BEFORE THE CORPORATION COMMISSION F I L E D OF THE STATE OF OKLAHOMA AUG 1 7,2016

APPLICANT:

RELIEF SOUGHT

LAND COVERED:

CHESAPEAKE OPERATING ) L.L.0 AND CHESAPEAKE ) EXPLORATION, L.L.C. )

WAIVER OF CONSENT ) REQUIREMENTS OF 0CC ) RULE 165:5-7-6 )

SECTION 15, TOWNSHIP 18 NORTH, RANGE 6 WEST OF THE IM KINGFISHER COUNTY, OKLAHOMA

COURT CLERK'S OFFICE - 0KG COW- RATI0N COMMISSION

Of OKLAHOMA

CD 201503764

REPORT OF THE ADMINISTRATIVE LAW JUDGE

This Cause came on for hearing before Michael Porter, Administrative Law Judge for the Corporation Commission for the State of Oklahoma, on the 13th and 14th days of April 2016, at 8:30 a.m. in the Commission's Courtroom, Jim Thorpe Building, Oklahoma City, Oklahoma, pursuant to notice given as required by law and the rules of the Commission, for the purpose of taking testimony and reporting to the Commission.

CASE SUMMARY:

Chesapeake filed an application to create horizontal spacing in Section 15, Township 18 North, Range 6 West of the IM, Kingfisher County, Oklahoma. There are several wells producing from the requested common sources of supply. Chesapeake began to seek consent from various parties in the unit that had interests in those producing wells. After initially gaining multiple consents from some of the parties, Chesapeake was unable to gain consent from one of the parties. Once it became apparent they would not be getting the necessary consent from that interest, Chesapeake filed a waiver request with the Commission.

RECOMMENDATION:

It is the recommendation of the Administrative Law Judge that CD 201503764 be granted by the Oklahoma Corporation Commission.

HEARING DATES: April 13 th and 10, 2016.

APPEARANCES: Richard Books, Attorney at Law, for Chesapeake Operating L.L.C. and Chesapeake Exploration L.L.C.

John E. Lee, Attorney at Law, for Twenty-Twenty Oil and Gas, Inc. Randy and Becky Boeckman, DLA Howe, Inc. Chris Jennings, Oak Creek Energy, LLC Snyder Petroleum, Inc. and TAP Oil and Gas, LLC.

PRELIMINARY FINDINGS

1. Cause CD 201503764 is the application of Chesapeake Operating L.L.C. and Chesapeake Exploration L.L.C. requesting an order for a Waiver of Consent of the requirement in 0CC Rule 165:5-7-6 for Section 15, Township 18 North, Range 6 West of the IM, Kingfisher County, Oklahoma.

2. The Commission has jurisdiction over the subject matter and notice has been given in all respects as required by law and the rules of the Commission.

3. No Emergency Orders have been issued by the Commission to Chesapeake Operating L.L.C. or Chesapeake Exploration L.L.C. related to this cause.

4. That CD 201502633 was heard and recommended on December 15, 2015 by Judge Elizabeth Cates. On January 25, 2016 a Third Amended Exhibit A was filed in the court. On January 29, 2016 a Motion to Re-open was filed to add the amended Exhibit A as evidence. On February the Motion to re-open was recommended. Once re-opened in front of Judge Michael Porter, the matter was recommended. The proposed order would create a 640-acre spacing unit for the Big Lime and Oswego common sources of supply in Section 15, Township 18 North, Range 6 West, Kingfisher County, Oklahoma.

5. The following numbered exhibits were accepted into evidence on April 13th and 14th

2016:

Well Location and Production map used in CD 201502633 for Section 15, Township 18 North, Range 6 West, Kingfisher County, Oklahoma

2. Oswego Isopach map of the Oswego in Section 15 Township 18 North, Range 6 West, Kingfisher County, Oklahoma

3. Structural cross section in Section 15 Township 18 North, Range 6 West, Kingfisher County, Oklahoma

4. Landman's Affidavit used in CD 201502633 showing notice to parties in that cause admitted on February 9, 2016

5. Form 1002A for various wells located in Section 15 Township 18 North, Range 6 West, Kingfisher County, Oklahoma

6. Selected portions of Oklahoma Geology Notes, a publication of the Oklahoma Geological Survey, University of Oklahoma

7. Oil in place calculations for Section 15 Township 18 North, Range 6 West, Kingfisher County, Oklahoma

8. Decline data for the Watson 1

9. Decline data for the John States 1

10. Decline data for the Ingle C-I

11. Drainage area for John States 1 and Watson 1 wells

12. Reservoir data sheet for the Watson iwell

13. Reservoir data sheet for the John States 1 well

14. Completion report for the Anderson 21-18-6 3H well

15. Completion report for the Emmerich 30-18-6 1H well

SUMMARIES OF TESTIMONY

Testimony of Eric Denneny

Mr. Denneny testified as a landman for Chesapeake. He testified that Chesapeake owns an interest in the area covered by this application. He agreed that the spacing case was previously recommended and that this case was about consent and waiver issues. He testified that Chesapeake had a 42.75 percent working interest and that Twenty/Twenty owned 19.19 percent. He also testified about ownership in three existing well bores in the unit that produce from the Oswego. He agreed the Ingle C-i was operated by Chesapeake. He stated that Chesapeake had a 67.5 percent interest in the Ingle C-I. He testified that Twenty/Twenty owned no interest in the Ingle C-i. Next, Mr. Denneny discussed the Watson 1 well. He said Chesapeake owned no interest in the Watson 1 well. He added that Twenty/Twenty owned 59.43 percent in the Watson 1 well. Finally, there was the John States well. He said that Chesapeake did not own an interest in the John States, but Twenty/Twenty owned 53.55 percent. He stated Twenty/Twenty got their interest in the John States well in August of 2005.

Mr. Denneny testified that Mr. Michael Lovelace had sent out notices by certified mail. He added that there were additional contacts made with the respondents by mail and by telephone. He agreed that there had been a written consent given in response to the contacts and that this demonstrated a bona fide effort was made to obtain the requested consent.

During cross-examination Mr. Denneny testified as to other working interests in the 80 acre spacing unit. He agreed that Twenty/Twenty has a 59.34 percent working interest and other parties represented by Mr. Lee own the remainder. He indicated there is an 80 acre spacing unit covering the Watson well. He thought it was an 80 acre stand up unit. He identified the other working interests in the well bore to be Snyder Petroleum, DLA Howe Inc., Randy and Becky Boeckman, Chris Jennings, TAP Oil and Gas, and Oak Creek 8 Energy, LLC. He agreed further that the weilbore interest in that particular 80 acre tract is different from the lease holder in that unit. He agreed that Twenty/Twenty owns a hundred percent in that unit. He further agreed the John States well is located in an 80 acre lay down unit for the Oswego and that the northeast quarter is spaced on lay down 80 acre units with the rest of the section spaced as stand up units.

Mr. Denneny confirmed that Chesapeake was seeking a waiver of consent as to the Big Lime. He thought the John States well produced from the Big Lime, but he had not verified production from any well. He did say that he looked at public data about production. He agreed the Commission had spaced the Big Lime in Section 15 as 80 acre drilling and spacing units. He further agreed the Big Lime was in conformance with the Oswego. He admitted there was no 640 acre spacing in Section 15. He ultimately agreed he was involved in a horizontal spacing case for this unit that was put on before the Commission.

Mr. Denneny agreed that he began working this area, along with other people, in January of 2016. He testified that he reviewed some email chains that the previous landman had sent him, including the well file which contained public records for the section, title opinions, and ownership reports. He testified the emails were between Mr. Lee and Mr. Lovelace in contemplation of settlement. Mr. Denneny admitted he had no correspondence or other communication type documents dated before August 5, 2015. He testified that he spoke with Mr. Lovelace and was told that he had made some phone calls and talked to people. He admitted that he himself had not talked to any of Mr. Lee's clients and was not involved on or about the date the spacing application was filed in August of 2015. He admitted he was relying on documents that were in the file, and email chains that occurred after that date. He described the documents in the well file that were generated prior to the filing in August 2015, saying it would have been the ownership report. He continued by saying there was not a lot generated prior to the filing.

