Executives
S. Jeffrey Johnson – Chairman of the Board & Chief Executive Officer
Benjamin Daitch – Chief Financial Officer & Senior Vice President
Patrick McKinney – Senior Vice President Engineering & Operations
Analysts
Derrick Whitfield – Canaccord Adams
Noel Parks – Ladenburg Thalmann
Can Petroleum, Inc. (CFW) F3Q09 Earnings Call May 12, 2009 11:00 AM ET
Operator
Welcome to the third quarter 2009 Cano Petroleum Incorporated earnings conference call. My name is [Keisha] and I will be your operator for today. At this time all participants are in listen only mode. We will conduct a question and answer session towards the end of this conference. (Operator Instructions) I would now like to turn the call over to Mr. Jeff Johnson, Chairman and CEO of Cano Petroleum.
S. Jeffrey Johnson
The third quarter for Cano was a very good quarter for us and we were able to see responses at our Cato water flood and continue to see good indication of response out of Cockrell Ranch. We were able to see production lift of about 5%, more importantly oil production lift of about 8% quarter-over-quarter and we were able to see that without any new production wells being drilled in about six months, at least since last October.
We continue to see our costs come down. We saw LOE come down from about $44 a barrel to $35 and as we sit here today it is closer to about $33. We anticipate to continue to see that reduce costs end lease operating expenses as we see production lift. We also have seen reduction in G&A, some of which we did start to realize this quarter, some that we’ll start to realize next quarter. But, all in all I feel like with the cost cuts that we’ve implemented, the production responses that our operating team has seen out at Cato that we’ve had a very good quarter.
I do want to reiterate one thing as we go forward, is we’re expecting to see the same thing out of Cockrell Ranch that we have seen at Cato. Cato saw an early response, we’re fortuitous, it had some water that was already in the ground from a prior water flood. We took a lot of things that we learned at Cockrell Ranch and deployed that information and executed the plan at Cato with that knowledge in mind and so we do have tighter spacing, we are in an area where there has been some water full up. So, as we continue to see the Cato production lift and we expand that water flood, we sure anticipate the same type of response out in Cockrell Ranch as we get towards the end of this calendar year.
So, sitting in here with me, I did forget to introduce everybody, I have Ben Daitch, our CFO; I also have Michael Ricketts, our Principal Accounting Officer; and then Patrick McKinney, our Senior VP of Engineering and Operations. With that, I’ll hand it over to Ben to go over the financials.
Benjamin Daitch
For the three months ended March 31, 2009 we incurred net loss applicable to common stock of $1.2 million or loss of $0.03 per share. Last year in the third quarter we reported a net loss applicable to common stock of $1.9 million or a loss of $0.05 per share including $0.02 per share of income from discontinued operations.
For the third quarter our sales were 78,000 barrels of oil versus 68,000 barrels in 2008 and 181 cubic feet of natural gas versus 216 million cubic feet in 2008. On a BOE basis our sales were 108,000 BOE versus 104,000 BOE for 2008. Third quarter production of 1,263 net BOE per day was 5% greater than the prior quarter and 7.2% greater than last year’s third quarter.
Revenue for the third quarter was $3.9 million down 57% compared to $9.2 million for the same period last year. For the current quarter, including realized gains from commodity hedges we received average prices of $62.34 per barrel and $9.64 per MCF of natural gas or $62.50 per BOE. The gas premium is based upon the high BTU content of our gas and the fact that we continue to have more gas hedges in place than our current gas sales as a result of having sold our Pantwist property last year.
For the same period last year including realized gains and losses from commodity hedges, oil prices averaged $87.33 per barrel and natural gas prices averaged $13.21 per MCF, or an average price of $84.53 per BOE. You can find a table with these metrics as well as unhedged realized prices in our Form 10Q that was filed yesterday.
On a production basis LOE for the third quarter fell $8.36 per BOE or 19% to $35.70 per BOE from $44.06 in the second quarter. The second quarter was down from $45.93 in the first quarter of this fiscal year and the peak of over $56 per BOE for the month of October. We continue to realize cost savings from actions implemented during the last two quarters with March LOE at $33.30 per BOE on a produced barrel basis.
