Copano Energy LLC Management Discusses Q3 2012 Results - Earnings Call Transcript

| About: Copano Energy, (CPNO)

Copano Energy LLC (NASDAQ:CPNO)

Q3 2012 Earnings Call

November 08, 2012 10:00 am ET


Douglas L. Lawing - Executive Vice President, General Counsel and Corporate Secretary

R. Bruce Northcutt - Chief Executive Officer, President and Director

Bryan W. Neskora - Chief Operating Officer and Senior Vice President

Carl A. Luna - Chief Financial Officer and Senior Vice President


TJ Schultz - RBC Capital Markets, LLC, Research Division

Rebecca Followill - U.S. Capital Advisors LLC, Research Division

Ben Wyatt - Stephens Inc., Research Division


Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Copano Energy’s Third Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, November 8, 2012.

I would now like to turn the conference over to Doug Lawing, General Counsel. Please go ahead, sir.

Douglas L. Lawing

Thank you, and good morning. We appreciate you joining us today for Copano's conference call to review financial and operating results for the third quarter of 2012. Before we begin, I have a few housekeeping items. If you’d like to be on our email distribution list to receive future news releases, please call our Investor Relations firm, DRG&L. Their number is (713) 529-6600.

A replay of the call will be available later this morning. Information on how to access the replay is provided in the news release. Please note that information recorded on this call speaks only as of today, November 8, 2012. Therefore, time-sensitive information may no longer be accurate as of the date of any replay.

Our discussion today will include forward-looking statements that are based on management’s belief, as well as on certain assumptions based on its experience and perception of historical trends, current conditions and expected future development. Actual results are subject to a number of risks and uncertainties and may vary materially from the forward-looking statement discussed on today’s call. These risks are discussed in our annual and quarterly reports filed with the SEC.

Please note, that on this call, we will use the terms gross margins, EBITDA, adjusted EBITDA and total distributable cash flow. These are non-GAAP financial measures, and we’ve provided reconciliations to comparable GAAP measures in our news release. In addition, the reconciliation of adjusted EBITDA to net income for our operating segments can be found in the Investor Relations page of our website under Events.

With that, I’ll turn the call over to Bruce Northcutt, our President and CEO.

R. Bruce Northcutt

Thank you, Doug, and good morning to everybody on the call. I'd like to begin this morning with a high-level review of our third quarter, followed by an update on our Eagle Ford Shale strategy. Following my comments, Bryan Neskora, our Chief Operating Officer, will discuss the operational results for the quarter, as well as update you on our current expansion projects. Carl will then review our financial results for the quarter and discuss our recently completed equity offering. After Carl's comments, I'll make some brief remarks to wrap up, and we'll take your questions at the end.

In the third quarter, total distributable cash flow increased $17.6 million, or 45% from the second quarter of 2012, to $57.1 million. This increase is partially due to a gain of $9.7 million from the sale of our non-core Lake Charles plant and an over $6 million improvement in Texas segment gross margin compared to last quarter.

We continue to see increasing volumes from the Eagle Ford Shale, with total volumes, including volumes on the Eagle Ford Gathering JV, increasing 16% or 77,000 MMBtu per day from the second quarter of 2012. While this increase was primarily driven by volumes gathered by our Eagle Ford Gathering JV, we also gathered higher volumes on our wholly-owned DK pipeline.

In recent calls, we have mentioned the continued interest from Eagle Ford Shale producers for additional midstream services. Several days ago, we extended an expanded relationship with a large privately-held producer behind our wholly-owned DK pipeline. Under the terms of the new agreement, what was previously a 5-year acreage dedication contract was converted to a 10-year volume commitment contract, with volumes reaching as high as 300,000 MMBtu per day of rich Eagle Ford shale gas.

Peak volumes from this producer will utilize all of the remaining capacity of our second 400-million-cubic-foot-a-day cryo unit scheduled to be complete in the second quarter of 2014. We were thrilled that this producer chose to strengthen its relationship with Copano through what is now our largest producer contract in the Eagle Ford, and we continue to pursue additional opportunities as the Eagle Ford Shale play develops.

