Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Benjamin Hulburt – President and Chief Executive Officer

Thomas Stabley - Executive Vice President and Chief Financial Officer

William Ottaviani - Chief Operating Officer

Analysts

Leo Mariani - RBC

Ron Mills - Johnson Rice

Jack Aydin – Keybanc Capital Markets

Jeff Hayden - Rodman & Renshaw

Marshall Carver – Capital One

Analyst - Natixis Bleichroeder

Rex Energy Corporation (REXX) Q4 2008 Earnings Call March 6, 2009 10:30 AM ET

Operator

Good morning and welcome to Rex Energy Corporation’s fourth quarter and year end 2008 financial results conference call. I will be your coordinator for today. At this time all participants are in a listen-only mode. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. We will conduct the question-and-answer session towards the end of this conference. As a reminder, this conference will be recorded for replay purposes.

I would now like to turn the call over to Mr. Benjamin Hulburt, President and Chief Executive Officer of Rex Energy Corporation.

Benjamin Hulburt

Good morning everyone and thanks for joining us on this morning’s call. This morning Rex Energy announced results for what I believe to be a tremendous year of growth for the company evidenced by record highs in our revenues, production, EBITDAX and cash flows from operations during the year.

First and foremost I want to continue to stress the financial stability of Rex Energy. At year end we had $7 million of cash on hand and only $15 million in debt. Our financial stability is further enhanced through our aggressive hedging position with over 86% of our current production hedged through the end of 2010 at very favorable prices. Our line of credit remains intact with a borrowing base, after the reduction from the planned sale of our Permian Basin assets, at $80 million. Lastly, we anticipate bringing in approximately $17 million in cash proceeds from the sale of our Permian Basin assets by the end of the first quarter.

Despite our strong financial liquidity position we have, and may continue to, cut back capital spending in 2009 as needed due to the energy crisis in order to preserve the integrity of our balance sheet and the value of our assets in the ground.

I would like to take a moment to review a very strong year just completed. We generated EBITDAX of $29.1 million, an increase of 32% over 2007. Production increased 5% to 949,000 barrels of oil equivalent. This growth in production was achieved despite delays in our drilling program in the Illinois basin due to record levels of flooding during the first half of the year and delays in our Marcellus Shale drilling program due to the challenging regulatory and well permitting environment in Pennsylvania we experienced during the year.

Our December 2008 production exit rate of 2,809 barrels of oil equivalent was 13% higher than our December 2007 exit rate. We were obviously disappointed in our year-end crude reserves which declined approximately 22% to 11 million barrels of oil equivalent. This was predominately due to a very significant decrease in year-end oil prices. Despite the declines in commodity prices I was very pleased with our management’s ability to increase our Appalachian Basin crude reserves by 142%.

In order to assess our management effectiveness over the year as it pertains to reserves we estimated what our hypothetical reserves would have been if we held commodity prices constant; so a commodity price neutral assessment. Using this assumption wherein we estimated 2008 reserves at the same commodity price level we did in 2007 in our crude reserves would have grown approximately 19% to 16.7 million barrels of oil equivalent, producing a 376% reserve replacement ratio and F&D costs of about $12.77 per BOE.

Operationally in 2008 we drilled and completed 58 net wells and achieved 100% success rate. We increased our Marcellus Shale fairway acreage by 107% to approximately 62,000 net acres. We successfully completed at least one vertical test well in each of our core Marcellus operating regions with encouraging results. We recently completed and put into production our third vertical well in southwestern Pennsylvania and are pleased to report that the well tested at a peak rate of 1.8 million cubic feet per day and an average rate of 1.4 million cubic feet per day over a 24 hour period.

We commenced chemical injection in our two ASP pilots in the Lawrence Field which, as Bill will discuss momentarily, showed some very encouraging indications of the potential of the ASP flooding in the Lawrence Field.

While we are proud of our operating accomplishments this past year we recognize the historic challenges represented by persistent low prices and tight credit related to the recession we are in. I would like to address investor concerns about the industry as they may relate to Rex Energy and how we plan to navigate through the challenges and opportunities we see in this downturn.

First, as I discussed, the integrity of our balance sheet is critical to our ability to grow and create value. Throughout the upturn in energy prices while the use of leverage was prevalent in the industry we managed our balance sheet conservatively in order to ensure that we would be positioned to endure when the inevitable downturn in commodity prices arrived. I believe we have done this successfully and are well positioned now in this tough environment.