Our general and administrative expense was $1.2 million less than the same quarter last year as we are now seeing decreased expenses pertaining to the Panhandle wildfire litigation. As a reminder, we’ve settled all matters related to the Panhandle wildfire except for one lawsuit that is under appeal but we continue to believe all the wildfire lawsuits were without merit. We will continue to seek the most economic route to finalizing this matter.
These G&A decreases were partially offset by increased expenses related to payroll and benefits. We anticipate additional savings in the coming quarters as we reduced our home office staff by 25% during our third quarter. Annualized savings from this reduction should exceed $750,000 per year. Production and ad valorem taxes decreased $300,000 as a function of lower revenues which is partially offset by higher ad valorem tax rates.
Depletion and depreciation expense increased for the yearly quarter-over-quarter period from $1 million or $8.03 per BOE to $1.6 million or $12.35 per BOE. The increase rates were primarily due to higher PPE from capital invested over the year. Net interest expense was $165,000 for the quarter. This figure was reduced by approximately $300,000 as we capitalized interest related to our water flood and ASP projects.
We recorded preferred stock dividends of $477,000 for the quarter ended March 31st versus $877,000 for the prior year. This reduction was due to the retirement of 22.9 million of notional value of our preferred stock during the second quarter of fiscal year 2009. In the current quarter 59% of our preferred stock dividends were payment in kind with the balance paid in cash.
That’s it for earnings, now on to our capital expenditures/liquidity update. As a function of earlier than anticipated increased fluid production at our Cato and Panhandle properties, we’ve increased our current year development capital expenditure budget from $38.5 million to $49.8 million. Details of how this capital is being deployed and what we expect to achieve through these expenditures will be discussed by Pat McKinney.
The initial and current borrowing base under our revolver is $60 million. The borrowing base is due to be redetermined based upon the value of our proven reserves at May 1st and again at June 30th. We will be beginning the reserve review process this week. As of May 10th, we had $32.2 million borrowed under our first lien with $27.8 million of availability remaining. We drew down the $15 million of availability under our subordinated loan on March 17, 2009 and used the proceeds to reduce borrowings under our revolver.
On January 13, 2009 we entered in to a three year LIBOR interest rate swap agreement for $20 million and notional exposure at a fixed rate of 1.73%. We’ve agreed to settlements regarding all the lawsuits related to the wildfires that began on March 12th in Carlson County, Texas other than the Burnett appeal. These settlements to date have been paid out as settlements with our insurance carrier, a third party electricians insurance carrier, the prior owners of WO operating and cash on hand.
With that, I’ll hand it off to Pat McKinney to provide an operations update.
Patrick McKinney
As was mentioned in our last two quarterly press releases our goal for the remainder of our fiscal year 2009 was to maintain first quarter production levels at over 1,200 BOE per day for the remainder of the fiscal year, while only spending within our operating cash flow until we see production lift coming from our prior investments in our Panhandle and Cato water flood projects.
In our fiscal year third quarter we experienced significant production lift from our Cato unit water flood and increasing oil and fluid production amounts at our Cockrell Ranch unit water flood. Subsequently we increased capital spending to support the responses of both Cato and at the Cockrell Ranch unit. Production in our second quarter fiscal year 2009 averaged 1,264 BOE per day, this is up 5.1% sequentially from our fiscal year second quarter average production of 1,203 BOE per day. Year-to-date production has averaged 1,233 BOE per day, up 10.3% from the 1,018 BOE per day in the first three quarters of fiscal year 2008.
We achieved this increased production rate without the benefit of any production related drilling activity. This ability is a unique aspect of our business model. Oil production which increased 12% was the biggest driver of our year-on-year quarterly growth and grew 21% for the first nine months over nine months of the year. The majority of this oil production growth occurred at the Cato field.
The sustained gains at the Cato unit are the result of an earlier than expected water flood production response. Since the injection permits were received in September of 2008, direct water flood production response has grown from five infield producers directly offsetting prior Amoco pilot injection wells in December to 20 pattern producers seeing direct response. We completed the fiscal year 2009 drilling program at Cato in early October of 2008.
