected to produce an additional 110 bbls of NGL’s per MMCF of natural gas and result in a </span><span style="font-family: Calibri; font-size: 12pt;">natural gas shrink of 18%”.</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Translation? Let’s give it a try. First, the reference to the BTU being high (at 1,214) and being </font></span><span style="font-family: Calibri; font-size: 12pt;">described as being “rich” are indicators that the production is liquid rich. Second, the reference </span><span style="font-family: Calibri; font-size: 12pt;">to a “natural gas shrink” means that, through processing, they can convert much of the dry gas </span><span style="font-family: Calibri; font-size: 12pt;">into LNG’s but at an 18% conversion loss. The amount of production reported as being gas </span><span style="font-family: Calibri; font-size: 12pt;">(17.1MMCF) will be converted at an 82% rate vs. normal conversion into liquids. The trade for </span><span style="font-family: Calibri; font-size: 12pt;">losing 18% of the gas production (a net 3.078 MMCF loss) is a gain of 110 bbls liquids for every </span><span style="font-family: Calibri; font-size: 12pt;">MMCF sacrificed. In numerical terms, the 3.078 MMCF lost is valued at about $3/MCF for a </span><span style="font-family: Calibri; font-size: 12pt;">total of $9.234 sacrificed daily. The reward is 110 bbls liquid production from every million </span><span style="font-family: Calibri; font-size: 12pt;">cubic feet of that 17.1 MMCF of gas, a net of 181 barrels. Consequently, gas production (17.1 </span><span style="font-family: Calibri; font-size: 12pt;">MMCF) x value per bbl of liquid production ($110) = 1881 barrels of liquids (valued at about $35 </span><span style="font-family: Calibri; font-size: 12pt;">per barrel), a trade resulting in over $65,000 in additional net income daily.</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">We must now attempt to value the percentage of production which is dry but still of value. </font></span><span style="font-family: Calibri; font-size: 12pt;">Using a conversion factor of 6000 CF/boe, we can do just that. Remember, the gas production </span><span style="font-family: Calibri; font-size: 12pt;">must first be discounted by 18% due to the loss converting some of it to LNG. Total gas </span><span style="font-family: Calibri; font-size: 12pt;">production (17.1 MMCF) less 18%, is now 14.022 MMCF. Divide by 6000 as per the formula, </span><span style="font-family: Calibri; font-size: 12pt;">and you have 14,022,000/6000 for a total of 2337 boe.</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Add the production reported as being “condensate” which is 432 bbls/d to the LNG production </font></span><span style="font-family: Calibri; font-size: 12pt;">(post shrinkage) which is 1881 bbls/d to the 2337 bbls/d assigned to what had previously been </span><span style="font-family: Calibri; font-size: 12pt;">described as “natural gas” and you are looking at total production of 4650 bbls of oil equivalent </span><span style="font-family: Calibri; font-size: 12pt;">per day. A rough value of the production would be about $100,000 per day, based upon its </span><span style="font-family: Calibri; font-size: 12pt;">comparison to an analysis made by West Virginia Professor Tim Carr in relation to Gulfport’s </span><span style="font-family: Calibri; font-size: 12pt;">Stutzman well in Belmont County (4060 boe with similar BTU’s and liquid content). At that rate, </span><span style="font-family: Calibri; font-size: 12pt;">payout to the driller occurs in only 70 days. Remember, these wells will decline steadily over </span><span style="font-family: Calibri; font-size: 12pt;">time, so the $100,000 per day figure is not perpetual, but it is still impressive to recoup a $7M </span><span style="font-family: Calibri; font-size: 12pt;">investment in such a short time period. Gulfport is using longer laterals and more fracking </span><span style="font-family: Calibri; font-size: 12pt;">stages than competitors, incurring an additional half million dollars or so per well.</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><b><font face="Times New Roman">Gulfort’s Shugart 2-1H Well (Belmont County)</font></b></span></p>
<p><span style="font-family: Calibri; font-size: 12pt;">If you think Gulfport is proud of their Wagner well, they must be positively giddy about their </span><span style="font-family: Calibri; font-size: 12pt;">most recent completion. Anything close to what was reported by Equities.com on 10/9/12 </span><span style="font-family: Calibri; font-size: 12pt;">would almost certainly be the best well drilled in the continental US this calendar year, and </span><span style="font-family: Calibri; font-size: 12pt;">perhaps one of the best ever, period. Their Shugart 1-1H well in Belmont County reportedly </span><span style="font-family: Calibri; font-size: 12pt;">tested at a peak rate of 20 MMCF per day of natural gas, 144 bbls of condensate per day, and </span><span style="font-family: Calibri; font-size: 12pt;">2002 bbls of LNG per day. Assuming full ethane recovery and a natural gas shrink of 17%, net </span><span style="font-family: Calibri; font-size: 12pt;">production was calculated at an incredible 4,913 BOE daily. Even more mind blowing was their </span><span style="font-family: Calibri; font-size: 12pt;">11/27/12 announcement, that their new Shugart 1-12H Well had an initial production rate of </span><span style="font-family: Calibri; font-size: 12pt;">7,482 boe daily, a figure unheard of in the industry!! Keep an eye on this one for sure. Gulfport plans to drill 50 new wells in Ohio during 2013. </span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">That news was followed by a January 23 announcement regarding their first 2013 completions. </font></span><span style="font-family: Calibri; font-size: 12pt;">They seemed proud, rightfully so, to announce the fourth biggest producer thus far their </span><span style="font-family: Calibri; font-size: 12pt;">Stutzman well in Somerset Twp, Belmont County, which reportedly was producing 4060 bbls of </span><span style="font-family: Calibri; font-size: 12pt;">oil equivalent, including 21 Mmcf of natural gas and 945 bbls per day liquids (presumably </span><span style="font-family: Calibri; font-size: 12pt;">condensate). Their Clay well in Freeport Twp, Harrison County was impressive in its own right, </span><span style="font-family: Calibri; font-size: 12pt;">coming in at 2,226 boe daily to rank eighth thus far. Gulfport is dominating the production </span><span style="font-family: Calibri; font-size: 12pt;">numbers and it is no surprise that they have plans to drill 50 new Utica wells in Ohio during </span><span style="font-family: Calibri; font-size: 12pt;">2013.</span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Anyone who has been keeping up with this play knows that competitors, including Antero and Rice Energy have completed wells with production exceeding that of the Gulfport completions mentioned here. However, they were reportedly almost exclusively dry gas, although high quality with a BTU content of just over 1050. Production has been described as being “pipeline quality”.</font></span></p>
<p><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri"> </font></span></p>
<p><em><span class="font-size-3" style="font-family: helvetica;"><font face="Calibri">Almost all my blogs are original in nature (unless otherwise cited) and have reliable bibliographies to accompany each.</font></span></em></p>Chesapeake's French Connection May be Coming to an Endtag:gomarcellusshale.com,2014-06-01:2274639:BlogPost:5877432014-06-01T22:20:13.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p></p>
<p><br></br>On November 4, 2011, Chesapeake announced a joint venture agreement whereby they agreed to sell part of its holdings in the Utica Shale for $2.3 B. The announcement claimed that CHK would get $649 M from an undisclosed buyer in exchange for a 25% interest in 650,000 acres in Ohio's wet gas and volatile oil window. It's partner, Enervest, would receive $90 M in cash. Further, the buyer, now disclosed as France's TOTAL SA, agreed to pony up $1.5 B toward Chesapeake's drilling…</p>
<p></p>