Mr. Denneny agreed he reviewed the notices sent out for the consent. He clarified the documents by adding that he reviewed the consent letters which included a cover letter and the actual consent form. He also said a notice of the spacing hearing, dated June 24, 2015, was sent out by Chesapeake. He added that the consent application would have been filed in August 2015. His testimony was clarified, confirming the notice of hearing for this case was filed the same day as the application, August 6, Consent letters went out on August 3 and delivered to the parties on August 5, 2015. He admitted that he had not had any conversations with any of Mr. Lee's clients. He further admitted that there were no documents in his files showing that Mr. Lovelace had any

conversations trying to obtain consent and making a bona fide effort to get consent with Randy Boeckman, Snyder Petroleum, or DLA Howe Inc. Mr. Denneny stated that Mr. Lovelace had spoken with Twenty/Twenty via the telephone. He also stated a letter with the consent had gone out to Twenty/Twenty in June of 2015 near the time the spacing application was filed at the Commission. He admitted that somehow Mr. Lovelace found out that there were other owners, from whom he needed consent. He further admitted that he was told there were phone calls, but he did not know who initiated the calls. As a further admission, he agreed that their bona fide effort to acquire consent prior to invoking the jurisdiction of the Commission for a waiver was the letter sent in June 2015, some phone conversations that may have been initiated by Twenty/Twenty, and additional letters sent to other parties in August of 2015.

He agreed that Chesapeake does not own a hundred percent of the working interest in the Ingle C-i. He stated the remainder was owned by the Ellie B. Beard Trust, Leman Minerals, Phillip and Susan Curl, and Thomas Leutkemeyer. He agreed those parties were not served with a waiver of consent notice because Chesapeake owns over fifty percent in the welibore. Mr. Denneny stated, according to Chesapeake's view of the rules, that if a party owns fifty percent of that well bore, the waiver of consent doesn't pertain to the aggregate working interest in the 640 acres.

Testimony of Walter Kennedy:

Walter Kennedy testified as a geologist at Chesapeake. He made a study of the Oswego in this area and examined available well logs. He characterized the Oswego as a tight limestone found at about 6,270 feet in Section 15. He stated that "tight" means vertical wells do not efficiently drain the section. During cross examination he stated tight limestone meant the limestone does not easily allow the flow of hydrocarbons, which means low permeability. He continued, saying that the permeability would be less than one millidarcy. Mr. Kennedy added that there were signs of natural fracturing beneath Section 15. From his study of the area he said that this is an ideal candidate for horizontal development, in his opinion, because it is a tight reservoir. He testified that the horizontal weilbore exposes more surface area of Oswego to get a more economic well. He testified that relative to horizontals, verticals were poor because a vertical well is only able to expose the welibore to the total height of the reservoir. A horizontal well is drilled horizontal and parallel to the 3 thickness of the reservoir and can expose that welibore to the reservoir for the entire length of the lateral. Mr. Kennedy testified the cross section shows horizontal wells would be desirable as the formation is thick enough to successfully drill a horizontal well with sufficient reservoir height. He agreed that as a general rule, if a zone is tight, that would indicate it is more likely to lend itself to horizontal development. He also testified there were indications of fracturing here. Continuing, Mr. Kennedy said the faulting and fracturing that was seen in the area is oriented east/west, more or less, so a weilbore drilled from the south to the north, or the north to the south, would intersect perpendicularly to most of those fractures and help oil flow into the horizontal welibore. He stated a horizontal wellbore is able to recover far more hydrocarbons because it exposes more of the wellbore to the reservoir than a vertical well. He said the level of activity in vertical wells was slight, testifying that the last vertical well was drilled in 1980, and that most of the drilling activity occurred between 1963 and 1980. He said during that time it was an active area, but in the last 15 years it was not active. He stated that horizontal wells have been drilled in the immediate area, pointing out that Chesapeake drilled the

Anderson well which is a horizontal Oswego well. Outside of the immediate area he said that there have been multiple horizontal wells drilled by Chesapeake and other operators. He testified that Chesapeake was willing to drill a horizontal well here in Section 15, if it is spaced horizontally. He indicated that there have been no proposals from any of the parties opposing this application to drill or recomplete any wells. The only proposal he was aware of was the proposal from Chesapeake.

Mr. Kennedy then discussed the wells shown in Exhibit 2. He stated that the Watson No. 1, in the northeast of the southwest was spud in 1963. This well also continues to produce from the Oswego and Mississippi. In the northeast quarter of Section 15 is the John States No. 1 which was also spudded in 1963. He said the John States No. I also produces from the Oswego and the Mississippi. He stated those two wells are commingled rather than dually completed. He then discussed the Chesapeake Ingles 22 C-i well located in the southeast quarter of Section 15. He said it was drilled in 1978 and produces only from the Oswego.

Mr. Kennedy then discussed the Oswego limestone reservoir thickness as it related to Chesapeake's plans to develop the Oswego horizontally. He explained Exhibit 3, saying it was a cross-section from the Davis 1-15 in the northwest quarter of Section 15, to the Ingles C-i in the southeast quarter of Section 15. He added that the top of the cross section is the Big Lime. He indicated the blue colored area represents the reservoir that Chesapeake will target with a horizontal well. He said it corresponds with the reservoir thicknesses shown on Exhibit 2. He agreed the blue color shaded area indicates what is mapped on Exhibit 2. He said the red numbers indicate the amount of feet that are perforated in the Oswego and the blue numbers are the total feet of thickness of the Oswego in that well. Starting with the Russell Pollard well in the southwest quarter of the southwest quarter, it shows 14.09 feet of perforations and the reservoir is 37.10 feet. He said in the Chesapeake Ingles C-i, 13 in the south half of the south half there were ii feet of perforations and 42 feet of reservoir. He testified the other Ingle well, located in the northeast quarter of the southeast quarter was not producing. He added that it had 7.94 feet of perforations in the Oswego reservoir and there was 38.19 feet of thickness. He testified the Watson well had 8.53 feet of perforations and 35.52 feet of reservoir. He stated the non-producing Davis well in the southwest of the northwest had two feet of perforations and 28.05 feet of reservoir. The Evelyn O'Hearn, in the southwest of the northeast had 7.74 feet of perforations and 38.04 feet of reservoir. Mr. Kennedy said the John States had almost 9 feet of perforations and almost 42 feet of thickness.

He testified that he had seen signs of fracturing on well logs. He said that you can look for tell-tale signs on them. He stated that if you look at the Davis 1-15 you can look for separation on the resistivity curve and that sometimes that's a sign of fracturing, though he admitted that sometimes what it shows is a function of fluid invasion. There was testimony given and questioning concerning the composition of the native water in the formation and the water that was used in drilling the well and its affect upon the logs reviewed. The result of those discussions between the Mr. Kennedy and Mr. Lee was that Mr. Kennedy admitted that sometimes that the separation seen in the Oswego reservoir zone may indicate fractures or it may indicate changes in water saturation or water salinity as you go further away from the welibore. Mr. Kennedy testified that he was part of the team with Mr. Denny and that they communicate back and forth with the operations and reservoir personnel. He stated Chesapeake operates the

Anderson and William Lee wells in Section 21. He agreed that the Anderson well is next to the William Lee well.