Normal production declines were experienced outside of the water flooded area but these declines were more than offset by water flood production responses experienced during the third quarter. As stated in our second quarter conference call, Cato’s January 2009 exit rate production was over 300 BOE per day. Cato exited April, 2009 at approximately 380 net BOE per day. We estimate that water flood production responses in excess of 230 net BOE per day.
Moreover, seven additional producing wells are in the first stages of water flood response with work overs planned to increase production at these wells in the near term. I will talk more about the Cato water flood response in the operational update section.
Given more color on our capital development, in the third quarter we revised our capital development budget from $38.5 million to $49.8 million. The new full year capital allocations are being increased to $49.8 million as follows: Cato properties up $5.9 million from $20.5 million to $26.4 million; Panhandle properties up $4.4 million from $13 million to $17.4 million; all of our other properties are up $1 million from $5 million to $6 million. The $11.3 million increase in capital budget is a direct result of Cato and Panhandle water flood responses.
At Cato our incremental water flood production response of over 7,000 barrels per day of fluid necessitated adding additional injection wells and facilities to balance our injection withdrawal. Regulatory limits on injection pressure required us to add four new injection wells to the flood pattern. These prior producing well conversions required running liners, adding additional injection plaque capacity. Increased fluid production response also required additional sub-pumps and electrical infrastructure additions. A total of six new sub-pumps were added in the quarter to make a total of 10 running in the field.
At the Cockrell Ranch unit we increased our daily injection capacity by over 20,000 barrels per day and increased our fluid production by over 5,000 barrels per day. This required additional capital for sub-pumps, fluid handling and chemical treatment costs. Eight new sub-pumps were added in the quarter bringing the total in the field to 26. We feel that with the increased capital spending in the third quarter we now have the necessary plant and infrastructure capacity at both Cato and Cockrell Ranch to handle near term production fluctuations much more effectively.
We have completed the drilling program for fiscal year 2009. Our fiscal year 2009 drilling development program results in the drilling of 18 new wells for the full year. This included four ASP operation wells at Nowata, five Harvey Unit mini flood replacement injectors in the Panhandle field, one Cockrell Ranch observation well also in the Panhandle field and eight water flood development wells at Cato. We anticipate approximately $5 million of maintenance capital spending for the remainder of the fiscal year, as we mentioned above, albeit a lower rate than we experienced in the third quarter as we continue to manage the responses at our two major water flood projects.
Going on to the specific field updates, at Panhandle during the third quarter we increased our average daily water injection rate at the Cockrell Ranch unit from roughly 50,000 barrels per day to over 70,000 barrels per day. Additionally, total fluid production increased 5,000 barrels per day to close to 25,000 barrels per day in total. To handle this increase we added eight additional sub-pumps in the quarter bringing the total at Cockrell Ranch to 26. This resulted in increase in our average daily production from 100 to 120 net BOE per day up from the initial base production response at the Cockrell Ranch unit water flood of approximately 80 to 100 net BOE per day between June and December of 2008.
We previously have taken actions to correct injection in the prior quarters as a result of our ongoing surveillance program. We identified injectivity issues in 16 of the 62 injection wells. This work was completed in September of 2008. With the results of the surveillance and the corrective actions taken, coupled with the increase in daily average injection, we now estimate the effective pore volume injection or PVI at the Cockrell Ranch unit to be approximately .28.
As a reminder, we are still early in the life of this water flood and the surveillance measures we have taken and the initial results at the Cockrell Ranch unit are normal. The Cockrell water flood has been at full injection at 13 months with corrected injection profiles since last October. We are pleased with the increase in [inaudible] pressures and in injection withdrawal rates in certain areas of the field. Of note there are areas of the flood that are responding favorably with producing oil cuts between 4% and 10%. This latest increase in injection volume should allow us to see direct correlation with pore volume injected versus corresponding oil production.