<p><br/>On November 4, 2011, Chesapeake announced a joint venture agreement whereby they agreed to sell part of its holdings in the Utica Shale for $2.3 B. The announcement claimed that CHK would get $649 M from an undisclosed buyer in exchange for a 25% interest in 650,000 acres in Ohio's wet gas and volatile oil window. It's partner, Enervest, would receive $90 M in cash. Further, the buyer, now disclosed as France's TOTAL SA, agreed to pony up $1.5 B toward Chesapeake's drilling costs and $210 M toward ENV's costs.</p>
<p>Aubrey McClendon, then CHK's CEO and President of the Board, claimed the transaction would cover all of their acquisition costs in the field while selling the equivalent of only 10% of their acreage. Combined net proceeds likely netted them at least $3.4 B total. This transaction became the life blood to fund drilling for CHK and ENV as well as Aubrey's new American Energy Partners, who is participating in a JV covering much of the acreage CHK leased under his leadership.</p>
<p>Talk about a shot in the arm. These funds have enabled them to collectively drill over 500 wells to explore the Utica here in Ohio. It remains to be seen how this will work out long-term for TOTAL, but it has been a God-send for the other participants. They will surely be sad if the agreement ends as expected by year-end 2014. </p>
<p>It will be interesting to see if their drilling pace falls accordingly. Aubrey has proven himself to be a master fund raiser and, if they continue the recent rash of joint ventures, he may well provide the drilling capital necessary to continue at today's pace. CHK's challenging balance sheet may well prohibit them from being an attractive investment partner for those less brazen than Aubrey. ENV has previously signaled that they are more interested in shallow production and mid-stream activities, but they have surely enjoyed a nice ride as a result of the initial agreement. However, they are a very unlikely source to provide or raise significant drilling funds to propagate further drilling for the partners.</p>
<p>Considering their investment in acquisition, due diligence, drilling and mid-stream projects, it is unthinkable that their activities will be significantly curtailed. However, it will be interesting to see if a similar agreement is forthcoming, whether it be with TOTAL, Sinopec, CNOOC or other from overseas sources.</p>Shake and Bake: the advent of the resting periodtag:gomarcellusshale.com,2014-05-31:2274639:BlogPost:5875612014-05-31T23:46:43.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p></p>
<p>Chesapeake released some quite interesting news during their first quarter 2012 conference call. Apparently they discovered, entirely by accident, another factor impacting production numbers on their OH Utica completions. When the Buell Well was drilled in Harrison County, a minor problem prohibited them from immediately completing it. The unintended resting period allowed much of the water and frack fluid to dissipate prior to completion. Their Carroll County wells, drilled…</p>
<p></p>
<p>Chesapeake released some quite interesting news during their first quarter 2012 conference call. Apparently they discovered, entirely by accident, another factor impacting production numbers on their OH Utica completions. When the Buell Well was drilled in Harrison County, a minor problem prohibited them from immediately completing it. The unintended resting period allowed much of the water and frack fluid to dissipate prior to completion. Their Carroll County wells, drilled prior to or during this same time period, were completed as per their regular schedule. Suddenly, the resulting difference in production numbers was deemed to be not entirely geological. CHK thinks at least five of the wells in Carroll were "damaged".</p>
<p>Their policy now, which is certainly mimicked by competitors, is to allow a resting period between fracking and final completion of 30-60 days in the wet gas window and 60-90 days where they believe they will encounter volatile oil. Their belief is that this is beneficial due to the low water saturation of the shale and that the resting period allows permanent benefits. Fracking techniques in the Utica continue to be tweaked, not only as to this, but as to lateral lengths and number of fracking stages as well.</p>A Unique Energy Problem for Americatag:gomarcellusshale.com,2014-04-17:2274639:BlogPost:5680662014-04-17T19:29:31.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3"> </font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Houston and the rest of the U.S. Gulf Coast have more crude oil than the region can handle.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Stockpiles in the region centered on Houston and stretching to New Mexico in the west and Alabama in the east rose to 202 million barrels in the week ended April 4, the most on record, Energy…</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3"> </font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Houston and the rest of the U.S. Gulf Coast have more crude oil than the region can handle.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Stockpiles in the region centered on Houston and stretching to New Mexico in the west and Alabama in the east rose to 202 million barrels in the week ended April 4, the most on record, Energy Information Administration data released this week show.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Storage tanks are filling as new pipelines carry light, sweet oil found in shale formations to the coast and U.S. law keeps companies from moving it out. Most crude exports are banned and the 13 ships that can legally move oil between U.S. ports are booked solid. The federal Jones Act restricts domestic seaborne trade to vessels owned, flagged and built in the U.S. and crewed by citizens.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">“You can’t get all that light, sweet crude out, it’s all kind of piling up,” said Jeff McGee, the founder of Makai Marine Advisors LLC in Dallas, who previously led research at two shipbrokers and worked as a refinery planner. “You couldn’t find a spot Jones Act ship to save your life right now.”</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">The glut will make prices of benchmark West Texas Intermediate oil $13 a barrel cheaper later this year than Brent, the international benchmark, according to Bank of America Corp. forecasts. The EIA forecasts the average gap for 2014 will be about $9. WTI traded at a discount to Brent of $4.17 a barrel at 12:20 p.m. on the ICE Futures Europe exchange in London.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Companies including TransCanada Corp. and Enterprise Products Partners LP built and reversed pipelines that helped a carry a record amount of oil to the Gulf Coast from the Midwest last year. Total U.S. production reached 8.23 million barrels a day last week, the highest level since May 1988.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Inadequate fleet</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Thirteen tankers can haul crude domestically out of a global fleet of about 2,400, according to the U.S. Department of Transportation Maritime Administration. The Jones Act, a 94-year-old law, requires all domestic seaborne trade to be shipped on vessels crewed by citizens and owned, flagged and built in the U.S.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Meanwhile, a 1975 law bans most overseas U.S. crude shipments. While supplies to Canada, one of the exceptions allowed, have risen to a record, the U.S. exports 3 percent of the oil it produces, Energy Department data show.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Neither law will change soon. Mariners’ unions and domestic shipping companies say the Jones Act is critical to national security. Lawmakers are discussing ways to extend rather than curtail it, such as by requiring liquefied natural gas exports to go on U.S. ships.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Murkowski call</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Even as Senator Lisa Murkowski of Alaska, the senior Republican on the Energy and Natural Resources Committee, added her support to Exxon Mobil Corp.’s call to lift restrictions on crude exports, other lawmakers in Congress say they’re concerned shipments would increase gasoline prices at home.