Mr. Kennedy said the perforations and reservoir thickness numbers on Exhibit 2 were based on the logs he reviewed. He did not bring the logs to this hearing and admitted Exhibit 2 was based on his opinion about logs not in evidence. Mr. Kennedy was shown Exhibit 5. He agreed it appeared to contain Commission records that have to do with Section 15. He admitted that it appears to contain Commission 1002A completion forms for all the wells in Section 15. He agreed there were other matters such as plugging reports as well. There was considerable discussion and cross examination about how and why the numbers on Exhibit 2 did not match the numbers shown in Exhibit 5. The end result was a computer program was used that gave different results. One such result was the log shows thickness of 12 feet and the computer program showed 11.31 feet. The other example was the computer showed 25 or 26 feet and the log shows 164 feet. Another example was the log showed 10 feet and the computer showed 10.31 feet. Mr. Kennedy explained some differences were because he considered only the actual perforated interval and not all productive intervals.

He indicated that the petro physical department analyzed well logs to determine water saturation. He stated he used data supplied by that department to make net pay maps. He said he was not the right person to ask about what a call of net pay is in the Oswego of Section 15 and what parameters were used to determine Oswego net pay. He did admit he discussed water saturation and porosity cutoffs. He testified that the net pay porosity cutoff for the Oswego in Section 15 would depend on what he was trying to show.

Mr. Kennedy admitted he had reviewed scholarly articles about the Oswego in this area. He said an article by Patrick Hurley that appeared in Geology Notes, 1963, sounded familiar to him. During a court recess he examined the article. He agreed that the four Oswego wells were drilled in the 1960's, with the exception of the Chesapeake well, the Ingles C-i. This was near the time this article was published. He also agreed the article is an Oswego study, or contains an Oswego study of the Dover area. The study area was west of this area, but the same Oswego. He agreed the structure shown on numbered page 7 of that study area is basically the structure of the Oswego in this area. He said he saw the isoporosity map that contoured where the Oswego has porosity greater than twenty percent. He testified that the author is making a link between porosity and production, stating the link was between a net of seven feet over a twenty percent cutoff and productivity in that area. He agreed with the author's conclusions about the lithology of the Oswego, at least in the cores. There was a discussion regarding the terms oolitic and oocastic that involved the leaching of the oolites. He testified oolitic means you've got a reservoir that is a stack of spheres like BB's in a box and if there is not material outside of those spheres that's oolitic. He said the oolites are the spheres. He said oocastic was the material that composed the inside of the spheres and has leached out and is deposited around the outside of those spheres. The net result is a reservoir with high porosity and very low permeability, so it's tight. He said that is what is present in this case. He agreed the Oswego is oocastic, but the porosity of the core was due to the leaching between the oolites with leaching being dissolved by a fluid. He admitted he was not the person who picked locations for wells drilled by Chesapeake. He also discussed the vertical fracturing that was mentioned in the referenced article. He said the article indicates the Oswego is fractured and that it contributes to production. He said the article

refers to porosity and permeability appearing to be caused by leaching of oolites as well as the matrix and vertical fracturing.

Testimony of Kathy Romanesko:

Ms. Romanesko testified as a reservoir engineer for Chesapeake. She has been involved in the 5 horizontal wells drilled by Chesapeake in this general area. She also has made a study of the area for the purposes of this hearing. She compared and contrasted the vertical and horizontal wells from an engineering standpoint, in a tight reservoir. She said in a vertical well in a tight reservoir, you have to hit those natural fractures to get production, and that is hit or miss. You can hit pockets of better porosity and better permeability, or you have to artificially stimulate the reservoir. Ms. Romanesko added that you can only reach out a certain distance from the welibore in order to drain the reservoir. She testified that with a horizontal well you are going through the entire reservoir rather than just going through a portion of the reservoir, which in this case is thinner from 9 to 60 feet thick, depending upon where you are in the play. She said if it's a vertical well you can only stimulate if you perforate every inch of the thickness. With a horizontal well you can go the full length of the wellbore and capture throughout that wellbore. With vertical wells you have to drill many vertical wells to drain the same amount as a horizontal well. She testified that a lot more of the fractures could join up in horizontal wells with natural fracturing. She said it was her understanding that the majority of the fracturing here is vertical in nature so in a vertical well it is all going in the same direction, thus many of those fractures have no ability to connect. When going horizontally, many of those fractures can connect without having to do anything to artificially stimulate it. As to vertical fracturing, she agreed that same phrase was used in the 1963 paper that's been previously introduced during there hearing. She stated her opinion that a horizontal well could recover hydrocarbons that would otherwise be left in the ground with vertical wells. She testified that she had seen ultimate recovery range from a 197 mbo, to 900 mbo for a single well.

Ms. Romanesko said the Anderson well was less than hoped for due to some operational issues. She said those issues had been ironed out on subsequent wells. She stated she did not think the performance, on the onset, was sub-par. She testified the Hughes Trust was the first well that they worked on ironing out our operational issues. She added that well subsequently came on with a thirty day peak rate of about 1900 barrels a day. She continued saying that when they started pulling hydrocarbons out of the well, that it was predicted to recover 450,000 barrels of oil. She testified the Merit well had been running between two and 500 barrels a day. She could not give an estimate of its ultimate recovery because it was too early to predict. She stated it was a well she would have recommend to be drilled. She then testified that the Luber well had a similar production profile as the Merit well.

Ms. Romanesko then discussed the oil in place calculation she had done. She stated they used reservoir height instead of a porosity cutoff. She added they used the average of that for the section and then used the average of the total porosity of the entire section. She admitted she did not do anything different here for this hearing for her calculations. She stated had she used an average porosity of twenty percent, she would have calculated significantly more reserves. She

had been using 18 percent for the recovery rate in Oklahoma. She said the original recoverable reserves were 853,000 barrels of oil with gas at 3.41 Bcf.

She testified that the Ingles C well produces only from the Oswego. She stated that other well in the section was commingled. Using Exhibit 11, she was asked a series of questions, without adopting the numbers shown on the exhibit. She admitted that she found the numbers on the exhibit to be in general agreement with her numbers. She stated she had examined production from available data from the state website, IHS and the data provided by Twenty/Twenty. She testified she was able to determine how the calculations were made for allocating the various zones.

Referring to the Watson No. I in the northeast of the southwest; she stated she believes the cumulative oil of that well to be approximately 82,600 barrels. She agreed that total production would be whatever it is producing from however many formations. She did not find any big disparity in Twenty/Twenty's numbers or in Exhibit No. 11. She stated the Watson No. 1 is near the end of its life. She also stated if this had been their well, they probably would have plugged it as uneconomical. She said the last production, based on public data for the Watson well, was in 2009. She agreed she was given data from Twenty/Twenty about the production from the Watson well that was different than the public data. She testified she was given three different oil hauling tickets that spanned roughly 15 months, from July 1, 2014 through October 14, 2015. She said the production was about 540 barrels over those 15 months, which would be 1.9 barrels a day. She again stated with a well making 1.9 barrels a day from multiple commingled that well was near the end of its life. She agreed that if we are looking at what's being produced from the Oswego it would be less than the 1.9 barrels a day.

She stated she could draw some conclusions from Exhibit 11, even though she did not prepare it. She testified the allocation for the Watson No. 1 well seems to be about 60 percent from the Big Lime/Oswego combination and 40 percent from the Mississippian. She did some calculations and determined that about 1.1 barrels per day was coming from the Big Lime/Oswego combination.

Next she discussed the John State well. She testified it was commingled. She said the total production shown was 96,105 barrels. According to Exhibit 11, 47 percent is attributed to the Oswego, which she stated would make 44,689 barrels of the 96,105 barrels of oil attributable to the Oswego. She stated this well was near the end of its life. She testified that she had the haul tickets from Twenty/Twenty and they showed the well was producing about a half a barrel a day from all zones. Applying the 47 percent, it would give the Oswego a production of just under one fourth of a barrel of oil a day.