Additionally, as previously discussed we made the decision last year to divest our assets in the Permian Basin and were successful in executing an agreement to divest those assets despite the challenging environment. We expect that transaction to close during the first quarter of 2009 and provide net cash proceeds of approximately $17 million making the company essentially debt free at that time. The decision to divest these assets was made for two reasons. First, to provide increased liquidity and secondly to enable our management team to better concentrate their focus on our Illinois and Appalachian Basin assets where we see the greatest opportunity for the company.

On the spending side we have significantly reduced our CapEx budget in 2009 down to $49 million and may continue to make further cuts in the event we do not see a rebound in oil prices in the second half of the year. Our capital budget as it stands now allocates approximately 70% towards our Marcellus Shale projects and 30% towards our ASP projects in the Illinois Basin. The portion of our capital budget allocated to the ASP projects in the Illinois Basin is heavily weighted towards the second half of the year and we will evaluate the environment at that time to determine whether these expenditures are delayed into 2010. Since we operate virtually all of our properties we have flexibility on making decisions on the timing of our capital expenditures.

In the third quarter we began taking several measures designed to reduce operating expenses as well. I am pleased to say these measures have already resulted in lease operating expenses falling by approximately $250,000 per month and in the fourth quarter were evidenced by a drop in lease operating expenses of $1.5 million from the previous quarter. These strategic cost saving measures have continued to show positive results in the first quarter of 2009.

In summary, I believe that Rex Energy is superbly positioned both financially and operationally to continue to grow in a challenging environment. We will continue to aggressively manage our balance sheet in order to ensure that Rex Energy not only endures but is positioned to excel when the inevitable rebound arrives.

With that I will turn the call over to Bill Ottaviani, our Chief Operating Officer, for an operational review.

William Ottaviani

Thanks Ben. I will begin by first reviewing production for our ongoing operations. In 2008 our net production grew by more than 5% thanks in part to our initial production from our Marcellus Shale production program in our Appalachian region and active drilling campaign in our Illinois Basin operations. We realized this production gain despite unusually severe flooding in the Illinois Basin that forced production curtailment from our ongoing operations and delayed the start of our planned new well development.

While flooding of this magnitude is rare we have taken a number of steps to mitigate the potential for production impacts due to any future flooding in the basin. I am pleased to note that following this initial set back due to mother nature we recovered quickly and production steadily rose throughout the year with a fourth quarter production increase of 3.5% over the third quarter.

On a barrel of oil equivalent basis we closed out the fourth quarter of 2008 with a production mix of 82% oil and 18% natural gas.

In terms of lease operating expenses we, along with the rest of the oil and gas industry, were affected by general increase in the costs of goods and services that peaked in the third quarter and finally began to diminish in the fourth quarter. For 2008 our lease operating expenses increased about 18.6% compared to prior year levels. We also temporarily increased our baseline activity levels for select maintenance, repair and well work across many of our operational areas to take advantage of favorable profit margin since mid-year. This too added to our overall increased costs for the year.

We have since scaled back this work as commodity prices began to fall but due to the increased work we did during the year we have positioned ourselves well to withstand a prolonged period of low prices without the need for higher operational costs to sustain production. As Ben alluded to earlier our operational costs steadily dropped through the fourth quarter with December’s costs being our lowest for the year.

These costs have continued to trend downward into 2009 as we establish an operational activity baseline commensurate with lower commodity prices.

Now let me turn my attention to our two major projects and give you an update on their progress for the year and our plans for 2009. Let me start with our alkali surfactant polymer, or ASP, flood project we have out in the Illinois Basin in our Lawrence Field. As previously reported we set out to test the ASP process in two small pilot areas, one testing the Cypress formation and one testing the Bridgeport formation.

During 2008 we achieved a number of notable milestones in this project including completion of our chemical injection plant, initiation of first chemical injection and indication of first production response from each pilot area. During the fourth quarter of last year we expected to see peak production response from each pilot based on the operational and technical assumptions used in the design of each pilot. Following a detailed assessment of all data collected during this pilot phase we now believe that peak production rates were achieved in the fourth quarter but not to the levels expected.

On the surface this may seem to be a wholly undesirable outcome but our analysis has given us much reason to be optimistic about this project going forward. So let me explain. First and foremost the pilot’s confirmed that the ASP process works for our reservoirs as incremental oil, not recoverable through conventional techniques like water flooding, was produced from each pilot. Obviously this proof of concept was a significant milestone for our pilots and one that we are quite pleased to have successfully achieved.