As discussed during the second quarter conference call, the current capital development plan in the Panhandle provided for the development of only one mini flood this fiscal year. The Harvey Ranch unit had its water flood permit application approved by the Texas Railroad Commission on October 20, 2008. The Harvey unit mini flood consists of six injection wells and 13 producers. Drilling of the mini flood pattern was completed in January 2009. We initiated injection at the Harvey unit on March 30, 2009 at a rate of 2,500 barrels of fluid injected per day.
We have filed mini flood permits for the Pond and the Olive Cooper leases. Pond lease permit is set for hearing in June while the Olive Copper permit is under administrative review. We slowed the pace of the mini flood permitting as the result of reducing our development capital plans for the year and with the extra attention warranted at Cato field due to its early water flood response. We expect to file appropriate water flood permits for the remaining three mini floods within the next 90 days. Net production at the Panhandle properties for March, 2009 was approximately 600 BOE per day.
At Cato, as previously discussed, we’ve seen a very encouraging initial water flood response. We currently have 19 water injection wells online and 29 producing wells in Phase I of the Cato unit water flood pattern. As of January, 2009 we established injection at a rate of approximately 12,000 barrels of water per day. As a result of the current capital expenditure forecast at Cato, this initial phase of the Cato water flood has now been increased from roughly 550 acres to 640 acres.
We have a total of 10 sub-pumps running with another seven planned due to increasing pattern responses and corresponding high fluid levels. These actions could increase fluid production by up to 4,000 barrels of fluid per day. This would bring total daily fluid production and associated injection rates to approximately 16,000 barrels of fluid per day. Net production for March, 2009 at the Cato properties was approximately 380 net BOE per day.
At Desdemona, due to falling commodity prices particularly natural gas, last quarter we shut in four uneconomic horizontal Barnett Shale wells and four uneconomic vertical Barnett Shale Marble Falls producers. In conjunction with these shut ins we took the appropriate steps to more than half our LOE at the field. We continue to water flood the Duke Sands reservoir, a zone above the Barnett Shale albeit at a much slower pace when we shut in Barnett Shale wells and loss the major source of our fluid for injection.
While we do not expect to see meaningful response from the Duke Sands water flood during the 2009 calendar year, we still view this project as viable with a large probably reserve upside. Net production for March, 2009 at the Desdemona properties was 40 net BOE per day.
At Nowata, our alkaline-surfactant-polymer or ASP tertiary recovery pilot project which has been in full operation since December of 2007 has injected close to .20 PVI of ASP. We now have completed the ASP stage of injection and are performing the final injection stage of polymer flush with injection close to .15 PVI. We have finished drilling completing four observation wells and they continue to be tested. The observation wells should allow us to test flood front results in our ASP.
Our plans are to continue to inject polymer flush for an additional two to three months. We will announce any updates at Nowata once we have definitive results. Net production for March, 2009 at the Nowata properties was approximately 240 BOE per day.
Shifting to lease operating expense, in the second quarter of our fiscal year we implemented LOE cost reduction initiatives that we’ll realize in our third fiscal quarter. During the third quarter we had three full months of reduced pulling expenses as a result of our successfully renegotiated pulling unit contract at the Panhandle field where the bulk of our LOE is incurred. Further actions taken at all our other fields during the second quarter produced savings during the third quarter compared to the first two quarters of the year.
We saw LOE on a produced BOE basis drop from $46.84 in the first quarter to $44.06 in the second quarter and finally to $35.71 in the third quarter. This is a19% sequential drop from the second quarter and 24% from the first quarter. As discussed, on our second quarter earnings call roughly every 100 net BOE per day of production lift should reduce LOE by approximately $2 per BOE. Whether or not we can go much below $30 per BOE in the near term will depend on the rate of production lift, changes in service costs and movements in electricity prices.
With that, I’d like to turn the call back over to Jeff for some closing remarks.
S. Jeffrey Johnson
We’ll go ahead and at this time just open it up and take any questions from anybody.
Question-and-Answer Session
Operator
(Operator Instructions) Your first question comes from Derrick Whitfield – Canaccord Adams.