Turning to prices. During the third quarter, Mont Belvieu NGL prices fell 5% from the second quarter and Conway NGL prices fell 4% from the second quarter. So far in the fourth quarter, natural gas liquid prices have improved from third quarter averages, particularly for Conway. Due to the sharper decline in Mont Belvieu prices compared to Conway in the third quarter, the basis differential for NGLs decreased by 37% from the second quarter to $0.17 a gallon. We have seen the differential tighten further in the fourth quarter to around $0.10 a gallon. We believe that until additional NGL pipeline capacity is placed in service between the Mid-Continent and Mont Belvieu, we will continue to see volatility in the spread.

Natural gas prices in the third quarter increased 27% from the second quarter and continued to increase in the fourth quarter. We believe these increases are primarily the result of higher demand for gas-fired power generation, as well as declining dry gas production. While our business remains subject to commodity price exposure, we have greatly reduced our sensitivity to price movements by shifting our contract mix to a greater percentage of fee-based contracts, which accounted for 63% of our total gross margin for the third quarter compared to 48% in the third quarter a year ago.

Now I'll ask Bryan to update you on our operational results for the quarter and current expansion projects. Bryan?

Bryan W. Neskora

Thanks, Bruce, and good morning to everybody. In Texas, third quarter service throughput decreased slightly over the second quarter but increased 17% versus the third quarter of last year, to 898,000 MMBtu per day. The decrease from the second quarter was due to the sale of our Lake Charles plant in the third quarter. Excluding volumes processed at Lake Charles, service throughput in the third quarter increased 7% over the second quarter and 8% versus a year ago. Both increases were primarily due to the growing rich Eagle Ford Shale volumes.

Total gas volumes from the Eagle Ford Shale averaged 567,000 MMBtu per day in the third quarter, which was up 16% from the second quarter and up 248% compared to the third quarter a year ago. Of these volumes, 247,000 MMBtu per day were gathered on our wholly-owned systems and 320,000 MMBtu per day were gathered on our joint venture pipelines. Gathered volumes on our Saint Jo system increased slightly, averaging 127,000 MMBtu per day during the third quarter and inlet volumes to our Saint Jo plant continue to be at capacity.

As a result of the growing rich volumes gathered in the Eagle Ford Shale, third quarter Texas segment NGL production increased by 9% compared to the second quarter of this year and 75% versus the third quarter of last year at 54,000 barrels per day. Excluding barrels from Lake Charles, NGL production increased by 12% compared to the second quarter of this year.

Eagle Ford Gathering JV NGLs produced at third-party plants averaged over 12,000 barrels per day for the third quarter, an increase of 25% compared to the second quarter of this year. During the third quarter, we are seeing good performance from our Texas assets, which we expect to continue in the fourth quarter as Eagle Ford Shale volumes continue to ramp up.

Turning to Oklahoma. Service throughput decreased slightly compared to the second quarter but increased 9% from the third quarter a year ago to 313,000 MMBtu per day. The volume decrease from the second quarter was driven by lower lean gas production in the Woodford Shale. Plant inlet volumes were slightly lower than the second quarter, and NGL production of 16,000 barrels per day was down 5% compared to the second quarter and 7% compared to the third quarter a year ago since some of our plants operated in ethane rejection during the third quarter of this year. We expect slightly declining volumes in the fourth quarter due to lack of drilling in the lean Woodford areas, and we expect some of our plants to continue to operate in ethane rejection during the quarter.

In the Rockies, volumes on the Bighorn system decreased as a result of lack of drilling and averaged 110,000 MMBtu per day in the third quarter, a decrease of 9% from the second quarter and 20% from the third quarter a year ago. Volumes on the Fort Union system decreased 7% from the second quarter due to lower volumes from Bighorn, but were up 10% versus the third quarter a year ago, to 585,000 MMBtu per day. The year-over-year increase is primarily due to producer volumes previously flowing on Bison pipeline coming back to Fort Union.

Now I'd like to update you on our current expansion projects. Construction on the first 400-million-a-day cryo expansion at the Houston Central complex is progressing well. And as previously discussed, we expect the first quarter of 2013 in-service date. We are working hard to complete the project ahead of schedule, which will require acceleration of some capital expenditures into the fourth quarter of this year. Additionally, Formosa's fractionation expansion at its point comfort facility is under way and is scheduled to come online in the second quarter of 2013. We will have 37,500 barrels per day of fractionation capacity at Formosa's expanded facility when it is complete.