When production was not reaching the levels anticipated our technical team’s thoroughly dissected field collected data against the design criteria and base assumptions used for each pilot and came to some surprising conclusions. For our Cypress pilot we determined the reservoir contained a few sub-layers of high quality rock that tended to cause most of the injected fluid to pass through these better quality layers and bypass the other layers. So the good news here is that we have rock quality that is better than expected. On the downside, this portion of the reservoir acted like a siphon to all of our injected ASP chemicals. The result of this effect is a less efficient sweep of the ASP flood in the Cypress reservoir and less incremental oil produced.

Although we did successfully increase oil production in pilot from two barrels per day to a peak of about 28 barrels per day we ultimately have only produced about 15-20% of the oil volume we originally expected due in part to this phenomenon. Now that the Cypress pilot is in its final stage of polymer only injection we have actually seen an increase in both oil production and oil cut which may suggest the efficiency can be improved through the use of polymer conformance gels. More on this point later.

For our Bridgeport pilot, the data suggests that we did have an efficient sweep of rock layers with our ASP chemicals and therefore produced a large percentage of the recoverable oil in the pilot area. In the Bridgeport pilot we successfully increased oil production from about one barrel a day to a peak of about 65 barrels per day. However, the volume of oil produced was lower than originally predicted because we now believe the amount of potential oil to be recovered was lower than projected. Allow me to explain.

Back in the 1980’s Marathon had performed a surfactant polymer flood pilot in a portion of the Lawrence Field that is near the location of our Bridgeport pilot. This Marathon flood proved to be highly effective in recovering incremental oil from the Bridgeport Reservoir. In fact it was results from this earlier surfactant polymer flood that got us interested in doing our own modern day ASP flood in the field.

Well, the Marathon flood was so successful we now have evidence to suggest that its effect extended outside the original pilot area and actually swept oil from our own Bridgeport pilot area. As such, our target volume of recoverable oil in the pilot area was much smaller than anticipated. Based on our initial assumptions the Bridgeport ASP pilot recovered only 10-15% of the oil volume expected. However, with the smaller oil volume target based on the most recent analysis we estimate that our actual recovery was up to 75% of the residual oil available which is certainly an encouraging outcome. This effect from the earlier Marathon pilot is not expected to have impacted a large portion of the field and therefore should not be a consideration going forward.

In summary, the pilots did their job by providing us with valuable insight into the design and performance factors for expansion of this project on a field-wide basis. So where do we go from here? First our technical team is developing a plan that addresses the injection issues we saw in the Cypress pilot. We believe the use of a conformance gel will allow us to more efficiently sweep the Cypress Reservoir and optimize recovery.

Our tentative plan at this time is to go back into the Cypress pilot with these performance gel products and assess their performance which should be relatively inexpensive. For the Bridgeport Reservoir our pilot results confirmed the need for further evaluation of reservoir oil saturation levels and simulation modeling to ensure optimal project design. This detailed analytical work is underway for both reservoirs.

During 2008 we and our consultants Netherland, Sewell & Associates, constructed a detailed, three dimensional model using thousands of logs taken from the field. Using this model we have already identified 18 separate high graded reservoir units or POD’s which result in 27 potential future ASP floods in the northern and central portions of the field with an estimated 40 million barrels in potential recoverable oil reserves from the ASP process. Analysis of the southern portion of the field will continue during 2009.

How and when we proceed in the actual development of the POD’s will be largely dictated by project economics and the anticipated commodity price over the life of the product. It is important to note that short-term commodity pricing is not relevant in this type of project economics since the oil to be recovered from this project is one to several years in the future. Unfortunately our 2008 year-end SEC pricing for evaluating reserves was $41 per barrel which did not allow us to book any crude reserves for this project.

So we believe that with some additional field testing of the Cypress pilot and continuation of our technical analysis of both pilots’ field data we will have greater clarity on the issues that affected our pilot performance and be poised to begin our development of our first full sized unit.

Given the current economic conditions and our desire to maintain a conservative balance sheet, drilling for this first unit of development will probably not occur until early next year unless we see a rebound in oil prices above $50 per barrel before that time.

Now I would like to update you on our other large project, the Marcellus Shale development in our Appalachian Basin region. Last year was an exciting time for us as we drilled our first vertical test well in the Marcellus Shale and began the sale of our first produced gas. In all of 2008 we drilled or participated in seven net vertical wells across Pennsylvania in three distinct operational areas. By year-end we had four wells going into sales with the remainder pending completion and infrastructure availability.