Derrick Whitfield – Canaccord Adams
Thinking about your Cato project, at year end you guys booked about 13 million of proved reserves, with the performance you’re seeing now with this north of P50 case, any chance you guys could see any upward revisions there?
S. Jeffrey Johnson
We’re not going to really take a look at that real hard until June 30th. That’s when we’re going to rack it up. But, to your point we have been pleasantly surprised with parts of the Cato flood, well actually all of it so far and some of the wells have outperformed what we have booked as PUDs but again, we want to reiterate, it’s early we want to really watch the production, monitor it and when we do get to June 30 we’ll definitely be taking a look at not only conversion of PUD but obviously taking a look at any other conversions that we might be able to get due to the response rate.
Derrick Whitfield – Canaccord Adams
That would carry over to your offsetting patterns correct?
S. Jeffrey Johnson
Well, I mean it’s going to depend. I’ll let Pat talk about it a little bit but, as you go through the reservoir you would think, it’s pretty consistent, you would think you’d continue to see the same type of response we’d get up there. Pat, do you want to talk about that?
Patrick McKinney
When we go in and look at the PUDs out there, we were pretty conservative. Obviously, if we’re able to take up reserves from our current exposure out there, obviously the entire field would get some lift potentially in converting probably barrels over. So, we just view this as a very positive sign right now and we’ll get with our third party engineers in June and take a look at it but we’re really pleased with where we’re at right now.
Derrick Whitfield – Canaccord Adams
A question for you on the Harvey unit, I saw in your Q that you guys mentioned an injection profile of 2,500 barrels of water per day. Where do you think that final injection profile might land? And, if I were doing a back down look calculation for production could I assume full production at about 50% of injection and say [inaudible] in the 1% to 5% range?
Patrick McKinney
Well, I think we’re starting off at a little lower injection rate up there just to kind of get a feel for the injectivity profiles at each of the wells and we hopefully are going to have some lessons learned from Cockrell Ranch. When we get in to looking at production response time I’ll let Jeff answer that who’s got a pretty strong opinion of it.
S. Jeffrey Johnson
One thing I can promise you that we’ve done – some of the things we haven’t done really well is try to predict the response to these water floods and we’re not going to try and do that here. But, we do think we will see a good response, it’s in a good area. To come out right now and try and tell you what we’re trying to predict as far as oil cuts or rates I can promise you whatever I told you, I’d be wrong. So, I really just don’t want to do that but we will keep everybody up to speed as we continue to inject and get more water in the ground up in the Panhandle.
Derrick Whitfield – Canaccord Adams
For the balance of the calendar year 2009 you guys are roughly $2 million for the third quarter or first quarter calendar, do you think you guys can hold about that level for the balance of the year?
Benjamin Daitch
I’s day that our run rate will be somewhere in the – cash run rate is about $750 to $800 per month is more accurate. We had some settlements inside our G&A in this current quarter so our cash run rate is about $750 to $800 a month.
Operator
Your next question comes from Noel Parks – Ladenburg Thalmann.
Noel Parks – Ladenburg Thalmann
A couple of things I wanted to run by you, if you look at say you finish out the fiscal year and you look ahead and look at your capital, I’m just trying to get a sense of how you think you might go about the setting up of your next water flood, whether that’s at Harvey or another part of Cato? I think that one thing I’ve heard you guys comment on is that you have been putting sort of more emphasis upfront in to the facilities work ahead of maybe the injection work or the drilling work in the new fields. I’m just wondering as far as being able to hang on to your capital and use it the best you can, is that something you’re going to continue to do going forward or are there some considerations that are going to force you to go back to the way you started doing it at Cockrell Ranch?
Patrick McKinney
I think the whole idea for looking at the mini phases out at Panhandle was from some of the lessons learned at Cockrell Ranch where it’s a lot easier to go in after you’ve got a successful response or you really have a better idea of what the reservoirs going to do and then have the infrastructure and facilities coming behind it. I think that we did that at Cato, we got the response and now it’s a lot easier to size facilities to go in behind it.
