Chesapeake Granite Wash Trust's CEO Discusses Q2 2013 Results - Earnings Call Transcript

Aug.10.13 | About: Chesapeake Granite (CHKR)

Chesapeake Granite Wash Trust (NYSE:CHKR)

Q2 2013 Earnings Call

August 9, 2013 10:00 am ET

Executives

Nick Dell'Osso, EVP & CEO

Steve Dixon, CEO & COO

Sarah Newell - VP, Bank of New York Mellon Trust Company

Analysts

Ronald Goldstein – Lighthouse Point Capital Management

Ted Durbin – Goldman Sachs

Operator

Good day and welcome to the Chesapeake Granite Wash Second Quarter 2013 Earnings Results Call. 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, sir.

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 of Chesapeake Energy.

Also joining me for the call this morning is Steve Dixon, Chief Executive Officer and Chief Operating 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 factors that could potentially affect the Trust and its financial results are included in the Trust's press release issued yesterday and in the Trust filings with the SEC including the 2013 second quarter form 10-Q the Trust filed yesterday.

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 yesterday afternoon, the distribution for the second quarter of 2013, which primarily relates to production attributable to the Trust’s royalty interests for the three month period ended May 31, 2013 from CHKR will be $0.69 per common unit and approximately $0.14 per subordinated unit. Worth noting, Chesapeake Energy owns 100% of the subordinated units.

The distribution will be paid on August 29, 2013 to unitholders of record at the close of business on August 19, 2013. The calculated distribution for this period is approximately $0.55 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. For the three month period of March 1, 2013 through May 31 of 2013, total sales volumes attributed to the trust royalty interest were 132,000 barrels of oil, a 12% sequential decrease; 267,000 barrels of natural gas liquids, a 15% sequential decrease; and 2.894 billion cubic feet of natural gas, a normal sequential increase.

Total sales of approximately 881,000 barrels of oil equivalent were down 7% sequentially. Production mix in the three month period ended May 31, 2013 was 15% oil, 30% NGLs and 55% natural gas.

Realized prices for the period were $88.88 per barrel of oil, $31.42 per barrel of natural gas liquids and $2.65 per Mcf of natural gas. These prices include the effects of transportation and third-party deductions.

For the period un-hedged realized oil prices were higher by $0.80 per barrel, natural gas liquids prices were lower by $1.25 per barrel and natural gas prices were higher by $0.38 per Mcf when compared to the previous period.

Turning to hedges, actual NYMEX oil prices were above swap contract prices held by the Trust is resulted in a realized loss on oil contracts of approximately $1.1 million for the period. These fixed price oil swap contracts were initially established to hedge approximately 50% of the 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 forecast revenue for the Trust assumed that NGL price at 49% of WTI, actual NGL prices during the quarter were lower at 36% of WTI. The trust has no natural gas hedges in place.

Turning to drilling results in the Trust AMI, during the three-month period ended May 31, 2013 Chesapeake completed approximately seven development wells as calculated under the development agreement are running four rigs in the Trust AMI. Through July Chesapeake has completed approximately 75 development wells, which is 64% of the total of 118 development well obligation.

As we noted in last quarter’s conference call, we are continuing to analyze the current underperformance of certain wells in the Trust AMI. We have learned that the reservoir permeability in sand body continuity within the Colony Wash reservoir are higher than was expected, which is resulted in lower than predicted reservoir pressure in some development well locations. This has resulted in lower initial production rates, lower recoverable reserves as well as a downward reserve revision to some older drilled wells.

As previously reported, the Trust recognized a $32.9 million impairment during the quarter ended March 31, 2103 and the trust is also recognized an impairment of $11.2 million during the quarter ended June 30, 2013 primarily because of these results.