For our size and given the myriad of regulatory and infrastructure issues affecting Marcellus Shale operators across the state we are quite pleased with how we ended the year and positioned ourselves for a 2009 drilling campaign. As Ben noted earlier our latest vertical well completion from our southwest Pennsylvania operational area yielded our best results yet with an initial rate of 1.8 million cubic feet per day and an average rate of 1.4 million cubic feet over a 24 hour period.

This kind of improved result in only our fifth well brought to production to date is a testimony to the diligent and focused efforts by our technical and operational teams out of the Appalachian region. As a side note, I realize there are higher flow rates being reported from the Marcellus Shale wells but in a fair comparison it is important to consider our relative size and the number and location of wells we have drilled so far. I can say with confidence that we have rapidly moved up the learning curve in 2008 and while there is always more learning to do we are now well positioned to enter a phase of significant growth in our Marcellus Shale development program.

With that said let me tell you about our plans for 2009. Firstly, we have under contract a new built for purpose rig capable of drilling horizontal wells to the deepest known depths of the Marcellus Shale and our operational areas. Fabrication of this rig is near completion and we expect to [spud] our first well of the 2009 campaign by the end of this month.

For the remainder of the year we anticipate drilling 6-8 net wells all or mostly all to be horizontal wells with multiple stage, hydraulic frac completions. We are currently building our inventory of well targets which includes a portfolio of both horizontal and vertical wells. Our desire is to exclusively drill horizontal wells but due to unitization, topographical and other factors a limited number of vertical wells may be necessary from time to time to fill out an acreage block.

In support of this new well program we are actively building our pipeline and gas processing and sales infrastructure which includes a new gas processing facility in our western Pennsylvania operating area and the addition of new gas sales tap sites in both our central and southwestern Pennsylvania operating areas. Initially we will focus our drilling program on those areas where existing gas infrastructure allows for the immediate sale of gas and then we will expand our drilling to those areas where our gas and structured projects will be completed later in the year.

In summary, we feel very good about our situation and prospects for significant production and reserves growth in the Marcellus Shale this year. We now have in place a highly capable technical and operations team, we have taken the necessary steps to upgrade and expand our existing infrastructure, we have gained invaluable knowledge from our early Marcellus test wells drilled last year and our portfolio of new well prospects continues to grow. Stay tuned there is more good news to come.

Benjamin Hulburt

Thanks Bill. Now I’ll turn the call over to Tom Stabley, our Chief Financial Officer.

Tom Stabley

Thank you. Before I get started I would like to remind you that this morning’s earning release posted on Rex Energy’s website posts financial statements, supplemental tables and non-GAAP reconciliations which I encourage you to review if you haven’t already.

Revenues of $68 million for the year ended December 31, 2008 represented an increase of 31% when compared to 2007. This increase in revenue was the result of increased production which grew by 5% and increased average realized sales price after the effects of hedging which grew by 24%.

Our revenue in the fourth quarter of 2008 increased 2% when compared to the fourth quarter of 2007 to $14.8 million. This increase is attributable to our production growth of 5% and partially offset by a 3% decrease in our average realized sale price after the effects of hedging. We incurred a net loss from continuing operations of approximately $41 million in 2008 and a net loss from continuing operations of approximately $32.6 million for the fourth quarter of 2008.

During the fourth quarter of 2008 it was determined that the carrying value of some of our properties exceeded their fair value which was the direct result of a compressed year-end commodity price. In accordance with statement of financial accounting standards 144 we recorded $38.6 million non-cash expense related to the impairment of certain oil and natural gas properties.

Additionally, we performed our annual tests for goodwill impairment during the fourth quarter. This test involved comparing the goodwill carrying value to its fair value. It was determined during our testing that our goodwill was fully impaired and we incurred an additional $32.7 million of non-cash impairment expenses.

Other non-cash items that significantly affected our net loss included DD&A non-cash compensation and loss on sale of assets. DD&A which increased by $20.1 million or 113% when compared to 2007 was primarily a result of the downward revisions of our proved reserves due predominately to low oil prices. We calculated our depletion on a units-in-production basis which accelerated in relation to our lower proved reserve base. At current proved reserve levels we anticipate that DD&A rates will average approximately $27 per BOE in 2009.

Our non-cash compensation expenses which are reported as part of our G&A increased from 2007 by approximately $2.8 million to $3 million in 2008. Of the $3 million in non-cash compensation expense incurred during the year approximately $1.1 million was due to the cancellation of 100,000 stock options by our board of directors which was done voluntarily to contribute to the reduction of expenses in 2009. The remainder of the increase can be attributed to the fact there our long-term incentive plans under which these non-cash expenses are incurred did not exist prior to November 2007. As such, we incurred 12 months of non-cash compensation in 2008 as compared to only two months in 2007.