An EPA permit application has been submitted for our second 400-million-a-day cryo expansion at Houston Central. Based on a 1-year permitting process and the time required to construct the second cryo, we currently anticipate a mid-2014 startup. In order to meet our expected in-service date, we have begun the procurement process for long lead items. The 2014 cryo expansion is supported by long-term fee-based capacity commitments with major producers, including the expanded commitment that Bruce mentioned earlier. When these 2 expansions are complete, we will have a total of 1 Bcf a day of highly efficient cryogenic processing capacity at Houston Central.

Construction on the southwest extension of our DK pipeline announced earlier this February is well under way. Right-of-way is almost complete, and the pipe has been delivered to the location. We expect to begin service late in the first quarter of 2013.

And finally, we are making good progress on the Double Eagle Pipeline. Our 50-50 joint venture with Magellan Midstream Partners, which will provide 100,000 barrels a day of condensate and crude oil gathering from the Eagle Ford Shale for delivery to Magellan's terminal on the Corpus Christi ship channel. All necessary permits have been secured, and construction is under way on the pipeline connecting Double Eagle's Three Rivers storage and truck terminal to Magellan's terminal at Corpus Christi. The Nueces Bay crossing is complete, which significantly de-risks the cost and in-service timing of the project.

Construction of our Three Rivers Terminal is also in progress and scheduled to be complete in the first quarter of 2013. We expect to be able to flow volumes from Three Rivers to Corpus Christi in the first quarter of next year and to complete the extension into Karnes County shortly thereafter. We also anticipate that further extension to Gardendale and LaSalle County will be completed late in the second quarter of 2013, providing access to additional production areas in the western Eagle Ford.

In Oklahoma, we have commenced construction of a pipeline connecting our Osage and Stroud systems in order to deliver rich Mississippi Lime gas gathered on the Osage system to the Paden processing plant where we can provide processing and nitrogen-rejection services. Construction is progressing quickly, and we expect this project to be complete by the end of this year, ahead of schedule. We now have roughly 140,000 acres under dedication for multiple producers in the Mississippi Lime, up from 50,000 acres that we mentioned on our last call.

Now with that, I'll turn the call over to Carl.

Carl A. Luna

Thanks, Bryan. As Bruce mentioned earlier, total distributable cash flow for the third quarter was $57.1 million, which was up 45% compared to the second quarter and up 55% versus the third quarter a year ago. The improvement in total distributable cash flow resulted in 124% coverage of our third quarter distribution compared to 93% coverage for the second quarter of this year.

The reported coverage includes the additional common units we issued in late October, as well as the gain on the sale of our Lake Charles plant. Excluding the additional units, coverage would have been 134%, and excluding the $9.7 million gain, coverage would have been 103%.

Now looking at our operating highlights by segment. In Texas, third quarter segment gross margin increased approximately 12% from the second quarter and increased about 24% from a year ago, to $55.2 million. The improvement over the second quarter was primarily the result of increased volumes from the Eagle Ford Shale play and enhanced performance at our Houston Central complex, partially offset by lower margins generated by the Lake Charles plant.

We received $6.3 million in distributions from Eagle Ford Shale Gathering during the third quarter, an increase of 30% from the second quarter. The increase was also due to higher Eagle Ford volumes and better performance at Houston Central. Keep in mind, Eagle Ford Gathering is unconsolidated and therefore, distributions we receive are not reflected in our segment for this margin.

Looking ahead to the fourth quarter for Texas. We currently expect Texas segment gross margin for the fourth quarter to be flat compared to the third quarter, primarily due to the sale of our Lake Charles plant and a shift in commodity prices. We also expect distributions from Eagle Ford Gathering JV to be roughly $2 million higher in the fourth quarter based on increasing volumes.