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">“The ban on exporting U.S. crude is mainly responsible for the pileup of crude stocks on the Gulf Coast,” said Harry Tchilinguirian, head of commodity markets at BNP Paribas, France’s largest bank. “The Jones Act is an additional hurdle in trying to move that surplus crude on the Gulf Coast to other areas of the U.S.”</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">The glut may start to shrink in the second quarter as refineries ramp up to meet summer gasoline demand. Plants on the Gulf Coast handled a record 7.92 million barrels a day of crude last year, equal to almost 80 percent of Chinese consumption in 2012, according to IEA and EIA data compiled by Bloomberg. Refinery runs in the region rose by 167,000 barrels a day to 8.22 million last week, EIA data show.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Falling imports</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Swelling inventories may also be curbed by falling crude imports, which last year averaged the lowest since 1996. U.S. refineries also exported a record 3.1 million barrels a day of gasoline, diesel and other petroleum products last year, EIA data show. The U.S. allows product exports.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">The American Petroleum Institute, which represents the U.S. oil and gas industry in Washington, is developing legal challenges to the crude export restrictions. Overturning the 1975 law would allow the U.S. to ship 1.5 million barrels a day and become one of the 10 largest crude exporters, according to JBC Energy, a Vienna-based consulting firm.</font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3"> </font></p>
<p style="margin: 0in 0in 10pt;"><font face="Calibri" size="3">Attributed to Naomi Christie @ Bloombergs</font></p>
<p></p>Why the Pt. Pleasant is Key to Utica Productiontag:gomarcellusshale.com,2014-04-01:2274639:BlogPost:5636892014-04-01T23:30:00.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p><b><font face="Calibri"> </font></b></p>
<p><font face="Calibri">The Point Pleasant formation has been described as marking the end of Middle Ordovician time. The Ordovician Period is characterized as the greatest submergence of the North American plate because shallow seas covered such an extensive area, including all of Ohio. In this environment, the Acadian mountain-building event occurred whereby sediments high in kerogen were shed from the highlands into a somewhat enclosed basin,…</font></p>
<p><b><font face="Calibri"> </font></b></p>
<p><font face="Calibri">The Point Pleasant formation has been described as marking the end of Middle Ordovician time. The Ordovician Period is characterized as the greatest submergence of the North American plate because shallow seas covered such an extensive area, including all of Ohio. In this environment, the Acadian mountain-building event occurred whereby sediments high in kerogen were shed from the highlands into a somewhat enclosed basin, lowering the amount of available oxygen. As they were buried and subject to the pressure and temperatures of the earth’s crust and core, the environment became conducive for the formulation of petrocarbons, especially oil and natural gas liquids. </font></p>
<p><font face="Calibri">The appropriate balance of hydrogen and carbon along with the corresponding favorable oxygen/carbon ratio (along with suitable temperature levels) created primarily type one or two kerogen content materials. Because they were formed from fossils containing mostly proteins and lipids, and to a lesser degree, from pollen, spores, or plant/animal decompositions, conditions became prime for oil or a mix of oil and wet gas. (*13) It is particularly important to recognize that the Utica and especially the Point Pleasant have both been identified as having high TOC (total organic content) and type one or two kerogen levels, two of the most important factors to realize if you are indeed searching for wet petrocarbons i.e. oil or natural gas liquids.</font></p>
<p><font face="Calibri">The Point Pleasant is characterized as having “three westward-thinning tongues of calcareous strata separated by shalier eastward-thinning tongues.” It is further described as being 60% limestone and 40% shale, interbedded, gray to bluish gray in color and up to 200’ thick in parts of Ohio. A well log which I located from a Tuscararas County well showed the Utica/Pt. Pleasant merged to create a 255’ core with an excellent TOC as high as 3.73%. Pretty damn impressive. Chris Perry, chief geologist with ODNR, claims the Point Pleasant to be the sweet spot of the entire play, with the highest TOC and a propensity to be highly brittle and contain significant natural fractures. Further, he claims formation thickness of as little as 50 feet to be commercially productive.</font><span style="font-family: Calibri;"> </span></p>
<p><font face="Calibri">ODNR’s Larry Wickstrom offers that the formation lies just beneath and adjacent to the Utica making the formation “actually thicker and higher in total organic content. It is very unusual. It is a black organic-rich crystalline limestone interlayered with black organic-rich shale. The Utica is a wonderful rock, but it is even better with the Pt. Pleasant beneath it. Since it is interlayered with the Pt. Pleasant, it is more frackable.” He believe the Utica/Pt. Pleasant package covers most of Ohio, but to what extent it will be commercially productive remains to be seem.</font></p>
<p><font face="Calibri">It is important to recognize it as being calcareous shale because it contains a high calcium carbonate content derived from ancient algae, which is the perfect content for petroleum formation. Consequently it is high in TOC and contains level one kerogen, making it a perfect source for formation of hydrocarbons, especially oil. The Point Pleasant and the Utica are both identified as having a much higher carbonate and lower mineral clay content than the Marcellus. It is exceptionally similar to the Eagle Ford. If only we are so lucky. Production and fracking techniques will likely be borrowed from experience gained in the Eagle Ford play. </font></p>
<p><font face="Calibri">The characteristics described in the preceding two paragraphs could easily be used to describe the Bakken. It is not a true shale play. Instead, it is various limestone and sandstone formations interbedden with shale. Consequently, it can achieve optimum production only through horizontal drilling and hydraulic fracturing. If this play is even remotely similar to the Bakken, we will truly be blessed. I am a believer. Of course, it may turn out to be more similar to the Eagle Ford……another good option. Our advantage over these two tremendous plays is significant. We are shallower, and will incur lower drilling costs. We can use fewer fracking stages and shorter laterals; and we have infrastructure in place to piggy-back off. </font></p>
<p><font face="Calibri">Gulfport Energy, who holds a leasehold interest in the Utica Shale in Ohio of as much as 65,000 net acres, has released the following prospectus as to their interest in the Utica shale here. They purport to have a drilling cost of less than or equal to the Bakken or the Eagle Ford. Further, and or more importance, they purport to have more oil in place, a higher recovery factor, better average formation thickness, and a much higher porosity then either the Bakken or the Eagle Ford. If they are only half right, this will truly be the best shale play in America, based upon potentially productivity and the simple economics of the deal. I may be biased, but my bias is based upon thorough research, which I deem to be most reliable.</font></p>
<p><font face="Calibri">Generally speaking, the Point Pleasant exists above the base of the Trenton limestone to the base of the Cincinnati group (Kope Formation). Of importance is noting that the source rocks of the Trenton limestone and the Point Pleasant formation have been credited with generating 75 billion bbl of oil. Of this, due to permeability of subsequent formations, some has migrated into the Silurian reservoirs, including the Clinton Sandstone.</font></p>
<p><font face="Calibri">Is the Pt. Pleasant really the key to the entire Utica Shale play here in Ohio? Time will tell, but so far it seems certain that the most productive areas certainly appear where the formation is quite prevalent. It seems to work almost like a conventional reservoir which traps hydrocarbons as they are migrating into the Utica. Word is that most frack jobs actually occur into the Pt. Pleasant rather than the Utica itself. It seems to be a wonderful trap for the condensate and NGL’s which exist in the area and which have been the source for much of the production and the hoopla associated therewith. </font></p>