During 2008 we sold approximately 79,000 net undeveloped acres in Indiana and certain related non-producing wells which was part of our New Albany Shale exploration project for approximately $8.4 million in proceeds. Due to this sale we reported a loss on the sale of assets of approximately $6.3 million. Partially offsetting the previously mentioned non-cash expenses was a $43.7 million unrealized gain on oil and gas natural derivatives. This gain reflects the change in the estimated fair market value of our outstanding collar and swap derivative positions as of year end.

Our EBITDAX from continuing operations for 2008 was approximately $29.1 million as compared to $22.1 million in 2007 representing a 32% increase. Our EBITDAX from continuing operations in the fourth quarter of 2008 decreased approximately 10% to $5.7 million from $6.3 million in the fourth quarter of 2007.

Loss from continuing operations comparable with analyst estimates was $9.8 million for 2008 as compared by a loss of $1.4 million in 2007. For the fourth quarter of 2008 loss from continuing operations comparable with analyst estimates was $18.1 million compared to a gain of approximately $448,000 during the fourth quarter of 2007. These losses incurred during the year can be primarily attributed to, as mentioned before, the increase in DD&A rates which were a result in the downward revision in our proved reserves.

Operating expenses increased approximately $4.2 million or 18.6% in 2008 from 2007 to $26.5 million. Lease operating expenses during the fourth quarter of 2008 increased approximately $654,000 or 12% from the fourth quarter of 2007 to $6.1 million. The increase in production and lease operating expenses can be partially attributed to the higher costs for durable goods throughout the oil and natural gas industry for items such as steel, chemicals and electricity as well as an increase in service costs. Also contributing to the higher expenses was the growth in our productive well count which increased by a total of 23 net wells.

General and administration expenses increased by approximately $7.4 million to $15.2 million in 2008 from $7.8 million in 2007. During the fourth quarter of 2008 G&A expenses increased by approximately $1.4 million as compared to the fourth quarter 2007 to $4.3 million. These increases in expenses resulted from increased costs associated with consulting fees related to compliance with Sarbanes Oxley and additional staffing needs in relation to our growth. Also as mentioned previous non-cash compensation which is reported as a G&A expense increased by $2.8 million compared to 2007.

We reported exploration expenses in 2008 of approximately $3.3 million as compared to $1.2 million in 2007 and during the fourth quarter of 2008 we reported exploration expenses of approximately $866,000 compared to an expense of $1.2 million in the fourth quarter of 2007. These increases in expenses for the full year of 2008 can be attributed to geologic modeling in our large scale ASP project and geophysical evaluation and modeling associated with our Marcellus Shale activities.

During 2008 we reported interest expense net of interest income of approximately $1 million as compared to $5.6 million in 2007. During the fourth quarter of 2008 we reported interest expense net of interest income of approximately $308,000 as compared to $349,000 during the fourth quarter of 2007. These decreases in interest expense are directly attributable to the decrease in the average balance on our long-term debt lines and other loan notes payable.

We reported a tax benefit from continuing operations of approximately $9.2 million and $3.4 million for 2008 and the fourth quarter of 2008 respectively. This compares to a tax benefit from continuing operations of $7.4 million and $7.2 million for 2007 and the fourth quarter of 2007 respectively. Our effective tax rate in 2008 decreased to approximately $18.4 million primarily due to a one time book to tax difference created by the impairment of our goodwill which is not deductible for tax purposes. Because we are in a tax loss position this permanent difference reduced our total tax benefit which ultimately reduced our effective tax rate.

At December 31, 2008 we also had available unused net operating loss carry forwards that may be applied against future taxable incomes of approximately $8.1 million with $3.8 million expiring in 2027 and the remaining $4.3 million expiring in 2028. Management has determined this is more likely than not our deferred tax assets will likely be realized in the future.

As Ben mentioned previously our financial stability has been enhanced through our aggressive hedging position. Before summarizing our hedging position to you it is important to note that all of our estimated hedge production is based on our full-year 2008 actual production and not our internal projections of actual future production.

In 2009 our oil production is approximately 85% hedged with an average floor price of $63.17 per barrel and an average ceiling price of $75 per barrel. Our oil production in 2010 is approximately 82% hedged with an average floor price of $63 per barrel and an average ceiling price of $79. Our 2009 natural gas production is approximately 95% hedged at an average floor price of $7 per mcf and an average ceiling price of $8.91 per mcf. Our 2010 natural gas production is approximately 100% hedged with an average floor price of $7.56 per mcf and an average ceiling price of $10.48 per mcf.