Now moving to Oklahoma. Third quarter segment gross margin increased by 14% from the second quarter and decreased 18% versus the third quarter a year ago, to $22.9 million. The increase from the second quarter was driven primarily by higher natural gas prices. The year-over-year decrease resulted from lower NGL and natural gas prices compared to the third quarter of 2011 and was partially offset by higher lean volumes from the Woodford Shale play. Looking ahead to the fourth quarter for Oklahoma. We expect the Oklahoma segment gross margin to increase slightly in the fourth quarter due to higher natural gas prices, which should offset lower overall volumes.

Touching briefly on the Rockies. Third quarter adjusted EBITDA for the Rockies, included -- including Bighorn and Fort Union, was $5.4 million, which compared to $7.2 million for the second quarter and $5.1 million for the third quarter of last year. The decrease from the second quarter was primarily due to lower cash distributions from Fort Union, offset by an $800,000 payment we received as a onetime imbalance cash-out and a $600,000 distribution from Bighorn related to the sale of non-core asset.

Also, Fort Union second quarter distribution was higher because it included an annual fee and deficiency payment. Adjusted EBITDA for the Rockies is estimated to be approximately $1 million to $2 million lower in the fourth quarter due to the third quarter nonrecurring items that I just mentioned and lower volumes.

Now turning to corporate and other. Third quarter gross margin was a loss of $3.7 million compared to a gain of $3.4 million for the second quarter and a loss of $8 million in the third quarter a year ago. The loss compared to the second quarter was primarily due to higher noncash amortization expense and unrealized losses on derivatives, partially offset by higher net cash settlements received.

We received net cash settlements on our commodity hedges of $4.8 million in the third quarter compared to $3.5 million in the second quarter and payments of $2.9 million for the third quarter a year ago. Based on current commodity prices, we expect cash settlements from our hedges in the fourth quarter to be lower by approximately $1.5 million.

Now moving to expense items for the third quarter. G&A expense was $13.7 million, which was up 33% from the second quarter and 37% from the third quarter a year ago. The increase from the second quarter was primarily due to higher noncash deferred equity compensation expense and collection in the second quarter of a previously written-off receivable. The year-over-year increase in G&A was primarily due to increases in noncash deferred equity compensation, as well as salaries and benefits associated with increased headcount related to our growth initiatives.

Operating and maintenance expense was $19.2 million, which was up 5% from the second quarter and 20% from the third quarter a year ago. These increases are primarily due to higher expenses for our expanded assets in the Eagle Ford Shale. Interest expense was $13.8 million, which is down 2% from the second quarter and up 24% from a year ago. The year-over-year increase was primarily due to higher debt levels associated with our capital expansion program.

Previously, we had provided guidance that interest expense for the full year 2012 will be in the $63 million to $67 million range. Given our current debt levels and higher capitalized interest, we now expect interest expense to be in the $53 million to $57 million range for the full year.

Finally, turning to CapEx and liquidity. During the third quarter, we spent a total of $114 million in expansion capital, including $96 million on wholly owned projects and $18 million on joint venture projects. We also spent approximately $2 million in maintenance capital during the quarter.

For the fourth quarter of 2012, we expect to spend approximately $115 million to $125 million for wholly owned and JV expansion projects and $3 million to $4 million in maintenance CapEx. For the full year 2012, we expect to spend approximately $430 million for wholly owned and JV expansion projects, which is at the high end of our previous guidance range of $400 million to $430 million.

As of September 30, we had $330 million borrowed on our revolving credit facility, and including our cash, we had over $228 million of total available liquidity. In October, we've closed a public offering of approximately 6.5 million common units issued at $32.13 per unit. Net of underwriting discounts and expenses, we received approximately $200 million in cash.

We'll use the proceeds from the offering to pay down our revolver, and we will use the resulting increase in liquidity to fund part of our 2013 capital expansion program. Adjusted for our October equity offering, our revolver balance would have been approximately $130 million and total liquidity would have been in excess of $400 million.

With that, I'll turn it back over to Bruce.

R. Bruce Northcutt

Thanks, Bryan and Carl. As we continue to focus on delivering our growth projects on time and on budget, we also continue to pursue new areas of growth, and I want to touch briefly on one of these projects.

