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Chesapeake Granite Wash Trust (NYSE:CHKR)

Q1 2013 Earnings Conference Call

May 9, 2013 10:00 am ET

Executives

Nick Dell'Osso – Executive Vice President and Chief Financial Officer

Steve Dixon – Acting Chief Executive Officer

Analysts

Justin Albert – Raymond James & Associates, Inc.

Aaron Terry – Kayne Anderson

Operator

Good day everyone, and welcome to the Chesapeake Granite Wash Trust First Quarter 2013 Earnings Results. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Nick Dell'Osso. Please go ahead.

Nick Dell'Osso

Good morning and welcome to the Chesapeake Granite Wash Trust Distribution conference call. This is Nick Dell'Osso, Executive Vice President and Chief Financial Officer at Chesapeake Energy. Also, joining me for the call this morning is, Steve Dixon, acting Chief Executive Officer of Chesapeake, and via teleconference is Sarah Newell, Vice President of Bank of New York Mellon Trust Company, the Trustee for Chesapeake Granite Wash Trust.

We have a few prepared remarks, and then we will take any questions you may have. Please note that today's call will contain certain forward-looking statements and assumptions that are subject to inherent risks and uncertainties. The actual results may differ materially from those projected in the forward-looking statements. Additional information about risk factors and other factors that could potentially affect the Trust and its financial results are included in the Trust's press release issued this morning and in the Trust filings with the SEC.

As a reminder, CHKR is a statutory Trust, which is required to distribute all cash flow after expenses. The trust has no employees or officers and Chesapeake Energy as the sponsor of the trust is responsible for operating the properties, in which the trust has an interest and fulfilling certain drilling commitments, which is also detailed in the Trust filings with the SEC.

As stated in the press release this morning the distribution for the three-month period ended February 28, 2013 from CHKR will be $0.69 per common unit and approximately $0.30 per subordinated unit. Worth noting, Chesapeake Energy owns 100% of the subordinated units. The distribution will be paid on May 31, 2013 unitholders of record at the close of business on May 21, 2013.

The calculated distribution for this period is approximately $0.59 per unit. However, since this is below the predetermined subordination threshold for the quarter of $0.69 per unit, the distribution per subordinated unit will be reduced in order to make a distribution up $0.69 per common unit.

I’ll now turn the call over to Steve Dixon.

Steve Dixon

Thanks Nick. The three-month period from December 1 through February 28, 2013, total sales volume attributed to trust royalty interest for 149,000 barrels of oil, a 2% sequential decrease; 312,000 of barrels of natural gas liquids, 5% sequential decrease; and 2.886 billion cubic feet of natural gas, a 6% sequential decrease.

Total sales of approximately 942,000 barrels of oil equivalent BOE were down 5% sequentially. Production mix in first quarter of 2013 was 16% oil, 33% NGLs and 51% natural gas.

As development in drilling continues and as well performances further analyzed, we are gaining additional knowledge about the Granite Wash Reservoir. For instance, we have learned that the reservoir permeability and sand body continuity within the Granite Wash AMI is higher than expected.

This has resulted in lower than predicted reservoir pressure and some recent infill well locations. This had resulted in lower IP rates and lower recoverable reserves and some newer wells, as well as downward reserve revisions on some previously drilled wells.

We are adjusting development plans in locations accordingly to maximize the value of this asset. Realized prices for the period were $88.08 per barrel of oil, $32.67 per barrel of natural gas liquids and $2.28 per Mcf natural gas. These prices include the effects of transportation and third-party deducts.

For the quarter un-hedged realized oil prices were higher by $1.81 per barrel, natural gas liquids prices were higher by $0.75 per barrel and natural gas prices were higher by $0.34 per Mcf when compared to the previous quarter.

On March 15, CHKR filed a 10-K with the SEC providing updated year-end 2012 reserve data. Total proved reserves as of December 31, 2012 were 28.2 million BOE. During 2012 the trust recorded downward reserve revisions of 11.5 million BOE including 1.1 million BOE of downward revisions resulting from lower natural gas prices and 10.4 million BOE of downward revisions resulted from changes to previous estimates.

The changes to previous estimates were primarily as a result of higher than expected pressure depletion within certain areas of the Granite Wash AMI, to mitigate this issue we are evaluating the benefits of drilling only three wells per section rather than four wells. Preliminary results while early have been encouraging.

As noted in the 10-Q filed yesterday, the Trust evaluates the quarterly carrying value of the investment in trust interest under the full cost accounting method prescribed by the SEC. This quarterly review is referred to as ceiling test. Under the ceiling test carrying value of the investment in royalty interest may not exceed an amount equal to the sum of the present value using a 10% discount rate of the estimated future net revenues from the proved reserves.