I think when looking at our capital going forward, obviously we’ve got a successful project at Cato and so we’re going to try and build off that. We’re still a little bit early to really look at capital for next year but I can tell you that most of our effort right now is looking at how we can maximize Cato in the near term.
S. Jeffrey Johnson
We’re going to be sitting down with our banks, our senior lenders here over the next few days and talking to them and so big driver behind all of this is going to be the amount of liquidity that is available and obviously production lift. That’s what’s going to drive that. We’re pleased with what we’ve seen but we need to sit down with the banks, talk to them, go over two or three different capital budget plans we have and then plan accordingly.
But, I guess to get back to the real simple answer to it is wherever we see responses, wherever we go put capital and see a return on that capital, that’s where we’re going to continue to put capital. Our job is to manage that within our cash flow and within the available credit facilities and just make sure that we’re doing that prudently and I think this quarter we’ll really turn the quarter on getting that done. Pat and his team, I want to commend them for that.
Noel Parks – Ladenburg Thalmann
Can you talk a little bit more about what has gone in to the improvement in the oil uplift at Cockrell Ranch? I’m thinking about a number months ago in your work you discovered that I think the upper portion of the Dolomite wasn’t really getting the water, it was going to I guess a more depleted zone of the field. Is the improvement at Cockrell Ranch related specifically to turning the corner on that or something else that is going on in the field?
Patrick McKinney
I think as we’ve mentioned on prior calls we needed to really focus our injection in to the areas that had the high Dolomite that had the highest remitting oil saturations and we feel that we’re starting to do that. As we go on we’re going to continue to optimize where we place the water and what we do and getting additional injection capacity has really helped us do that. So, we feel we’re on a really good path right now to get the water where it needs to be.
Noel Parks – Ladenburg Thalmann
Do you have a lot more of additional work to do as far as drilling surveillance wells and so forth or do you have about as much of that in the field that you need to understand where it’s going right now?
Patrick McKinney
We’ve done a lot of work here in the last couple of months really trying to go through and detail in a lot more precise form the geologic considerations at the Cockrell Ranch and we feel that we’ve got a lot better insight now of what’s going on in the reservoir and what we need to do. So, in a normal surveillance program you’re always going to be trying to optimize that on a pattern-by-pattern basis of where you put your water and how you focus your injections.
So yes, we’ll continue to carry out our surveillance plan and there’s not going to be a lot of really capital expenditures to talk about, it’s just more day-to-day of just making sure the wells are pumped down, making sure the injections going in at the right intervals and it’s pretty much a day-to-day operation out there to continue to enhance that injection profile.
Noel Parks – Ladenburg Thalmann
Just my last question, you made the comment naturally that the bulk of your LOE is at Panhandle, I’m just thinking about with all the decline we’ve seen I guess really across most of the country in service costs, how are the operating costs of the water floods themselves trending these days? I don’t know if it’s primarily electricity or on the disposal side or anything like that, or the water injection side, I’m wondering how that’s looking?
Patrick McKinney
Well, as Ben had mentioned on this call, once you get a water flood up you pretty much have a fixed cost with it. You’re injecting and lifting like at Cato the same amount we inject we lift. So obviously, your electricity costs come in to play and chemical costs and we’re looking at some initiatives with how we can try and reduce electricity costs. We’re definitely looking at initiatives to decrease chemical costs and we still feel pretty good that steady state our water flood lifting costs are going to be under $15 per barrel steady state when we get up, and they’ll go below that when we see lift. But, we’re working really hard to try and get a good baseline of those costs out there and obviously, you’ve seen some of that in the LOE the last couple of months where we’re really trying to work to get the costs we can control, really get them down.
Operator
With no further questions in the queue I would now like to turn the call back over to Mr. Jeff Johnson, Chairman and CEO of Cano Petroleum for closing remarks.
S. Jeffrey Johnson
Again, thanks everybody for joining us on the call today. I thought this was a very good quarter from both operational perspective as well as financial perspective with some cost cuttings and being able to deploy the capital in the manner that we have. I appreciate everyone joining us today and we’ll talk to you with our next call. Thank you.
Operator
Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a great day.
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