We're working with producers in the Woodbine shale, a rich resource play behind our upper Gulf Coast gathering system located north of the Houston area. While it's still relatively a new play, we have gained enough confidence in recent well performance to set a leased processing plant in that area. We used a similar approach to launch our north Barnett Shale Combo play strategy before we built our Saint Jo processing plant. We believe that this strategy will allow us to gather enough volumes to economically install a larger cryogenic processing plant as the play develops further.

And we continue to see opportunities for additional capital projects around our existing Eagle Ford assets, where we will have invested approximately $1 billion in projects by the end of 2013. These projects provide a firm foundation for total distributable cash flow and distribution growth for the next several years and for additional growth opportunities.

And finally, I'd like to also recognize and thank our employees for their hard work and dedication to our initiatives, both this past quarter and throughout the year.

With that, I'll turn it back to the operator for opening the line for your questions.

Question-and-Answer Session


[Operator Instructions] Our first question comes from the line of TJ Schultz with RBC Capital.

TJ Schultz - RBC Capital Markets, LLC, Research Division

I guess just first on that last point in the Woodbine, maybe if you could expand on what some of the near-term CapEx you may have allocated there and then, when we think about timing for the ability to install a new cryo, kind of what that time frame looks like.

R. Bruce Northcutt

Sure. Right now, the capital for setting the leased refrigeration plant, TJ, is probably going to be somewhere around $2.5 million. That doesn't include the ongoing monthly lease payments. That also doesn't include the gathering lines behind the systems, which that will be ongoing. We expect that we'll have that in place in the first quarter of 2013. And then to your question about when do we think that we'll start realizing some -- enough growth in order to set a full cryo, obviously the permitting process on a new plant takes a little longer in Texas than it has in the past. But we're contemplating that, that would probably be something we might just be able to start by -- depending upon wells and activity in the area, by the end of this next year and probably wouldn't be completed until -- into the 2014 time frame, if everything went according to plan. Again, it'll be a lot dependent upon how the producers perform during that time frame.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay. I guess on the -- just moving over to the new 10-year volume commitment on the DK pipeline. I guess, what are your expectations there? I think you said the peak volumes would fill the second cryo. Kind of, what's your expectation for them to hit those peak volumes as you look to fill that cryo.

R. Bruce Northcutt

Well, first of all, we'll see a little bit of that volume at the back end of 2013. We expect right now that the lion's share of it probably in the 2014 time frame, whenever the second cryo comes on. So I think Bryan may know when we hit peak volume, but it's probably late 2014, I believe. It's -- this producer, without going into too much detail, is -- their acreage is truly in the heart of that DeWitt, Karnes County area that seems to perform better than even the stuff in the southwest part of the play.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay. I guess just one last one real quick. Any update to the 2013 gross CapEx budget? I think you had $250 million to $300 million. Then just kind of funding, does this equity you just did, in your mind, take care of funding for next year?

Carl A. Luna

TJ, this is Carl. We ended up doing $200 million on the equity, with a slight upsize from the base offering. We said last time that we would only comment on our 2013 guidance to the extent that it changed materially, so we don't see any changes to that here, obviously, or we would update you one way or the other. We'll kind of continue that plan. But from -- as the CapEx develops and if it does kind of get outside the ranges that we talked about with any significance, we'll come back and update it, update really kind the whole thing because if we're going to add CapEx, we have to include other factors associated with that.


[Operator Instructions] Our next question comes from the line of Becca Followill with U.S. Capital Advisors.

Rebecca Followill - U.S. Capital Advisors LLC, Research Division

Two quick questions. One, do the volumes, I missed this on your -- when you're explaining your Texas segment. Did the volumes include anything from the Louisiana, Lake Charles plant?

R. Bruce Northcutt

They did. We can get you the actual number here in just a second. The -- of course, for the fourth quarter, it will not. We'll get you...

Rebecca Followill - U.S. Capital Advisors LLC, Research Division

While you're looking it up, then I'll go to my next one. When you look at the yields, just taking your NGLs divided by the plant inlet, we're seeing some nice increases in that yield going from roughly 1.8 in Q4 and Q1 to 2.52 in Q2 and 2.8 in Q3. And I would expect that yield to go higher just because as the Lake Charles plant goes away, that's lower yielding volumes. So it sounds like your guys are doing a really good job of being able to handle more of the rich Eagle Ford gas. Can you talk a little bit about where you think that yield goes as we go into -- prior to the new plant coming online and then after that new plant comes online? I don't know if you guys look at it that way, but it's one way at least that we kind of follow what potentially margin could be.