Our 2011 natural gas production is approximately 78% hedged with an average floor price of $8.00 per mcf and an average ceiling price of $14.75 per mcf. Subsequent to year end we liquidated and unwound our oil derivative instruments relating to fiscal year 2011 which resulted in cash proceeds of $4.6 million to the company.

Benjamin Hulburt

Operator, at this time we would like to open up the call for questions.

Question-and-Answer Session

Operator

(Operator Instructions) The first question comes from the line of Leo Mariani – RBC.

Leo Mariani - RBC

I am just trying to get a sense of what current production is in Marcellus and when you guys are planning to get that plant on line up in Butler County pretty soon and what that can do to your volumes in terms of some increases on the wells you have got out there?

Benjamin Hulburt

I don’t know our total Marcellus production off the top of my head. I can get you that after the call. In terms of gas plants in Butler County, PA initially we have two vertical wells that are on line and producing in that county now. Depending on what the local market can take, they sell anywhere from 50 mcf a day to 400 mcf a day. Obviously they will do more than what the current line allows them to do. Those wells will be the first to be connected into sales through our plant and so then we will be able to see what will those wells ultimately sell.

We have two additional vertical wells in Butler County that we own 50% of that will be completed at this point probably in April. Those wells will then be connected to the plant. We then plan to drill a horizontal well there but it is starting by the end of the first quarter which would then go into that plant.

So at this point we think we will be able to get a decent production increase out of that part of our Marcellus Shale acreage relatively soon.

Leo Mariani - RBC

Could you maybe also touch on southwest Pennsylvania in terms of how many wells you have producing down there and what kinds of rates you are seeing overall in what you are getting from the line?

Benjamin Hulburt

Well in southwestern PA we have three verticals on line and producing. One is the one we announced in this call. I’ll have to get you what their current sales are. I can get you that after the call. I don’t know if you know off the top of your head Bill what they are?

William Ottaviani

The one well that we just put in the line is still stabilized so we don’t have that value determined. The other two wells in Westmoreland County are producing in the order of 200-300 mcf per day into the sales line. That fluctuates. On any given day it could be a little bit higher.

Leo Mariani - RBC

Is that 200-300 a piece? Are those restricted based on [capping] there?

William Ottaviani

It is 200-300 a piece. They are restricted by some of the production units we have on those two wells which are probably under sized. Going forward we are going to use a much larger production unit on our wells.

Leo Mariani - RBC

So it sounds like you are getting pretty good flow in those that are up and running. So far they have kind of held up pretty good on those verticals?

William Ottaviani

Yes. A lot of these were some of our initial wells. We have changed the way we frac and complete these wells almost entirely from when we started the vertical well program to now. I think the results would be expected to continue to get better.

Leo Mariani - RBC

Sticking to the production theme here, as I was looking at your third quarter press release you had some production guidance for the first quarter of roughly 2,400 to 2,700 barrels a day. Is that still a range you are comfortable with? You kind of mentioned a pretty good exit rate of 2,800 barrels a day. Do you think you will fall in that range or be close to top end? What are your thoughts on first quarter production?

Benjamin Hulburt

At this point we are not changing that production guidance. First quarter production always does tend to fall. On the oil side it falls primarily because it is cold out there and you tend to sell less in the colder temperatures. Two, there is a consequence to lowering your development work and your operating expenses and all of those things. As wells go down part of cutting your expenses is you don’t go back on line quite as quickly. So there is some production fall off associated with bringing those expenses down and that is reflected in that guidance.

Leo Mariani - RBC

Obviously your LOE on a basis is down as you mentioned pretty significantly in the fourth quarter. Any thoughts as to where you think that number is going to be in 2009? I think you were around $22 a barrel or something in the fourth quarter.

Benjamin Hulburt

What we are seeing so far into the first quarter is that the lease operating expense cuts we implemented are continuing if not getting even a little better in the first quarter. So as a model, if you take fourth quarter expenses and run those that would be pretty conservative.

Operator

The next question comes from Ron Mills - Johnson Rice.

Ron Mills - Johnson Rice

I wanted to follow-up on one of Leo’s questions or at least one of your answers. It sounds like your bill to purchase rate when it gets delivered it sounds like your plan is to drill your first well in Butler County where it is located, flow proximity to the processing plant. Did I hear that correct?

Benjamin Hulburt

That is correct.

Ron Mills - Johnson Rice

Can you refresh my memory in terms of the processing plant, how it is being designed if there is capacity and I assume you have adapted to a big line as well from there?