The next discussion concerned the Ingles C, a Chesapeake operated well. Ms. Romanesko stated the cumulative production for that well was just less than 81,000 barrels of oil. She agreed the number she had and the number that Twenty/Twenty had for cumulative production are similar. She stated it produces only from the Oswego with current production just less than six barrels a day. She agreed it was not quite six times the current production of the Watson well and about twenty-four times the current production of the John States. She said this well was near the end

of its life as well. She said the ultimate recovery for this well would be approximately 87,000 barrels of oil.

Ms. Romanesko did not make a prediction of ultimate recovery for the Watson 9 well because the database she used showed no production from the well. Her exhibits were prepared prior to receiving the run tickets from Twenty/Twenty. She did make predictions as to the John States No. 1. She testified that the gas ultimate gas recovery was 185,000 thousand cubic feet of gas. However she indicated that she did not make a prediction as to ultimate oil recovery for the same reason she did not make a prediction on the Watson well.

She then described the methodology she used to arrive at recoveries from the various wells. She testified that there would be 511,000 barrels of oil remaining, using the allocations furnished by Twenty/Twenty. She said the currently producing well could not recover the remaining oil at their current rates. She agreed that if she were to assume all production came from any Oswego producing well, the remaining reserves would be 370,000 barrels of oil.

Ms. Romanesko stated she did not believe anybody was going to drill a vertical Oswego well. She also agreed that no vertical well had been drilled in 30 years and if no vertical well is going to be drilled in the Oswego, then between 370,000 to 511,000 barrels of oil is going to remain in the ground unless somebody drills a horizontal well. She further agreed that no one would drill a horizontal well on eighty-acre spacing. She thought drilling a horizontal well could prevent waste of the oil in the ground. She did not know of any method to recover those barrels of oil without the horizontal spacing. She also did not see any alternative to horizontal development. As to correlative rights, she did not know of a way to protect the royalty owners of those 370,000 to 511,000 barrels of oil without the horizontal spacing requested by Chesapeake. Ms. Romanesko also discussed the effects upon existing wells. In this area, she discussed some examples of the affects on existing wells. She said the Anderson well was drilled within 200 feet of the Chesapeake Lee 1-21 vertical well. She explained that they shut in the Lee well since it was the first well in the drilling program and was close to one of the producing vertical wells. She testified that prior to frac'ing the Anderson well, they dropped pressure gauges in the Lee well. She said during the process of frac'ing, there was no jump or drop off shown in the pressure gauges that would be indicative of communication between the two welibores. She said if the completion changed the pressure it would either spike upwards or drop off. She stated if it drops off, it means that you are losing all of your pressure into the other well. She testified that in the Lee well, there was no pressure change, which indicates no communication between the two wells. She also examined the Anderson from the Lee well. She looked at three months before and after the frac job. She stated in the Lee well the oil performance remained on the same decline profile. The gas dropped off slightly and the water also remained consistent. It bumped up a little bit for a couple of days and then bounced back to where it had been prior. She said the gas drop off was from 20 Mcf a day to 15 Mcf a day. She testified that part of that drop off spanned a time frame when we were going up against higher line pressures so, that could have been a part of it. She said there were later line pressure increases after the frac job and again there was a drop of about 5 Mcf a day in the area and in other wells. She said it then bumped back up to the same decline it had been on prior to the frac job. She agreed that considering the line pressure here and the fact that the oil and water stayed the same, and the pressure gauge didn't show any change, her conclusion was that there was no adverse affect on the Lee well.

Ms. Romanesko discussed Exhibit 11 as to what it represented. She believes the circles shown on the exhibit represent the drainage areas. She was not adopting the circles. She stated that the drainage pattern would generally not be circular. She testified that if there is natural fracturing involved it will drain along those fracture planes further out. She added it is usually more irregular shaped a lot of times because of how stresses are around the weilbore. She explained as the thickness changed, the size of the circle would get smaller. She stated, in her opinion, the O'Hearn did recover hydrocarbons that might have otherwise been recovered by the Watson, based on the drainage radius. She also opined that the Ingle C recovered some of the Watson well's hydro carbons. She said that is based on the volume recovered and the size of the Watson circle. She added there would definitely be overlap in the two circles.

Ms. Romanesko agreed the Chesapeake landman testified that Chesapeake owned sixty-seven percent of the Ingle C well and that in the 640 acre unit, that Chesapeake owned 43 percent. She also agreed Chesapeake would have no incentive to harm that well. She testified the Ingles C was the best Oswego well, which has the most productive life left in it.

Ms. Romanesko discussed issues with some of the wells. She testified the primary issue is a production issue with wells using frac sand. She said the problem was proppant flow back into the wellbore which inhibits the flow into the wellbore. She said proppant is the sand that is put in there that holds the fracs open. It props them open to allow additional pathways for hydrocarbons to flow. She said the Anderson and the Emmerich were both completed that way as were all of the wells prior to them. She said the Luber, the Hughes Trust and the Merit, did not use proppant. She testified that the reason she thought there was a proppant flow back problem in the Anderson was because they have to go down quite frequently and do gel sweeps to clean the proppant out that has fallen back into the wellbore, inhibiting the flow. She added that they ended up having bridges of proppant that come into the wellbore that effectively shortened the wellbore length, restricting its flow. She said the Emmerich well was completed similar to the Anderson well and has the same issues as the Anderson.

She said the Emmerich 22 30-1861H, was an offset to Chesapeake's vertical Emmerich 1, stating it was about 510 feet away. She said that it was shut in during the frac'ing procedure. She added that because Chesapeake had not seen a response on the Lee well that was closer to the Anderson well that Chesapeake chose not to drop pressure gauges in the Emmerich 1. She said when both wells were turned back on, the oil performance also improved. She said it was about a seventeen percent improvement from 171 barrels per day pre frac to 205 barrels a day post frac. She said the gas quantities remained relatively the same, but did have a three percent increase. She said the three percent increase could have been the result of other factors since there are fluctuations in the line pressures in the area on regular basis. Mr. Romanesko added that water production dropped off by 25 percent. She agreed that based on the lack of effect of horizontal wells upon vertical wells, she did not predict any adverse effect upon the vertical wells in the section. She added there was no incentive for Chesapeake to try to harm the vertical wells. She said they could harm their horizontal well by frac'ing into a pressure depleted area. She believed the application should be granted so that the rest of the hydrocarbons can be effectively recovered. She also believed that the correlative rights of the parties in the vertical wells, and the correlative

rights of owners to reduce gas outside the vertical wells, will be protected if the application is granted.

Ms. Romanesko stated she was unaware of any mention in a location exception order that allowed Chesapeake to be closer than 600 feet to either the Emmerich or William Lee well. She added that the hearing for those exceptions took place prior to her employment with Chesapeake.

She stated her duties at Chesapeake included the evaluation of new plays inside and outside of the company. She added she helps to determine acquisition and divestiture. She works on the existing plays within the area for future development and looking for outside potential. She also takes care of the reserve reporting portion for SEC reserves for the area under her assignment in the Kingfisher field office area. Her assigned geographic area spans several counties, from Noble County through Oklahoma County down to the south. It also goes eastward over to the Arkansas border and includes Kingfisher County. She admitted she was on a team with Mr. Kennedy and Mr. Denneny, but only for the development of the Oswego. Her duties also include performing reservoir studies. She said that she did not analyze well logs but did interpret pressure transient well surveys when they are available. She said she looks at core data for her own interests but does not evaluate it.