R. Bruce Northcutt

I'll take a shot at answering that. Becca, to answer your first question, for the third quarter our actual volumes were 70 -- roughly 75,000 MMBtu a day for Lake Charles. And you're right. I mean, we see a pretty big increase in the Eagle Ford volumes, obviously, overtaking what we'll lose on out of the Lake Charles plant. And again, the margins we were making on the Lake Charles plant are really not in the same league, really, so to speak, as what we'll see from the Eagle Ford Gathering JV. We don't really comment about our actual recoveries at Houston Central, as you know I've discussed before, but we have seen improvement in recoveries, partially due to just better operations at the plant, lower amount of downtime, lower fuel and flair but also because, as you know, we also are processing gas for the joint venture, both at Formosa and at the Williams plant. And we've been able to get a little bit more volume out of those 2 facilities, which have a little bit higher recovery. And of course, what we're looking forward to is, is the January time frame or the first quarter when we hope to have our Houston Central plant, our first 400-million-a-day cryo, which is highly efficient cryo that will improve our recoveries, not just for the heaviers but more importantly for the ethane as well. That won't -- we won't see the full brunt of that increase, which we're really anticipating really until the Formosa expansion of their fractionator is completed in the second quarter. So we are seeing improvement in the recoveries. We expect that to continue even in the first quarter as the new plant comes on but even more so whenever we get the Formosa fractionators up and running. Did that get it?

Rebecca Followill - U.S. Capital Advisors LLC, Research Division

Is it fair to say that the recoveries that you saw in the third quarter, if we strip out the Lake Charles volumes, that, that's probably kind of maxed out until you get the new plant online and then Formosa?

R. Bruce Northcutt

No, I don't think so. I think we can do -- I think we could still do more volume.


[Operator Instructions] Our next question is from the line of Ben Wyatt with Stephens.

Ben Wyatt - Stephens Inc., Research Division

Just a quick question on just the Eagle Ford growth. When you guys talk about even more potential for Eagle Ford growth, just curious your thinking on or if any type of down-spacing opportunities or production or other formations or anything like is in your thinking and in your growth plans right now? Or is that even additional upside as E&Ps find additional ways to gather more hydrocarbons?

R. Bruce Northcutt

You're talking in particular in the Eagle Ford area?

Ben Wyatt - Stephens Inc., Research Division

In the Eagle Ford, yes.

R. Bruce Northcutt

Certainly, one of the areas, Ben, that we're also focused on is the development of the Pearsall Shale. We've seen some tremendous IPs on some wells out of that part of the play. Certainly, we want to expand and extend our capability to capture those volumes. So that's what our -- obviously, what our commercial teams are working on. But quite honestly, right now, we still got our plate pretty full with what we expect to be pretty significant Eagle Ford volume increases over the next couple of years. So -- and I think that's also what we mean by we're continuing to look for additional growth opportunities and capital programs -- or capital projects that we could work on in the Eagle Ford. It's like this with any play: You -- once you get a position in any given play and a good position where you can provide a lot of different services and more diversified stream, I think that leads to follow-on projects and bolt-on projects that help extend your even further in that play. And the more value-added services that we can provide through our diverse portfolio of services that we do provide in the Eagle Ford Shale, I think that will only give rise to additional projects.


And I am showing no further questions at this time. I would like to turn the call back to management for any closing remarks.

R. Bruce Northcutt

Thanks, everybody, for joining us on the call. Hope to have additional updates on our next call, especially with regards to projects such as the Eagle Ford Gathering -- or excuse me, our 400-million-a-day cryo at Houston Central. So I look forward to visiting with you after the next call. Thank you.


Ladies and gentlemen, this does conclude today's conference call. If you would like to listen to a replay of today's conference, please dial (303) 590-3030 and enter access code 4570334. Thank you for your participation, and you may now disconnect.

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