<p><font face="Calibri">It is likely no coincidence that the wells drilled further North in Ohio have been disappointing. The Utica is much thicker in Mahoning and Trumbull counties, and BP and Halcon had hoped this would offset the nonexistence of the Pt. Pleasant there. So far they have been disappointed, Halcon so much so that they have abandoned their Ohio operations entirely. Perhaps technology will be developed soon to maximize results in that area and Halcon will reappear. Their leasehold is entirely HBP and unlikely to change in status anytime in the near future. For now, they seem more interested in pursuing the TMS (Tuscaloosa Marine Shale).</font></p>
<p></p>Potential Suitors for a Chesapeake Buy-outtag:gomarcellusshale.com,2014-03-23:2274639:BlogPost:5605462014-03-23T22:07:13.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p><font face="Calibri" size="3"> </font></p>
<p>Ever since billionaire Carl Icahn bought in last year, speculation has been that he would eventually force a sell-off of Chesapeake. He has already forced a number of divestitures including the recent sell of their pipeline, processing and mid-stream divisions. He is almost single-handedly credited with forcing the reluctant resignation of Aubrey McClendon and has a track record of controlling the company's leadership and…</p>
<p><font face="Calibri" size="3"> </font></p>
<p>Ever since billionaire Carl Icahn bought in last year, speculation has been that he would eventually force a sell-off of Chesapeake. He has already forced a number of divestitures including the recent sell of their pipeline, processing and mid-stream divisions. He is almost single-handedly credited with forcing the reluctant resignation of Aubrey McClendon and has a track record of controlling the company's leadership and finances. </p>
<p> </p>
<p>Almost immediately upon acquiring a 7.6% interest in 2012, Icahn forced a huge sale by CHK of all Fayetteville Shale assets to BHP Billiton, a perfect example of how the corporate oil and gas business works. Further, he teamed up with Southeastern Asset Management (holding a 13.6% share) to shake up the entire board of directors. Of the four member immediately replaced, Icahn personally selected one, with Southeastern proposing the other three. He vowed to "personally retool" the company with plans to implement "cost savings initiatives" and a more conservative spending approach. Rumors that he intended to push for the sale of pipelines and gas processing plants have already been proven true. Prior to their recent sell off of the entire midstream division, Icahn had maneuvered to make a $4 B pipeline sale to Global Infrastructure. Money speaks loudly in the corporate world.</p>
<p> </p>
<p>Now that he holds as much as a 10% interest, Icahn is wielding even more power. He reportedly is seeking a cash bid for the company, possibly for as much as $40 per share. But who would their suitors be, and why would they have interest in a debt-ridden, cash strapped company?</p>
<p> </p>
<p>Since early 2012, speculation as to a CHK fire sale had begun. Seeking Alpha entitled their May 30, 2012 article “Is a Buyout CHK’s Only Hope”? They, along with Bloomberg, were already speculating that Exxon, Chevron, and Shell are all analyzing just that possibility. Almost everyone agrees that their asset portfolio is unparalleled on-shore in America. However, Chesapeake is of interest to each for other reasons as well.</p>
<p> </p>
<p>Exxon, despite being the world’s largest energy company (with a market value of $373 B) has seen their oil and gas production decline steadily for the last three straight quarters. Bloomberg says that they “desperately need” to boost production and may well look to acquire CHK as a quick fix. Chesapeake’s debt is of less concern to them considering that they are sitting on at least $19 B in cash right now. Phil Adams, a Chicago-based debt analyst with Gimme Credit LLC rates them as the most likely suitor for several reasons. They have not only the highest corporate credit rating, but can easily buy in without incurring any damage to such.</p>
<p> </p>
<p>Speculation regarding Chevron is similarly grounded. Their year-over-year production numbers have fallen for five straight quarters but they are sitting on a pile of cash similar to Exxon’s. “For somebody like an Exxon or Chevron”, according to Suntrust’s Neil Dingman, “they just don’t have much in the way of production growth right now, and the easiest way to get that is to go out and acquire it. Both are sitting on billions of dollars of cash right now that’s really not doing anything.” Hence, CHK may be an incredibly attractive acquisition prospect for them right now, despite their unattractive balance sheet.</p>
<p> </p>
<p>Shell may be greatly interested for different reasons altogether. Despite being Europe’s biggest oil company, buying CHK would greatly reduce their exposure to regions with higher political risk. About a third of their production last year originated in Africa and Asia, according to their annual report. Huntington’s Paul Sorrentino summed it up quite nicely saying “If you want to try to clean up and eliminate some of your political and geographic risk, these (CHK’s) assets would be quite attractive. Chesapeake has quite a bit of drama surrounding it, but that doesn’t change the fact that these are very desirable assets”.</p>
<p> </p>
<p>Speculation that Shell and/or Chevron have interest in CHK holdings were confirmed September 12, 2012 when the Canton Rep (via AP) reported that CHK had sold a considerable portion of its Permian Basin holdings to a subsidiary of each. Details were sketchy, but the transaction, described as a “series of deals” was valued at $6.9B. Once closed, they will allow Chesapeake to have liquidated assets and holdings in the amount of $11.6 B. This equated to about 85% of their full-year goal of $13-$14B, “which we expect to achieve by year end”, as per then CEO McClendon. That same day, they announced the sale of unspecified Utica Shale assets to undisclosed buyers in the amount of $600 M. Apparently this is a small part of an offering announced previously and discussed below.</p>
<p> </p>
<p>Whichever suitor may appear, they will have to cope with seven joint ventures and $13.1 B in debt. “Many people think CHK is too convoluted and too complicated to have somebody buy it out,” says Dingman in a telephone interview reported by Bloomberg. However, other analysts disagree. “For any of the major integrated oil companies that want to pick up reserves on the cheap, this would be a good opportunity,” says Sorrentino. With natural gas almost certainly at its absolute bottom, CHK will be “worth a whole lot more in the near future than they are today. We’ll look back on this and say, ‘Wow, this was really an opportunity.’ There may be some people that end up kicking themselves.”</p>
<p> </p>
<p>Stay tuned……</p>
<p> </p>
<p></p>The Truth about the Utica Shaletag:gomarcellusshale.com,2014-03-23:2274639:BlogPost:5606172014-03-23T22:00:00.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p><span style="font-family: Calibri;">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…</span></p>
<p><span style="font-family: Calibri;">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.</span></p>
<p><font face="Calibri">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?”</font></p>
<p><font face="Calibri"><a href="http://storage.ning.com/topology/rest/1.0/file/get/72919027?profile=original" target="_self"><img width="400" src="http://storage.ning.com/topology/rest/1.0/file/get/72919027?profile=RESIZE_480x480" width="400" class="align-right"/></a>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…..</font></p>
<h2><font color="#4F81BD" face="Cambria" size="4">ODNR’s 2012 Production Report</font></h2>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<h2><font color="#4F81BD" face="Cambria" size="4">What drillers have learned – both good and bad…..</font></h2>
<p><font face="Calibri">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. </font></p>