In looking at Exhibit 7, she said the average porosity was given to her by Mr. Kennedy in the geology department. She admitted she did not analyze logs to get the average porosity. Ms. Romanesko also stated she reviewed the logs to confirm the reasonableness of the five percent average porosity. The logs she used were from throughout the play. She stated she relies on the experts within Chesapeake for information. She said she did not confirm that the values provided to her, were reasonable. There was considerable discussion regarding the origin of the values placed on Exhibit 7. This testimony was considered by the Court in reaching its recommendation to the Commission. It was determined the average reservoir depth was taken off of a map of the area and Ms. Romanesko did not determine the depth. She did examine the gas analysis and oil API gravities. From those she determined the Bo that was utilized and the Z-factor. Further, she determined the temperature and pressure. She said the reservoir temperature depended on the location within the reservoir. She testified that the reservoir fluid temperature she derived for the fluids coming out of the reservoir were at about at about 145, 146 degrees. She used a temperature of 146 degrees for the reservoir temperature. She testified she got the fluid temperatures from the intake pumps from the area. She did not know where a temperature of 120 degrees came from. As to the oil gravity of 40 degrees API, she did not get it from an oil sample but rather from publicly-available data. She said she also used data from a Chesapeake oil well and other data. She stated that the gas/oil ratio of 400 was her work based on test data from Chesapeake's well and area wells. She testified that the Bo, the reservoir volume factor, was determined through an algorithm. Ms. Romanesko testified the Z-factor is a compressibility factor for natural gas. She said it was determined from some of the oil-and-gas parameters from the data sheet. She also agreed the recovery efficiency, RS of V of 18 percent, was obtained from public data. She stated the data was from the Standard Handbook of Petroleum and Natural Gas Engineering and indicated the book gives a range of recovery factors depending on porosity, permeability, and water saturation. She added that the recovery factor was not specific to the Oswego. She stated that she believes the 18 percent recovery factor applies, taking the natural fracturing into consideration. She agreed that on Exhibits 11 and 12 that the estimated recovery

factor on those exhibits was shown to be 12 percent which was a 33 percent reduction from her recovery factor. She also agreed that if you used a 12 percent recovery factor to compute the recoverable reserves in place that those reserves drop from her estimate of 853,000 barrels of oil. She was asked to calculate the gross reserves shown using a recovery factor of 12 percent. She testified that would result in around 569,000 barrels of oil. When asked to use the values she discussed earlier for the Oswego recovery, the result would be 283,000 barrels of oil.

Ms. Romanesko agreed that she had testified that the Ingle well had a cumulative production of roughly 81,000 barrels of oil and an estimated ultimate recovery of 87,271 barrels of oil. She explained that ARIES is a software program she uses to do economic evaluations. She said she inputs certain data into the program and it gives her a reasonable projection of the economic limit production rate. She testified that the ARIES cutoff is when it is running negative for longer than six month's time and indicate it is no longer an intelligent decision to continue producing the well under those current conditions. She agreed the equations used to determine the economic limit is sensitive to price. She said she used $50 per barrel for oil and $3 mcf for gas, which were not the current prices at the time of the hearing. She said the economic production limit in ARIES would be 10 barrels. She was asked what Qref means, and replied it is the approximate production at the reference point, which is the red line and with the little green arrow up at this top in this case. The green arrow is the reference point indicating that would have been the approximate production rate at that point in time, in this case sometime in 2015. She said it showed 52.757 barrels per per-month basis. She agreed the abandonment rate is ten barrels a month at $50 a barrel and $3 per mcf and those operating costs and that net revenue interest. She testified that YRS means at the current projected profile, it is the number of years that this well would potentially run. On the Ingle C well it would be 21 years. She agreed it was making fifty-six barrels a month and it will go out to a third of a barrel a day in 21 years. She further agreed it will take 21 years to produce that the 6,400 barrels of oil remaining. She clarified her statement that the Ingle C well was near the end of its life referred to the well being near the end of its economic productive life based on the current price environment. She said if she were to run a price with today's pricing, it would cutoff much sooner than that. She admitted she had not run new numbers for Exhibit 10.

Ms. Romanesko admitted the data she has now shows both the John States and Watson wells are producing oil. She also admitted from the accounting data she has that both wells are economic. She again stated that the well was nearer to the end of its life than the beginning. She agreed it had been on since 1963 or about 53 years. She also agreed that it could have another 52 years left at small rates. She clarified that low recovery rates referred to the volume of oil and gas coming out of the ground. She did not admit that it was her opinion that those wells are worth anything now, testifying that value is kind of an arbitrary thing. She stated that how much economic-producing life is left, and taking into consideration what kind of plugging and abandon liabilities exist, would help to determine what an actual value, from a strict perspective, would be. She did not have an opinion about whether or not Twenty/Twenty should plug the wells at this time.

Next, there was a discussion regarding Exhibit 7. Ms. Romanesko agreed it showed the estimated remaining recoverable reserves. She said for Exhibit 7 the John States and Watson wells had their cumulative values plugged in instead of any future production even though now they are known to be producing wells. For the EUR, the estimated ultimate recovery from the Ingle C,

she used the cumulative amount. She said she did not subtract from the EUR the future production from the Ingle. She admitted her portrayal is that there is 624,000 barrels remaining, not considering the current production from this unit. She also admitted that she had no idea where Chesapeake intended to locate a well if they get the spacing they want. She did not dispute that no matter where the well is drilled, Chesapeake expects to get anywhere from 200,000 barrels up to 600,000 barrels.

Testimony of Jon Stromberg

Jon Stromberg testified on behalf of Twenty/Twenty as a consulting petroleum engineer. He agreed he was asked to review the Oswego, Twenty/Twenty's wells, and what they believe to be the contemplated Chesapeake horizontal well. The review was to determine whether there may be alternate methods of developing the Oswego, and to see if there's anything to develop in the Oswego, and finally review the horizontal development in Section 15. He was to determine if any vested correlative rights of Twenty/Twenty were in jeopardy because of Chesapeake's horizontal drilling. Mr. Stromberg then discussed Exhibit No. 11. He said it was a plat on Section 15 on which shows the wells that have been drilled and completed in various zones in the section. It shows the name of the well, the ultimate oil recovery, and the name of the well. He added it is colored-coded as to what zone it produces from. Also shown are two lines of cross section, AA prime and BB prime. He also stated it has two circles, one around the Watson No. 1 and one around the John States, which are calculated drainage areas. He agreed he was aware that both the Big Lime and Oswego are spaced on 80 acres at this time and that he believed it has both lay down and standup configurations. He said the configuration in the Northeast Quarter was as 80 acre lay down with standup units in the rest of the section. He said that not all of the 80-acre tracts have been drilled. He testified there haven't been enough wells drilled to drain have a well in each one. He agreed that any additional vertical drilling would be on an increased density basis. Mr. Stromberg said the increased density would be for the Watson, the John States, and the Ingle "C". Other units are not producing. He said he did not know what how the Mississippi was spaced, but opines that it almost has to be spaced on 80 acres because the wells are commingled.

Mr. Stromberg agreed with that if Twenty/Twenty felt it to be economically justified to drill another Oswego-Big Lime well, it would have to be on an increased density basis, either in the John States 80 or in the Watson 80. He stated the allocation between the Mississippi, the Big Lime and the Oswego was a very rough allocation of 96,000 barrels of cumulative oil. He said on the 1002A the initial potential for the Mississippi and the Big Lime-Oswego was shown separately. He said he used that initial test to determine the allocation between the formations. He agreed engineers make educated assumptions. He agreed, in his opinion, it would not be realistic to assign all the production to the Mississippian or all to the Oswego. He further agreed there is some split and that he was probably wrong, but agreed the exact split is unknown. Mr. Stromberg stated to the Court that every engineering calculation is wrong, and that it is that we don't know how wrong. He clarified the statement by adding that with things engineers can see, the calculations are pretty close, but they can neither measure nor see anything they want to know in petroleum engineering. Mr. Stromberg agreed, as to the John States, there was no way to determine what zone is contributing to production today and agreed it could all be Oswego. He

agreed that the John States continues to produce gas but that it does not give an indication of which zone is producing. He testified that the Watson is not producing any gas but some of the other wells have produced gas. He said the Ingle "C", which is only completed in Oswego, sells both gas and oil.