During the first quarter celling test evaluation, the carrying value of the investment and royalty interest exceeded its discounted present value of estimated future net revenues, resulting in $32.9 million impairment. This impairment is a non-cash charge to Trust Corpus and was no effect on distributed income or taxable income.

Turning to hedges, actual NYMEX oil prices were above swap contract prices held by the Trust resulting in a realized loss on oil contracts of approximately $1 million for the period. These fixed oil swap contracts were initially established to hedge approximately 50% of projected oil and natural gas liquids volumes.

The use of crude oil derivatives to partially mitigate the price risk of NGL production is subject to basis risk to the extend oil and NGL prices are not highly correlated. The initial forecasted revenues of the Trust assumed an NGL price of 49% of WTI, actual NGL prices during the quarter were lower at 37% of WTI. The trust has no natural gas hedges in place.

Turning to the drilling results in the Trust AMI, during the quarter, Chesapeake brought on line seven gross operated wells by running four rigs in the Trust AMI. Through April Chesapeake has completed approximately 65 development wells as calculated under the development agreement and is ahead of schedule to meet its 118 development well commitment to the Trust by June 30, 2016.

We will now take any questions you might have. Operator, please open up the line for Q&A.

Question-and-Answer Session

Operator

Thank you. At this time we will start the question-and-answer session. (Operator Instructions) And we will go first to Justin Albert with Raymond James.

Justin Albert – Raymond James & Associates, Inc.

In light of the three wells per section versus typical four wells per section, in your estimation guys, how many locations do you believe you have remaining in AMI.

Nick Dell'Osso

We have plenty of locations to meet our commitment. I believe we have 356 wells yet to drill and yes we have plenty of remaining locations.

Justin Albert – Raymond James & Associates, Inc.

Alright. Perfect. And then just a follow-on to the negative PUD revision in your reserve report. Do you guys have an updated type curve? You mentioned the IPs are lower, do you have any numbers for that?

Nick Dell'Osso

Well, we are hoping by increasing our spacing that we don’t have near the influence and so that are PUDs going forward, will not be as influence. So we are studying that hard and again trying to maximize what we get out of the trust AMI.

Justin Albert – Raymond James & Associates, Inc.

Alright, great thanks.

Operator

We will take our next question from Aaron Terry with Kayne Anderson.

Aaron Terry – Kayne Anderson

Good morning guys. I just want to follow up on Justin’s questions. Can you at least give what the PUD bookings were, the EURs on the PUD bookings on the 2012 reservoir report?

Nick Dell'Osso

I don’t know the average PUD’s bookings, sir.

Aaron Terry – Kayne Anderson

And then as far as talking through the three wells per section, if you’re stating you have around 50 wells to 56 wells remaining, do you plan on drilling all of this wells on 3 wells per section or do you kind of give a development concept for what you guys have planned for this?

Steve Dixon

We are studying that hard and it kind of depends on how good the first wells were and how interconnected we think it is across that section. So, I don’t know that all wells will be 3, some could probably still handle four.

Aaron Terry – Kayne Anderson

Okay. And I’m sorry, I actually didn’t get the number that you stated as far as wells that you brought on line during the quarter and I don’t think it was in the press release. What was that number again?

Nick Dell'Osso

Yeah, seven.

Aaron Terry – Kayne Anderson

Seven wells during the quarter. Is that a pretty fair assessment for what you would expect to be the run-rate in the number of wells on line in the future?

Steve Dixon

Yes, sir. I think seven to eight, good run-rate.

Nick Dell'Osso

It has been lumpy at times due to completion activity, but that’s been not abnormal to be right in that range.

Steve Dixon

And that’s again – that’s the pace I believe that was in the original prospectus well.

Aaron Terry – Kayne Anderson

Okay. And so you haven’t seen any wells flow yet on the three wells per section or have you seen any expectations. Is there anything, any color you can guided as far as how you would expect that to change the original IP rates, or are you just expecting that to be closer to what the original type curve was?

Nick Dell'Osso

Yeah, we have seen some with some positive results, and again when you have three versus four, you used to get a lot less straws in that same reservoir, so you have less pressure draw down and interface effect, so…

Aaron Terry – Kayne Anderson

Okay.

Nick Dell'Osso

Okay.

Aaron Terry – Kayne Anderson

Alright, thanks guys. That’s all I have.

Operator

(Operator Instructions)

Nick Dell'Osso

No further questions. Okay, well thank you. Thank you everyone. Appreciate the time this morning. Thank you.

Operator

Again that does conclude today’s presentation. We thank you for your participation.

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