<p><font face="Calibri">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).</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<h2><font color="#4F81BD" face="Cambria" size="4">Specifics regarding Utica production….</font></h2>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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…..</font></p>
<p><font face="Calibri">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.</font></p>
<h2><font color="#4F81BD" face="Cambria" size="4">NGL’s vs. condensate….</font></h2>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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. </font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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. </font></p>
<p><font face="Calibri">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?</font></p>
<h2><font color="#4F81BD" face="Cambria" size="4">Midstream’s $10B gamble…..</font></h2>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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…..</font></p>
<p><font face="Calibri">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. </font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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…..</font></p>
<h2><font color="#4F81BD" face="Cambria" size="4">Who will paint the picture for 2013 production??</font></h2>
<p><font face="Calibri">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”.</font></p>
<p><font face="Calibri">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.</font><span style="font-family: Calibri;"> </span></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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? </font></p>
<p><font face="Calibri">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. </font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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.</font></p>
<p><font face="Calibri">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. </font></p>
<p><font face="Calibri">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. </font></p>
<p><font face="Calibri">Further, affiant sayeth naught!</font></p>
<p><font face="Calibri"> </font></p>Royalty Rip Off? The Case Against Chesapeaketag:gomarcellusshale.com,2014-03-23:2274639:BlogPost:5605512014-03-23T22:00:00.000ZJohn Hhttps://gomarcellusshale.com/profile/jwh
<p><br></br> Joe Drake (Abrahm Lustgarten for Propublica)</p>
<p>This story was co-published with The Daily Beast.</p>
<p>At the end of 2011, Chesapeake Energy, one of the nation's biggest oil and gas companies, was teetering on the brink of failure. Its legendary chief executive officer, Aubrey McClendon, was being pilloried for questionable deals, its stock price was getting hammered and the company needed to raise billions of dollars quickly.</p>
<p>The money could be…</p>
<p><br/> Joe Drake (Abrahm Lustgarten for Propublica)</p>
<p>This story was co-published with The Daily Beast.</p>
<p>At the end of 2011, Chesapeake Energy, one of the nation's biggest oil and gas companies, was teetering on the brink of failure. Its legendary chief executive officer, Aubrey McClendon, was being pilloried for questionable deals, its stock price was getting hammered and the company needed to raise billions of dollars quickly.</p>
<p>The money could be borrowed, but only on onerous terms. Chesapeake, which had burned money on a lavish steel and-glass office complex in Oklahoma City even while the selling price for its gas plummeted, already had too much debt.</p>
<p>In the months that followed, Chesapeake executed an adroit escape, raising nearly $5 billion with a previously undisclosed twist: By gouging many rural landowners out of royalty payments they were supposed to receive in exchange for allowing the company to drill for natural gas on their property.</p>
<p>In lawsuits in state after state, private landowners have won cases accusing companies like Chesapeake of stiffing them on royalties they were due. Federal investigators have repeatedly identified underpayments of royalties for drilling on federal lands, including a case in which Chesapeake was fined $765,000 for "knowing or willful submission of inaccurate information" last year.</p>
<p>Last month, Pennsylvania governor Tom Corbett, who is seeking reelection, sent a letter to Chesapeake's CEO saying the company's expense billing "defies loqlc" and called for the state Attorney General to open an investigation.</p>
<p>The losers were landowners in Pennsylvania and elsewhere who leased their land to Chesapeake and saw their hopes of cashing in on the gas-drilling boom vanish without explanation. People like Joe Drake.</p>
<p>"I got the check out of the mail. .. I saw what the gross was," said Drake, a third-generation Pennsylvania farmer whose monthly royalty payments for the same amount of gas plummeted from $5,300 in July 2012 to $541 last February. This sort of precipitous drop can reflect gyrations in the price of gas. But in this case, Drake's shrinking check resulted from a corporate decision by Chesapeake to radically reinterpret the terms of the deal it had struck to drill on his land. "lf you or I did that we'd be in jail," Drake said.</p>
<p>Chesapeake's conduct is part of a larger national pattern in which many giant energy companies have maneuvered to pay as little as possible to the owners of the land they drill. Last year, a ProPublica investigation found that Pennsylvania landowners were paying ever-higher fees to companies for transporting their gas to market, and that Chesapeake was charging more than other companies in the region. The question was •why"?</p>
<p>ProPublica pieced together the story of how Chesapeake shifted borrowing costs to landowners from documents filed with the U.S. Securities and Exchange Commission, interviews with landowners, people who worked for the company and employees at other oil and gas concerns.</p>
<p>The deals took advantage of a simple economic principle: Monopoly power.</p>
<p>Boiled down to basics, they worked like this: When energy companies lease land above the shale rock that contains natural gas, they typically agree to pay the owner the market price for any gas they find, minus certain expenses.</p>
<p> <br/> Federal rules limit the tolls that can be charged on inter-state pipelines to prevent gouging. But drilling companies like Chesapeake can levy any fees they want for moving gas through local pipelines, known in the industry as gathering lines, that link backwoods wells to the nation's interstate pipelines. Property owners have no alternative but to pay up. There's no other practical way to transport natural gas to market.</p>
<p>Chesapeake took full advantage of this. In a series of deals, it sold off the network of local pipelines it had built in Pennsylvania, Ohio, Louisiana, Texas and the Midwest to a newly formed company that had evolved out of Chesapeake itself, raising $4.76 billion in cash.</p>
<p>In exchange, Chesapeake promised the new company, Access Midstream, that it would send much of the gas it discovered for at least the next decade through those pipes. Chesapeake pledged to pay Access enough in fees to repay the $5 billion plus a 15 percent retum on its pipelines.</p>
<p>That much profit was possible only if Access charged Chesapeake significantly more for its services. And that's exactly what appears to have happened: While the precise details of Access' pricing remains private, immediately after the transactions Access reported to the SEC that it collected more money to move each unit of gas, while Chesapeake reported that it also paid more to have that gas moved. Access said that gathering fees are its predominant source of income, and that Chesapeake accounts for 84 percent of the company's business.</p>
<p>What's more, SEC documents show, Chesapeake retained a stake in the gathering process. While Chesapeake collected fees from landowners like Drake to cover the costs of what it paid Access to move the gas, Access in turn paid Chesapeake for equipment it used to complete that process, circulating at least a portion of the money back to Chesapeake.</p>
<p>ProPublica repeatedly sought comment and explanations from both Chesapeake and Access Midstream over the course of several months. Both companies declined to make executives available to discuss the deals or to respond to written questions submitted by ProPublica.</p>