Mr. Stromberg then discussed the circle drawn around the John States, stating he was trying to determine the potential drainage area around the John States. He testified he did a volumetric calculation to determine what the drainage area of the well would be using the best petro physical data to do the volumetric calculation. He stated he had no way of determining which was Big Lime and which was Oswego. He said he used the net hydrocarbon feet of pay in the well for each zone and allocated between the two of them on that basis. He testified that hydrocarbon feet is the height of the reservoir times the porosity times one minus the water saturation, and that gives the feet within that area that are hydrocarbon bearing, also known as hydrocarbon pore volume. He agreed that he determined the hydrocarbon feet in the Big Lime and the hydrocarbon feet in the Oswego, added these two values together, and then assigned a ratio based on thickness or based on based on the difference between the two. He agreed there are some significant differences in the reservoir parameters of petro physical parameters that were used in Exhibits 12 and 13 and what is shown on Exhibit 7. He opined that five percent porosity in a limestone will produce oil, but not at high volumes or rates. He determined the 14.7 in Exhibit 13 by using a log on the John States and he calculated the interval as an eight-foot interval and ten-foot interval that had good looking porosity. He said the rest of the zone is down in the two to five percent porosity. He stated the well was perforated primarily in this interval, so he used that interval which has a high porosity, the best producing characteristics, and where it was perforated. He testified he was not trying to calculate the total oil in place but the oil in place to determine the drainage area for that well. He figured that the drainage area would be the higher porosity where they perforate. This led him to the drainage area of 46 acres. He agreed that engineers assume circular drainage that leads to radial flow, even though engineers know that it is probably not accurate. He agreed he drew a circle because we don't have anything better to describe it in this particular reservoir. Mr. Stromberg then discussed other reservoir parameters. The original reservoir pressure was 2,555, based on a gradient. He added that it was lower now due to depletion. He testified that there have to be pressure gradients if there are wells producing oil, because the pressure pushes the oil from one spot in the reservoir to the other. He stated if the reservoir is at one pressure and if the pressure is not drawn someplace, the oil will not move. He added that if there is not a higher pressure someplace, there is no way to move the oil through the reservoir. He testified that there are pressure gradients that exist within the reservoir as soon as the reservoir starts producing. He agreed that if the original reservoir pressure was around 2,550 and that a certain volume of oil and gas has been produced out of the reservoir, the overall reservoir pressure has decreased. He stated that we do not know, initially or now, what the pressure is for sure. He stated we do not know how much gas has really been produced. As an example, he was sure the Watson was producing some gas but it's never been recorded. He also stated they have no idea what the water [saturation] is. He said as a consequence of this lack of data, they could not do any kind of a material balance. He said the reservoir pressure would be lower around the three producing wells. However he said, many of the wells have been shut in for 10 to 20 years, so there has been some equalization within the reservoir. He said the area of higher pressures would be where there are no weilbores. He agreed there were pressure sinks around the John States, the Ingle and the Watson wells. He also agreed

that the reservoir pressure may have stabilized in the area where there are no wells drilled and in the areas around where wells have been plugged for some time.

He agreed he used a recovery factor of 12 percent and that Chesapeake is using 18 percent. He agreed he heard Mr. Kennedy state that Chesapeake believes the permeability of the Oswego is less than one millidarcy. He further agreed the range given by Mr. Kennedy was from five micro-darcies up to 1 millidarcy. He stated for his purposes he used one millidarcy in his calculations for permeability. He testified that to get to an 18 percent recovery that the permeability of the reservoir would need to be 18 millidarcies. He stated that you usually see 18 millidarcy in sandstones. He agreed it was possible to have 18 millidarcy permeability in a limestone clearly, but that it would be hard to find one that is that highly averaged. He stated that with fractures you could have that kind of permeability in a limestone. He agreed that according to Chesapeake there were not 18 millidarcies in the five percent porosity range. He also agreed that is what they were calling net pay for the purposes of Exhibit 7.

He said he determined the average porosity of 16.2 percent in the Watson well by using the Ingle log to calculate the petro-physical data for the Watson well. He was able to compare the electric log information he had on the Watson with the logs on Ingle. Mr. Stromberg said they correlated very well, including lithologically.. He said that Chesapeake perforated that thin, high porosity interval in the Watson. He also said he could recognize it by correlation on the electric log as well. He testified that the Watson well has drained 87 acres, assuming a circular drainage pattern as shown on Exhibit 12. He stated that Ingle C's last production was in 1987 at 180 barrels a month. He agreed that it had not produced at that rate in the past 5 years

Mr. Stromberg agreed that his experience in the area of petroleum engineering has included reservoir work and being in charge of drilling and completion operations. He testified that he designed fracture stimulation treatment. He said it was not a fancy design and that he usually works with service companies to co-design the treatments. He is aware of the design parameters of what he was looking for. He agreed when trying to fracture stimulate a well, when it is advised, that existing production from an unstimulated zone be augmented. He went on to explain there is no such thing as a homogeneous reservoir, they are all heterogeneous. Continuing, he stated there are areas of high permeability; there are areas of low permeability; there are areas of high porosity, low porosity and so on. The oil, of course, is held in the high porosity areas and it flows easier through the high permeability areas. So what they try to do with a frac job, or a fracture treatment, is to connect some of the better porosity zones through the poor porosity zones. They build-up pressure in fluid and it breaks the rock, then they pump the fluid out through that break or fracture and then fill that fracture with fluid. If you're in a carbonate, that fluid can be acid and it will eat up some of the carbonate. Carbonate will dissolve in acid. When the pressure is relieved and the reservoir tries to close back together, which it will do, some areas have been eaten up and so little worm holes are left through there that production can flow through. The other option is to put proppant in it. Proppant is used especially at these shallower depths. As you get deeper, you have to use different and harder proppants. At these shallower depths, you can use sand. The fracture is pumped full of sand and when the pressure is relieved it closes back up, but the sand is in the way so it can't close all the way. It then flows between the sand grains, which give the permeability. The purpose of the fracture is to get as long a fracture as you can over whatever the interval is, then either fill it full of proppant to hold

it open, or treat it with an acid to dissolve some of the reservoir so that it can't close all the way up. Those are the two basic ideas behind fracture treatment. Mr. Stromberg agreed that when one designs fracture stimulation, it's important to know the height of the fracture that one wants to induce. He said the optimal height for that fracture would be the entire potential productive interval. He stated that sometimes there are barriers to the frac that limit the ability to fracture the entire length or the entire height. He indicated that they do try a design to fracture the entire interval. He said, in this instance, there is a whole series of Oswego sands mixed in there with some shale barriers. He agreed that those shale barriers can act as barriers to propagation of a vertical fracture, and that the fractures that propagate at this depth are assumed to be vertical fractures, not horizontal. He agreed that based on traditional textbook rock mechanics, it is expected the fractures will propagate upwards.

He discussed the 1002A descriptions of the fracture stimulation treatment in the Anderson well. He said that it reports the volumes used, but it doesn't describe the frac job. He agreed that Ms. Romanesko described the frac job as having 13 stages. He then described the differences between a frac job in a vertical well and a horizontal well. He testified that in a vertical wellbore, you generally perforate within the productive interval and then frac and get a vertical frac. He continued with all that can be frac's is that vertical interval, and it then propagates outward and upward. So in the vertical, if there is 30 feet of pay, there may be a 30-foot frac in this zone. He agreed that that the frac is going to go against or perpendicular to the highest rock stress, and is probably going to go each way out of the vertical wellbore so that they have a fracture on both sides. He further agreed when one designs a frac job, they think of frac length and that is basically the frac wing length. He said the frac wing length is the length of the frac away from the welibore, be it in a vertical or horizontal well. Continuing he said they frac away from that and get a frac that runs in two general directions and similar in length on both sides, hopefully. If the frac length is a thousand feet then there should be a wing length of 500 feet on each side of the weilbore.