William Ottaviani

The processing facility that we are building we are building initially to accommodate a flow rate or through put rate of about 3-5 million but it will also be expandable up to 25 million. It is a refrigeration unit but not a full blown cryogenic unit. We only need to get our BTU down to about 1,100 so we are able to use a refrigeration process and again I just want to emphasize we are building it in two phases so that the initial through put rate is going to be about 3-5 million per day.

Benjamin Hulburt

It is scalable from there.

William Ottaviani

We are building the scalability into the initial design so that when we do want to upsize it we already have the internal infrastructure ready to go ahead and expand it at that point.

Ron Mills - Johnson Rice

Once you move outside of Butler County into Westmoreland County or some of your Clearfield or Centre acreage if you look at your 6-8 well drilling program can you walk through at least as your blueprint shows right now how many new wells you would drill in each of those areas and what it is going to take to get production on in each of those areas?

Benjamin Hulburt

The current plan, and again some of this is always dependent on several factors, but the current plan is to start Butler County with one well and then move the rig to Westmoreland County for several wells and then move to the central part of the state towards the second half of the year. In terms of getting the wells online in Butler County we just discussed that. In Westmoreland County we already have existing tap and pipeline infrastructure in place that will allow us to put several wells on line in our existing tap sites. We also are in the process of putting in two additional tap sites on an Equitrans line that would give us more than we would need in capacity especially for this year’s program.

Additionally in Westmoreland County we already took all the rights away about a year ago from our field to get to the Texas Eastern line which also would provide a very large market for us. In Westmoreland County the gas is a dry gas so we don’t have the need to build a treatment facility there. In terms of our ability to get gas to market easiest it is definitely Westmoreland County.

In Clearfield County and Centre Counties we plan to tap the Columbia 1711 line which runs very close to our acreage. The rights away for the pipeline are already in place. So that tap would be in place prior to our drilling there by the second half of the year. Again, we don’t expect wet gas in that part of the state. There will be no need to build a treatment facility there.

Ron Mills - Johnson Rice

Any thoughts in terms of concerns any more on your side in terms of water access or water disposition issues that continue to be raised by people?

Benjamin Hulburt

We aren’t finding water access to be a major hurdle at this point. In the southwestern part of the state it was always relatively easy to get water and then the central part of the state we were approved to withdraw up to 4 million gallons a day out of rivers in that area. Accessing water is not really a concern any more. Treatment and disposal of water I think remains an industry concern and certainly concerns us as well. Right now we are disposing of our water at existing treatment facilities throughout the state. The concern is that the available capacity of those facilities is very quickly being used up. It does remain a concern in the industry that honestly at this point there is not a total solution for.

Ron Mills - Johnson Rice

On question on the ASP, I think you mentioned it sounds like you all have plus or minus $50 trigger to go forward and spend the money in the second half of the year. How has the development plan changed after your meeting with the Netherland, Sewell in terms of I think you were designing plants for 320 acre unit development. Is that still the course of development? How does that development look based on the data you all have now?

Benjamin Hulburt

Well the development is still being designed as we discussed. What we had originally planned to do in 2009 was to commence two approximately 40 acre units, one in the Bridgeport sandstone and one in the Cypress sandstone. I think at this point it is highly unlikely that our development plan looks like that. As Bill discussed we really want to go back into Cypress pilot and test some conformance gels which one will help us tremendously in the future in understanding how to effectively sweep that reservoir. Two, it does have the potential to maybe move some of those Cypress reserves into a proven category if those tests were successful and showed that yes that is what you should have done all along. It is a relatively cheap test because we don’t have to re-drill all the wells.

On the Bridgeport sandstone we are still in the process of designing the first unit that we would move forward with. We discussed briefly on the call that we met with Netherland, Sewell and they had identified several, I think 27 different ASP POD’s meaning confined areas of the sandstone that are high enough quality that economics would work for ASP flooding in those. But they are varying in size. They range in size from 50 acres to as large as 500 acres. So they are each of different size and very well defined sandstone POD’s. Our plant is already built in the middle of the field. Our plant as it stands now has the capability of flooding about 300 acres, maybe a little bit more at a time.

So we don’t anticipate having to build another plant based on the size of the POD’s because it is centrally located. I think some of the answer is there is more to come over the next 30 days or so as we complete a refined development plan for our ASP project and then we will also have to pull back and see how does our balance sheet look at the time, what are oil prices and what is the best place for us to put our money in this kind of environment.