<p>Days after the last of the deals closed, Drake and other landowners learned the expense of sending their gas through Access's pipelines would eat up nearly all of the money they had been previously earning from their wells. Some saw their monthly checks fall by as much as 94 percent.</p>
<p>An executive at a rival company who reviewed the deal at ProPublica's request said it looked like Chesapeake had found a way to make the landowners pay the prinCipal and interest on what amounts to a multi-billlon loan to the company from Access Midstream.</p>
<p>"They were trying to figure out any way to raise money and keep their company alive," said the executive, who declined to be named because it would jeopardize his dealings with Chesapeake. "l think they looked at it as an opportunity to effectively get disguised financing ... that is going to be repaid at a premium."<br/> .......</p>
<p><br/> At 54, Joe Drake guns his six-wheeler up a steep rock-rutted trail on the backwoods of his 494-acre tract and points to his property line, marked by a large maple in a sea of indistinguishable trees. He knows where it lies, because as a kid his father made him walk that line to string barbed wire. The wire is long gone, but a rusted snag remains entombed in the bark. Back then, the Drakes ran a dairy farm in these pastures.</p>
<p>"It's just something you've got in your blood that you do," Drake said. "But dairy farmers are a dying breed ... It was a good way of life. Today, the milking stalls have been ripped out of a long bam that still carries the stench of their manure, but stores 20 -foot stacks of bailed hay instead. Drake sold all 187 head of cattle two years ago, pinched by regulated milk prices and the rising costs of independent farming. He took out a second mortgage to keep the farm afloat.</p>
<p> <br/> Across the road, past his house and just beyond a stand of oak and ash, the hillside's natural shape transitions to a steep slope of pushed dirt, capped by a 7-acre flat the size of a large gravel parking lot. In the middle stands a 6-foot stack of steel pipes and valves - a gas well.</p>
<p>When Chesapeake arrived at Drake's door, he was optimistic. Drake plastered a "Drill, baby, drill" bumper sticker in the window of his Ford F-250 pickup. He welcomed the chance todraw an easy income from his land, and was unswayed when his neighbors raised questions about the environmental risks of drilling. Chesapeake promised Drake one-eighth the value of whatever it made from his well. It seemed like a fair deal.</p>
<p>If any driller was going to make money for Drake, he thought, it would be Chesapeake. The company had built an empire off finding and drilling natural gas discoveries as the fracking boom rolled across the country. With uncanny foresight, its founder, McClendon, locked up exclusive access to immense tracts of land across the country by promising property owners that their lives would be transformed by the wealth the gas under it would bring.</p>
<p>Then the company drilled furiously -- in Oklahoma, then Texas, Louisiana and later in Pennsylvania's Marcellus Shale - catapulting itself to the rank of second-largest producer of natural gas in the United States. It made McClendon - who snatched up a stake in the Oklahoma City Thunder basketball team and moved into a stone mansion in the posh Oklahoma City suburb of Nichols Hills - one of the richest men in the world.</p>
<p>McClendon - named by Forbes in 2011 as "America's Most Reckless Billionaire" - would find his way into plenty of personal trouble. He took a personal stake in Chesapeake's wells, and then liquidated his stock in the company in order to cover his own losses, rattling investors and ringing corporate governance alarm bells. He drew scrutiny for selling his $12 million antique map collection to the company and ire for taking a $75 million bonus as Chesapeake struggled.</p>
<p>In 2012, he borrowed as much as a billion dollars from the company's private equity partners to fund his private interests. Separately, an investigation by Reuters alleged Chesapeake had rigged land leasing prices in Michigan, under McClendon's direction, sparking a federal criminal probe.</p>
<p>But McClendon's overarching design for the business nonetheless made it a formidable player. Chesapeake aggressively pursued business opportunities beyond its drilling. It created interlocking businesses and took advantage of tax breaks that deliver out-sized benefits to energy companies.</p>
<p>By structuring itself this way, Chesapeake eamed a slice of profit from each step. Chesapeake's subsidiaries trucked the drilling materials, drilled the wells, fracked the gas, gathered and piped it away to a hub, and then marketed the end product - what economists call vertical integration. In fact, he built Chesapeake into a powerhouse, an echo of the old Standard Oil empire, positioned to control almost every variable and armed with the leverage to get its way.</p>
<p>Neither McClendon nor his staff responded to requests for comment for this article.</p>
<p>From early on, the company viewed the local pipelines as a profit source. Chesapeake formed subsidiaries to build and run the lines, then spun them off into a separate, publicly traded company. That company would eventually evolve into Access Midstream, when Chesapeake sold its shares - one of the three deals - for $2 billion in 2012.</p>
<p>The strategy paid dividends. At Chesapeake's headquarters, a group of new, distinctively-designed office buildings went up, with views south over the state capital and the city's small skyline. The company lavished its employees with perks, too. "They've got a 72,OOO-square-foot gym, free trainers ... free Thunder tickets," said Andrea Watiker, who scheduled pipeline capacity for gas traders in one of the company's new towers.</p>
<p>Confident he was in good hands, Drake endured the trucks, dirt and noise that accompanied gas drilling and signed agreements that allowed Chesapeake to run pipelines across his fields. To transport the gas from Drake's well, Chesapeake built a pipeline that stretched south from within spitting distance of the New York border, cutting a wide swath through the forest. Then it went down beyond the white-spired church in Litchfield, and ran some 35 miles further to its handoff at the Tennessee interstate pipeline near the Susquehanna River. What Drake didn't know at the time was that the pipeline was more than a way to move his gas to market. It would become part of a strategy to make more money off of Drake himself.<br/> **.</p>
<p>When the first gas flowed from the well on Drake's land in July 2012, it was abundant, and the royalty checks were fat. "We was hoping to get these loans paid off ... with the big money," said Drake, who earned more than $59,400 from the first few months of production, referring to the mortgages on his farm.</p>
<p>That year, many Pennsylvania landowners began receiving similarly sized payments as thousands of new wells - many of them drilled by Chesapeake -- finally began producing gas. Pennsylvania fast approached Texas as the largest source of natural gas in the country, and with it, the prosperity long promised to this rural part of the United States seemed about to arrive.</p>
<p>But then, in January 2013, without warning or explanation, the expenses withheld from Chesapeake's royalty checks for use of the gathering pipelines tripled. Drake's income dwindled. His contract with Chesapeake - and Pennsylvania law that sets a minimum royalty share in the state - promised him at least 12.5 percent of the value of the gas. Drake says the company led him to believe any expenses would be negligible. "Well, they lied."</p>
<p>A few miles away, the same month, his brother-in-law had 94 percent of his gas income withheld to pay for what Chesapeake called "gathering fees.' Others across the northern part of the state also saw their income slashed. "I've got a stack," said Taunya Rosenbloom, a lawyer representing Pennsylvania landowners with natural gas leases. She pulled the statements of all of her Chesapeake clients into an eight-inch pile on her desk. "Everyone is having this issue." Drake found the statements Chesapeake mailed him each month mystifying. He pored over the papers, hired a lawyer, compared notes with his neighbors, but couldn't make sense of the charges.</p>