Mr. Stromberg then discussed technical aspects about frac fluid and other factors he used to derive a frac length. He said the total frac length is about 5,000 feet and it's about 2,500 feet per wing. He said that was for each stage. He then testified about the Emmerich frac off its 1002-A. He said he did not know how thick the zone was or how many stages they had. He testified the length was about the same, so he assumed 14 stages, and assumed 50 feet of thickness. He did say if it was greater than 50 feet, then the frac would be a little bit shorter and if was thinner than 50 feet, the frac would be a little bit longer. His calculations indicated the frac length in the Emmerich well was approximately 2,100 feet. He agreed that based on this length that it would frac out of Section 30.

Mr. Stromberg then discussed costs to drill and complete vertical wells to 6,500 feet. He said he calculated a total of $680,000 which included the cost of drilling the well, all the subsurface work to get the well in production, having the surface equipment, and the infrastructure to produce and sell oil and gas. He agreed that it looks like the Oswego production ranges anywhere from 40,000 to 80,000 barrels. He testified that the cost of capture for a vertical well at an ultimate recovery of 40,000 barrels of oil would be $17.00 a barrel, for 60,000 barrels of oil it would be $11.30, and for 80,000 barrels of oil it would be $8.50 per barrel. He stated that $680,000 is approximately a-fifth of $3,200,000. He said they could drill four and a half to five

vertical wells for every horizontal well that Chesapeake drills. He said if Chesapeake lost its $3,200,000 well and got nothing, they'd be out the $3,200,000 or whatever they had spent. He stated if Twenty/Twenty lost their well they would lose $680,000 or less. He said from a risk-weighted position, his opinion was that the vertical wells make more sense to drill than a horizontal well.

Mr. Stromberg agreed that the location of Chesapeake's horizontal well is not known. He agreed if the spacing is granted, then the well tolerance in a carbonate would be 660 feet from every unit boundary. He also agreed that he has seen where Chesapeake has come before the Commission and received well location exceptions for their horizontal wells to be as close has 330 feet. He was asked to assume that Chesapeake drills their horizontal well from south to north along the west side of the section approximately 300 to 400 feet from the West Line, and frac'd it the same way with, at least, the same amount of fluid and similar number of stages and frac lengths. He said in that interval, the reservoir is a little thinner, ranging between 30 and 40 feet, so the frac lengths with a shorter, vertical lateral would be a little bit longer and the frac length would be something in excess of 2,500 feet at the same frac volume as the Anderson and the Emmerich. He thought at 2,500 feet there was a good chance of frac'ing into one of Twenty/Twenty's wells. He said there is a low pressure area around the Watson well at this time. Mr. Stromberg opined that fracs migrate to the lower pressure areas. He testified that he previously had two clients that have had Mississippi wells frac'd into. He said one was a Mississippi horizontal Felix well that frac'd into their vertical Hunton-Mississippi well. He said he knew it affected the clients well because of the information he had been given and his evaluation of that data. He stated the timing, fluids and everything were correct, and it appeared the frac came into that well. He stated the vertical well was lost. He said he recalled it collapsed the casing. He agreed if the Chesapeake well is on the west side, it could frac into the Watson and if the well is on the east side, they could frac into both the Watson and the John States wells. He agreed if the Watson well is ruined, then Twenty/Twenty and its working interest partners would be responsible for plugging that well. He said the probable cost to plug that well would be in the range of $20,000 to $30,000. He further agreed that not only would they have lost the future reserves that the Watson's producing, but they'd be in the position of spending another $20,000 to $30,000 to comply with the Commission and get the well plugged. He also agreed that Twenty/Twenty, their working interest partners, and the royalty owners in the 80 acre tract have vested rights. In addition, he agreed the same was true for the John States well. He agreed if the [horizontal] well goes into the John States or the Watson, or both, and ruins them, it would destroy their rights, in his engineering opinion. He stated he thought it was better than a 50/50 chance the well proposed by Chesapeake would ruin one or both of the wells.

He agreed that he heard that Anderson frac did not affect the William Lee well. He was asked if he had a different opinion. Mr. Stromberg explained that it is hard to examine the data dealing with low production volumes and using sales data and not actual production data. He testified he had reviewed the production data for 2014 and 2015 and said it appears that there has been a decrease in production from the William Lee. He said in 2014 it sold 564 barrels. In 2015 it sold 202 barrels, which shows greater than a 50 percent drop in sales. As to the Emmerich, in 2014 it sold 1,060 barrels and sold 396 barrels in 2015.

During cross examination, Mr. Stromberg admitted he had not checked the line pressure on the William Lee or Emmerich wells. He also admitted he did not know when the last [vertical] Oswego well was drilled within this section or the four miles on the surrounding five square miles. He further admitted Twenty/Twenty had not proposed a vertical well when prices were higher. Additionally, he agreed he was not aware of any other party, whether his clients or any other clients, that had proposed the drilling of a vertical well in Section 15 in the last 41 years. He agreed with a series of questions concerning the Oswego's tightness, fractured nature, and the statement that there will be recoverable Oswego hydrocarbons remaining at the end of the life of the vertical wells. He also agreed that no one would drill a horizontal well under 80-acre spacing. He confirmed that the based upon his allocations, the Ingle C appears to be the well with the highest ultimate recovery in the Oswego. Finally, he agreed that low porosity reservoirs can produce from fractures.

Continuing, he concurred that if there are two identical reservoirs with the same perm, and everything about those reservoirs is identical except one is fractured and the fractures are connected, there would be better production from the reservoir that's fractured than from the non-fractured reservoir. He would expect this result in the Oswego if everything else was equal and if there are some fractures that are either connected naturally or induced fractures, they would produce better. He admitted he had not studied sand flowback in fractures of any horizontal well or horizontal Oswego wells in this township. Mr. Stromberg also admitted it was correct to say that he had not presented any estimate of original recoverable reserves from the Oswego underlying Section 15. He testified he had studied Hunton wells in Seminole and Pottawatomie counties to determine their ultimate recovery factors. He admitted none of the wells he studied were Oswego. He stated he had looked at some Mississippi wells for production as well. He said the Hunton wells were primarily east of Oklahoma City in Seminole and Pottawatomie counties and Kingfisher County was generally north and west of Oklahoma City. He admitted he did not expect identical recovery factors from wells in Pontotoc and Seminole County in the Hunton to be the same recovery factor as Oswego wells in Kingfisher County.

In looking at Exhibit 11, Mr. Stromberg stated that it was not his position that his clients have a vested right to all of the oil or gas shown in the circles on Exhibit 11. When asked would he agree that vested rights, on behalf of all parties, has to do with competing fairly for reserves, Mr. Stromberg agreed that was a fair statement. He admitted there were three units shown on Exhibit 11 where someone would need to request increased density before they could drill a well. He was not aware of any request by Twenty/Twenty to drill an additional well in their acreage at the present time. He also agreed that five of the units would not require increased density authority. In those units, he was not aware of any proposal or request to drill an additional well using vertical development. He did not know of anybody today that is willing to drill a vertical Oswego well in Section 15.

Mr. Stromberg recalled the discussion about pressure sinks at the Watson and John States wells. He agreed he made the point that those pressure sinks might or might not cause a frac to go that direction. He had no reason to believe there wasn't a pressure sink at the William Lee or Emmerich wells when the horizontal well was frac'd nearby. He agreed that it would be fair to say that the mere fact that there is a pressure sink doesn't mean that a well is going to be damaged.