With the goal of improving average well performance in the Granite Wash, Chesapeake has made the decision to reduce its recount in the AMI from four rigs to two rigs by mid-August 2013. We believe this slower rate of development is prudent and we provide the company more time to assess the performance of each new producing wellbore and to optimize future wellbore locations and intervals to be drilled because there is a finite number of wells remaining in the Trust to be drilled, Chesapeake’s intent is to select the very best available locations at internals in the Granite Wash formation.

However, well performance does not improve; the revenues and distribution income available to unitholders will be reduced, which may contribute to future distribution to common unitholders at or below subordination threshold.

While we believe this moderated phase of drilling to ultimately improve the economic returns of the Trust, the operated well count reduction will decrease the rate in which royalty income from the remaining development wells becomes available to the trust for distribution.

It combined with continued low commodity prices and reduce well performances will likely result in future distributions to common unitholders below the subordinated threshold. However, the moderated phase of drilling will not have the significant impact on distributions until the distribution will be paid in the first quarter 2014. This will primarily relate to production attributed to the Trust royalty interest for the three month period ended November 30, 2013.

I would like to conclude our prepared remarks by noting the Chesapeake owns 50.8% of the outstanding units of CHKR and owns approximately 72% working interest in the Colony Wash wells. Further as a 100% owner of subordinated units of the Trust Chesapeake’s cash distribution to the Trust have been negatively impacted by the issues I described above.

We are heavily invested in the economy outcome of this play and is operated we are working very hard to improve performance of these wells.

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

Question-and-Answer Session

Operator

(Operator Instructions). We will go first to Ronald Goldstein of Lighthouse Point Capital Management.

Ronald Goldstein – Lighthouse Point Capital Management

Thank you. My question is if you could discuss the other factors besides transportation that result in the differential between NYMEX and your realized wellhead prices for natural gas, give us a little more detail as to how we calculate that differential.

Steve Dixon

For the significant component is going to be transportation there are from time to time basis differentials in just the pricing we receive in this part of Oklahoma relative to Henry Hub gas that has been a little more volatile over the last couple of months and has widened down a bit from time to time.

There are processing charges that apply to the creation of the natural gas liquids out of the gas stream, but by and large for natural gases and differential you could see the transportation costs as well as and the basis differential.

Ronald Goldstein – Lighthouse Point Capital Management

Given the location of this field, how much is its transportation relative the other factors?

Steve Dixon

We will have to follow-up with you on that. But the transportation is going to be the larger component.

Operator

(Operator Instructions) We will go next to Ted Durbin of Goldman Sachs.

Ted Durbin – Goldman Sachs

Hi, I just want to thank you. I wanted to just follow-up on I think of ending comments there. So, if I understand it, the way you're looking at the projections here, if you go from four rigs to two and given the well results you've seen, and I think, given commodities, I know there were a lot of things that were in the assumptions there. Do you think you could go below the subordinated distributions as well as early as the first quarter of 2014? Did I hear that right?

Steve Dixon

That won’t be paid. It could happen as early as the fourth quarter of this year, but that wouldn’t get paid until first quarter of next year.

Ted Durbin – Goldman Sachs

Okay. That's just using sort of spot NGL prices and gas prices?

Steve Dixon

Right, current prices because we just with reduce new wells coming on line.

Ted Durbin – Goldman Sachs

Got it. And then is there any sense here of the timing of, because you have the window of when you have to hit the 118 wells. Do we think we're then on the back half of what that is based on the current drilling program?

Steve Dixon

It really depends on how long we stay at a two rig program. So, Ted if we were to stay at a two rig program we can get there by the end of the period. Our hope would be that by going to two rig program, we identify more optimal development plan here and would be in a position to increase rig count at some point in the future. But again we need to go through that process and find that more optimal program. So, there is no real, we don’t have timing for when that could happen.

Ted Durbin – Goldman Sachs

Got it. Okay, that's it for me. Thanks.

Operator

And at this time, we have no further questions.

Steve Dixon

Okay. Thank you all for dialing in this morning. We will look forward to talking to you next quarter.

Operator

And that concludes today’s conference. We thank you for your participation.

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