<p>Other Pennsylvanians were similarly baffled. Sometimes, Chesapeake charged different fees to neighbors whose wells fed into the same gathering line. Other times, companies that had partnered with Chesapeake on the same well charged vastly less for expenses. No one at the Chesapeake could seem to explain how the charges were set.</p>
<p>"There is no rhyme or reason why one client would have such an exorbitant amount taken out when another no more than 3 miles away has only 20 percent of their royalty taken," said Harold Moyer, an accountant in Bradford County, Pa., who represents more than 150 landowners with royalty rights. Moyer said he saw a dramatic difference between what Chesapeake usually charged compared to other energy companies in the area.</p>
<p>Different contracts may entitle Chesapeake to charge varying amounts. Some of the leases examined by ProPublica limit a landowner'S share of expenses to 12.5 percent - or the same as their share of the proceeds. Other contracts prohibit Chesapeake from withholding any expenses at all. Drake's contract appears to allow Chesapeake to recoup as much money as it wants; it stipulates that he can be charged for the expense of gathering and transporting his gas without specifying his share of such expenses.</p>
<p>Gas drillers differ Significantly in how much they charge landowners for expenses. The Norwegian energy company Statoil owns a portion of the gas extracted from Drake's well, as well as a portion of the gathering line that moves the gas to an interstate pipeline. Yet Statoil rakes off virtually nothing for its expenses, according to its statements. Statoil told ProPublica that it sells its gas independently and makes decisions about billing separately from Chesapeake.</p>
<p>"When it comes to deciding which, if any, deductions are appropriate, we make that assessment according to the terms of each lease and the applicable laws,• wrote Ola Morten Aanestad, in an e-mailed response to questions.</p>
<p>Orake peers out the window, over the hills that descend from his porch into a valley brightening with the changing colors of fall, and scowls. He can't stand being indoors. He's worried that he'll spend most of next hunting season here at this table, trying to decipher Chesapeake's statements. His monthly gas statements pile up, unorganized, on the kitchen table, below a rack of deer antlers and beside two empty cans of Coors Light and a camouflage baseball cap.</p>
<p>Drake's gathering pipeline only extends a few dozen miles, far less distance than the interstate pipeline it feeds into that carries his gas through New Jersey towards White Plains, NY. Yet public documents filed with the Federal Energy Regulatory Commission show it only cost about $.38 - on average -- to move a unit of gas on the interstate system - a fraction of the $2.94 Chesapeake charged Drake to move a unit of gas a vastly shorter distance that February."Nobody can tell you why or how come," Drake said. "They pass the buck, they tell you to call this person, and you are lucky if you can even get an answering machine.•</p>
<p>Chesapeake declined to explain its charges to Drake or to ProPublica. When a ProPublica reporter visited Chesapeake's headquarters in Oklahoma City, the company's director of external communications sent a message that he was "booked solid" and couldn't talk .</p>
<p>..**</p>
<p>There has long been dispute over how drilling companies calculate royalty payments due landowners. A 2007 report commissioned from a forensic oil and gas accountant by the National Association of Royalty Owners (NARO) - an organization representing landowners in their dealings with the oil and gas industry - found that almost every company it examined had "used affiliates and subsidiaries to reduce income to royalty owners and taxing authorities. "</p>
<p>charging landowners, on average, 43 percent more than what they actually paid to handle the gas. (Neither Chevron nor Chesapeake provided information about their expense deductions. )<br/> ConocoPhillips and BP declined to comment for this article. Chevron did not respond to a request for comment.</p>
<p>Other companies have been ensnared in similar controversies. The giant pipeline company, Kinder Morgan, which also declined to speak to ProPublica, has been accused by Montezuma County, Colo., of overstating its transportation and other expenses, and underpaying $2 million in taxes as a result. (Kinder Morgan has paid that bill, but is appealing the decision.) Chevron has faced multiple lawsuits for underpaying royalties and overstating expense deductions because of alleged self-dealing through its affiliate relationships, including a 2009 case the company settled with the U.S. Department of Justice for $45 million.</p>
<p>"Every company has been involved," said Jeffrey Matthews, a vice president and forensic accounting expert at Charles River Associates, a consulting firm, in a lecture to landowners and oil and gas industry accountants in Houston. "If you're dealing with related parties," the technical term for the sort of inter-lOCking subsidiaries created by Chesapeake, "the costs can be double, or triple. You don't know if you are paying for something two to three times over."</p>
<p>Even so, Chesapeake stands out among its peers and is widely known to interpret contracts to match its strategies, executives in the oil and gas industry say. The company has faced numerous lawsuits - filed by the billionaire Ed Bass, and the city of Fort Worth, among others - claiming it misrepresented its expenses. Chesapeake has paid hundreds of millions of dollars in settlements and judgments in such cases, including a $7.5 million settlement with Pennsylvania landowners last fall.<br/> <br/> One Oklahoma lawsuit, brought by other oil companies that had partnered with Chesapeake, alleged that Chesapeake cheated them out of the final sales price of their gas and artificially inflated its operating expenses, in part by folding in the salaries of high-level management, the cost of seminars they attended, and rent and office expenses for field offices. The suit was settled in late 2004 for $6.5 million. Chesapeake denied any wrongdoing, and the settlement explicitly states that Chesapeake did not agree to "chanqe the practices complained of' in the lawsuit.</p>
<p>"They were making excessive, unwarranted, and unauthorized charges: said Charles Watson, an Oklahoma attorney involved in the case. "I don't think it's mistaken interpretation, I think it's an intentional accounting maneuver to reduce the amount of money going to the royalty owners and increase the amount of money going to the operator."</p>
<p>Chesapeake declined to comment about the case.</p>
<p>For Drake to know how Chesapeake calculated his gathering costs, he has to pay lawyers and accountants to audit the company, or take his grievance to arbitration, a process that would cost him tens of thousands of dollars. In either case, he would need to see the purchase agreements that describe the company's gas sales in detail. They list far more precisely than Drake's own statements exactly what costs were incurred, how much gas might have been lost along the way or used by the company for its own purposes, what marketing fees Chesapeake's subsidiary charged, and the final, real price of the gas.</p>
<p>But Chesapeake isn't required to share these agreements. They are proprietary."When it comes to production expense," said Charles River's Matthews, "you're at their mercy: ......The deals that led to much higher expense charges for Drake and his neighbors involve some sophisticated financial engineering.</p>
<p>Over 12 months, Chesapeake sold off a significant portion of its nationwide system of gathering pipelines in three separate transactions. By December 2012, almost all of the pipes were controlled by a single company Chesapeake's former affiliate, Access Midstream. Taken together, the sales brought $4.76 billion in cash into Chesapeake's coffers.</p>
<p>The reason behind the moves was simple: All that profligate spending - the Oklahoma City offices, corporate jets and huge executive salaries -- had come at roughly the same time that the price of gas tumbled to historic lows, analysts at several Wall Street investment firms told ProPublica. Chesapeake "desperately needed cash," observed Tony Say, who once headed Chesapeake's Marketing division - the same part of the company that now handles transportation for the gas.</p>