The next discussion concerned frac lengths. Mr. Stromberg admitted he did not know the width of the frac in the Anderson well. He said the frac would be shorter if the width was two or three times what it is in the Anderson. He said his answers would be the same for the Emmerich well. He said if the thickness is more than the frac, then it would be shorter. He said it was possible that a frac stimulation would perform differently in an oocastic reservoir than in a non-oocastic reservoir.

As to well costs, Mr. Stromberg testified he came up with the $680,000 number from several AFEs recently in Eastern and Western Oklahoma. He said he had just put together an AFE. He stated the AFEs in Eastern Oklahoma were in Pontotoc, Pottawatomie, and Hughes counties. In the Western counties, it was the county just on the other side of Canadian. He admitted it would be a county or two from Kingfisher County. He admitted he had not made any investigation to see whether any parties have actually drilled and completed vertical Oswego wells recently for $680,000. He said he had drilled and completed some wells to the same depth for $680,000 or less, but they weren't Oswego wells. He admitted he had contacted Blake to see whether they are able to drill vertical Oswego wells for $680,000. He also admitted he had not looked at detailed cost figures from any vertical Oswego wells to see whether or not they are staying within any estimates.

Mr. Stromberg was then asked about the instances where a horizontal well frac'd into a vertical well. He agreed it was a Mississippi horizontal well frac'd into a Mississippi vertical well. He said it was in Western Oklahoma, about 25 to 50 miles away from Kingfisher County. He also agreed that different formations and different depths may come up with different results in a frac job.

Testimony of Dale Howe

Mr. Howe testified as the Vice President of Twenty/Twenty Oil and Gas. He agreed he had received correspondence from Chesapeake in June of last year. He said it was certified mail for consent to formation of the horizontal well in Sections 15, 18 and 6, dated June 25th, 2015. He said they got it sometime after the date on the letter. He testified that after he received the letters, he called Mike Lovelace and told him the names and addresses of their investors. He said he also gave him the percentages that they owned. He also thought, at first, that he gave Mr. Lovelace the addresses of the investors, but wasn't sure. He said there was no further discussion about the consent requested. He wasn't sure if Mr. Lovelace called him or not. He said he had one more communication where he told Mr. Lovelace Twenty/Twenty might consent to the spacing. He said this happened after he got a certified letter in the name of his company, DHL Howe, Inc. He said the letter was dated August the 3rd, 2015. He said he had a conversation with Mr. Lovelace either the same day or within a couple of days of receiving the letter. He testified that he had spoken to his investors and some of them reported they had received certified letters from Chesapeake, but had not conversed with any Chesapeake representatives. He admitted that if Twenty/Twenty owns in excess of 50 percent in both the Watson and the John States, then Twenty/Twenty controls whether or not the necessary consent will be acquired. He also agreed

that calls and pleading with all of the other investors still would not get the required 50 percent. He further admitted all of the investors added together could not give the necessary consent.

FINDINGS AND RECOMMENDATIONS

There are four findings that must be made before an order can be issued granting a waiver of consent.

There must be a showing of due diligence to locate each owner having the right to drill in any existing well and/or any drilling and spacing unit producing from the same common source of supply as the proposed horizontal well unit and/or any party entitled to production from the requested common source of supply as the proposed horizontal unit. The respondent list contains the names and addresses of the parties identified as having the right to drill in the existing spaced unit. Chesapeake did not give notice to their partners in the interests they own. Chesapeake felt that having over a 50 percent interest negated giving notice of the proposed spacing as Chesapeake had over 50 percent ownership of those interests and could give consent without its partners. Chesapeake certainly can ascertain and locate its partners. The ALJ believes due diligence was exercised to locate and give notice to each owner having the right to drill in the proposed unit.

A bona fide effort must be made to obtain the required percentage of consent. In this cause Chesapeake presented evidence of their attempts to get waivers from the affected parties. They successfully obtained all the consents needed except for Twenty/Twenty and its partners. Chesapeake did not attempt to obtain the consent of the partners of Twenty/Twenty as those interests accounted for less than the required 50 percent and having all of their consents would not have met the required percentage in the unit. Chesapeake sent out notice of the proposed spacing via certified mail. Chesapeake also made contact by mail which included a cover letter explaining the included consent. Chesapeake also had email and telephonic communications attempting to gain the consent of the parties who had not given consent. Chesapeake did admit that the communications did not include the partners of Twenty/Twenty for reasons as stated above. The ALJ believes a bona fide effort was made by Chesapeake to obtain the required consent from Twenty/Twenty.

Chesapeake had to show that alternate methods of development are inadequate to prevent waste and to protect correlative rights unless the consent requirement is waived and the proposed horizontal well unit is created. As to preventing waste, it was uncontroverted that no vertical development had taken place in the area since 1980. It was also uncontroverted that with the exception of Chesapeake's proposed horizontal well, no party was contemplating drilling a vertical well. The principal reason given for this lack of development was that market conditions were not optimal. No explanation was given for a lack of development when oil prices were much higher than current pricing. Chesapeake is the only party contemplating any sort of development in this section. Without their activity waste will be created by leaving hydrocarbons in the ground unrecovered. While vertical wells could be drilled, the evidence showed that recovery of hydrocarbons is greater with horizontal wells than with vertical wells. This is due to

the tight nature and natural fracturing of the common source of supply. The well bore of a horizontal well will expose more of the producing interval than the well bore of a vertical well. The evidence shows that a horizontal well was expected to produce between 190,000 barrels of oil to 600,000 barrels of oil. The average ultimate recovery of the existing vertical well was estimated to be less than 90,000 barrels. The evidence also showed there was a range of between 283,000 to 853,000 barrels of oil to recover in the unit. It was stated that no party would contemplate drilling a horizontal well on an 80 acre unit. Thus the advantage of the horizontal well to recover more hydrocarbons will be lost if the 640 acre horizontal unit is not formed. This lack of 640 acre horizontal will not protect the correlative rights of the parties who will be unable to produce their hydrocarbons.

Finally, any owner's correlative rights, vested rights, or both, in the existing wells and or drilling and spacing unit and in the proposed horizontal well unit will be adequately protected if the consent is waived and the proposed horizontal well unit is created. Evidence was given that in the event a horizontal well is drilled and completed for production, that it will have a minimal impact on existing wells. Chesapeake's engineer gave evidence regarding two wells in an adjacent section that had horizontal wells drilled near existing vertical wells. While there was some affect upon the wells, the wells continued to produce after the work was completed n the horizontal well. Chesapeake was the only party to show evidence of actual production before and after the frac job was performed on the horizontal well. An attempt was made to refute this evidence by showing sales were down from 2014 to 2015, before and after the frac job in the two vertical wells that had nearby horizontal wells. This ALJ does not believe that sales equates to production. The evidence implied to this ALJ that public records regarding production do not appear to match records kept by the Oklahoma Tax Commission. Evidence was given that no party would purposefully harm their own well. Chesapeake drilled two wells near vertical wells they owned in another section. No one would believe that they would drill those wells if they thought it would hurt the production from their wells. As noted above there was minimal impact on those wells. Evidence was given by Twenty/Twenty regarding a well that was ruined in another county over 25 miles, in another common source of supply by a horizontal well drilled nearby. While the affected formation may have similar characteristics, such as being a carbonate, this evidence regarding the ruining of that well is too far removed to be applicable to this situation. Thus the ALJ finds that the correlative or vested rights of the owners in the existing wells will not be affected. As for the owners in the proposed horizontal spacing unit, their rights will be protected by the creation of the horizontal spacing unit so that they recover reserves that otherwise would not be recovered.

After consideration of all the evidence presented, it is the recommendation of the ALJ that the requested Horizontal Spacing in CD 201503764 be approved by the Commission.

RESPECTFULLY SUBMITTED THIS 17th day of August, 2016.

Michael J. Porter Administrative Law Judge

cc: Richard Books John E. Lee III Michael Decker Oil-Law Records Commission File Office of General Counsel