<p>In its securities filings, Chesapeake said that the deals brought the company $1.76 billion more than it had invested to build and maintain its pipelines and the companies that ran them, leaving the impression that the sales were an unqualified boon for Chesapeake. But a look at an SEC filing by Access Midstream tells a different story: Chesapeake was going to have to give much of that money back.</p>
<p>On the same day as the last of the major sales, Chesapeake signed long-term contracts pledging to pay Access a minimum fee for transporting its gas. In some cases, the fee held no matter what happened to the price of gas, or even how little of it flowed out of Chesapeake's wells. Chesapeake also promised to connect every new well it drilled to Access's lines for the next 15 years in Ohio's Utica Shale, a potentially lucrative emerging drilling field, and made similar agreements elsewhere.</p>
<p><br/> According to ProPublica projections based on figures disclosed by the companies in late 2013, Chesapeake's commitments would have it paying Access a whopping $800 million each year. Over ten years, the contracts would generate nearly twice as much money as Access had paid Chesapeake for its businesses in the first place.</p>
<p>In plain words, Chesapeake and a company made up of its old subsidiaries were passing money back-and-forth between each other, in a deal that added little productive capacity but allowed both sides of the transaction to rake in billions of dollars.</p>
<p>Access' chief executive, J. Mike Stice, told a group of investment banking analysts last September that the deals amounted to a "low-risk business model" that "most people haven't understood.""Nobody really has the access to contractual growth that [Access Midstream} has," Stice said."lt doesn't get any better than this:</p>
<p>The SEC filings provide other detail about the ways that the two companies devised to remain inextricably linked, even though Chesapeake has sold the stake it once had in Access.</p>
<p>At the same time it signed its contracts, Access pledged to subcontract a slice of its business back - again - to companies still owned by Chesapeake. It also agreed to buy industrial equipment used to compress the gas for the pipelines from a company owned by Chesapeake. In essence, Chesapeake would get a rebate on the fees it had guaranteed to Access. Chesapeake never answered questions about whether that rebate was figured in to the price it charged Joe Drake and his neighbors.</p>
<p>In its royalty statements to Joe Drake, Chesapeake says the expenses it had deducted reflect what it costs the company to move his gas. The company has said in public statements about the royalty disagreements in Pennsylvania that it is merely recouping its costs. But ProPublica's projections drawn from figures previously reported by both companies show that Chesapeake could earn back billions of dollars of the transportation fees it is paying Access over the next 10 years.</p>
<p>There are other ties between the two companies. Access's Chief Executive, Stice, once worked for McClendon as the chief operating officer of one of the companies that used to run the pipelines. Chesapeake's chief financial officer, Dominic del Osso, sits on the board of Access Midstream Partners, and as of 2011, according to SEC records, owned thousands of shares of Access stock.</p>
<p>The relationships raise questions about Chesapeake's assertions that its contracts are arm's-length agreements, and that its expenses reflect its true cost of operating. "They had a lot of disguised debt,' said Philip Weiss, a chief investment analyst with Baltimore Washington Financial Advisors, who has covered Chesapeake over the years, and was often concerned that the company has understated its financial obligations. In this case, he said, Chesapeake's expensive contracts with Access might not just be the cost of operating, but another unusual long-term financial obligation that would weigh down the company, but which . wouldn't be reflected in the normal measures of debt. "The use of off-balance-sheet debt is often a way to try to avoid getting as much investor scrutiny:</p>
<p>For six months Chesapeake declined to answer questions about these discrepancies posed by ProPublica. But in its latest annual financial filings made public just two weeks ago, Chesapeake noted for the first time that it had $36 billion worth of what it called "off-balance-sheet arrangements," including $17 billion of long-term commitments to buy gathering services. This appears to be the first time the company has acknowledged that it owes more money than what has been identified as debts in previous SEC filings.</p>
<p>In the filings, Chesapeake said that the $17 billion figure didn't include reimbursement from royalty owners, and that landowners and corporate partners alike "where appropriate, will be responsible for their proportionate share of these costs."</p>
<p> <br/> In an earlier, September 2013 quarterly filing, there were hints of the same activity, but with no disclosure of the salient details to shareholders that might help them understand what was really going on. Chesapeake reported that its expenses related to its pipeline and marketing business roughly doubled in the months after it sold its pipelines, compared to the same period a year earlier, and that its revenues for that part of its business also increased accordingly, covering the new costs. Chesapeake told investors it had cost the company more than $8 to transport a cubic foot of gas or its oil equivalent - an astronomical amount unheard of in the energy industry.</p>
<p>•Something is wrong with this calculation," said Fadel Gheit, a seasoned industry analyst for the investment firm Oppenheimer, who estimated the figure was off by a decimal point before later confirming that it matched the numbers Chesapeake had reported to the SEC. "It can't be."</p>
<p>In fact, none of the financial analysts who cover Chesapeake that ProPublica spoke with could explain the explosion in Chesapeake's marketing and transportation revenues and expenses using oil sales alone.</p>
<p>"The change in marketing, gathering, compression revenue and expense is staggering,• wrote Kevin Kaiser, a financial analyst with Hedgeye, a private equity group in New York, in an email to ProPublica.</p>
<p>Neither Chesapeake's investor relations group, nor its media staff would comment on whether the deals amounted to disguised debt that landowners would repay. In interviews, one former Chesapeake employee with knowledge of the company's operations dismissed the notion that Chesapeake was essentially paying back an off-balance-sheet loan by paying unusually high fees for use of the pipelines.</p>
<p>"The timing supports that - that Chesapeake got paid a lot of money and the gathering fees get paid back over time, and it looks like a loan arrangement: said the former employee. "But to jump to the conclusion that the whole thing is a sham and a means by which they are going to defraud royalty owners is not true.•</p>
<p>Only in its latest filing at the end of February, after months of queries from ProPublica, did Chesapeake add a note two sentences in 299 pages - stating that its contracts with Access and other companies played into the rising figures. But the company did not specify how much.</p>
<p>And to the extent that the real costs of gathering and transporting gas can be gleaned from securities reports and Joe Drake's own statements, there's still a big gap between what Chesapeake reports it paid out, and what Access reports it received for gathering services.</p>
<p>In the mean time, one thing is for sure: all the escalating costs, side deals, and unexplained debt aside, Access is making more money than ever, while Chesapeake - so recently fighting to stay alive - has emerged from its troubles and is turning a profit.</p>
<p>Joe Drake, on the other hand, is almost back to where he began.</p>
<p>He recently cancelled a fishing trip to Canada and doubled back on the question of how to make a living from the farm. With his livestock gone he will now focus on growing and bundling hay, which he will sell to other farms so they can feed their animals. The natural gas boom has become little more than a sideshow.</p>
<p>"We are surviving," he said. "But we learned that a good old handshake don't cut it anymore."</p>