Operator

The next question comes from Jack Aydin – Keybanc Capital Markets.

Jack Aydin – Keybanc Capital Markets

The ASP, the out [inaudible] was expensive. Now with using…let’s assume you are going partially to the gel or to polymer that is cheaper and part of the field you still use the surfactant. Is the cost structure per barrel or cost per barrel change or the economics of the project would shift somehow? Could you elaborate a little bit? Give us a little bit of a window into your thinking?

Benjamin Hulburt

On the cost side I don’t want to confuse people. The use of conformance gels in Cypress is in addition to ASP flooding. Not a replacement of it. So in the Cypress that would mean you would have added costs for the cost of those chemicals. So far we don’t exactly know what that cost would be until we test the process.

In terms of existing F&D costs, Netherland, Sewell’s current estimates are approximately $25 a barrel on ASP flooding. So when we say we are looking for oil prices above $50 I don’t think people should take from that the F&D costs are $50. $50 is an area where you get a reasonable rate of return. Did that answer your question?

Jack Aydin – Keybanc Capital Markets

At what point would you might decide to cut spending? In the first half of the year or the second half of the year? Looking at, I know your balance sheet is in good shape and everything and with those projects that have long lead times at what point would you might bite the bullet and say okay our focus is on the Marcellus and we will fight the battle on ASP some other day?

Benjamin Hulburt

First of all there is doubt that our main focus is the Marcellus at this point. As I said, if we do an ASP unit this year it will be fairly significantly scaled back. We aren’t at this point changing our capital budget. I think at this point we look at it as the capital budget we set we don’t feel we have a hard time funding. We don’t feel that spending that amount of capital puts up risk of insolvency or anything like that in the future. So we are comfortable with the capital budget we have spent. The question is where can we put that money to get the best bang for the buck in the near term. Those are the decisions we will continue to make as we further define how the ASP process will work, as we see how our Marcellus orders on the wells are working. Obviously if we get flow rates commensurate with some of the other ones we have seen in the state that makes your decision relatively easy as to where you put that capital.

At this point we aren’t changing our capital budget in the aggregate.

Jack Aydin – Keybanc Capital Markets

On your acreage is there a chance that you might lose some of your acreage because of leases? Second, what is acreage going for in that area in the region that you are involved in?

Benjamin Hulburt

In terms of our expiring acreage it is pretty deminimous in 2009. In our 10K I think we are going to release on Tuesday I think it will have a table in there of our expiring acreage and I could tell you it is virtually all Marcellus and you will see we don’t have much acreage expiring at all this year or next year and really not much in 2011 either. Our acreage position remains very, very much intact.

As to leasing costs right now I really don’t want to go into that. We are still selectively leasing in areas where we are filling in drilling units so I would rather not for competitive reasons say what we are seeing in costs.

Jack Aydin – Keybanc Capital Markets

Would you bring in outside personnel to help a little bit in those to accelerate the drilling?

Benjamin Hulburt

We are continuing to evaluate that concept. There has been a lot of interest and we have been approached numerous times on our acreage holdings and would we consider partners. So certainly also goes into some of our analysis in our capital budget and where best to put monies. So it is certainly something we continue to evaluate and consider but it would be very important to us that it be the right partner and somebody that we feel we could work with and would actually add value rather than just doing it for capital.

We are, in our opinion, on the verge of proving horizontal drilling in several of our acreage positions that will substantially change the value of that acreage. So part of our analysis would be are we better off doing a few horizontals, changing the value of the acreage and then look to bring in a partner. The answer to your question is yes we will consider it but we continue to evaluate it.

Operator

The next question comes from Jeff Hayden - Rodman & Renshaw.

Jeff Hayden - Rodman & Renshaw

A couple of follow-up questions to some of the other things which guys have been kind of asking about. Starting with the ASP, thinking about the POD’s, 27 POD’s kind of 40 million barrels potential, I guess the first question would be is that 40 million barrels entirely the Bridgeport or does that include some Cypress too?

Benjamin Hulburt

No that includes both Bridgeport and Cypress and it assumes a 12.7% poor volume recovery which equates to probably around 15% of the original oil in place.

Jeff Hayden - Rodman & Renshaw

So that is kind of 15% versus the initial 23% you were targeting?

Benjamin Hulburt

That’s right. So I think it is a pretty good assessment. Also, I want to stress, it only includes the northern and central part of the field so there is another 25-30% of the field that all of that detailed geological work on is not done yet.

Jeff Hayden - Rodman & Renshaw

Using that $25-ish a barrel as the F&D cost, how about LOE, what is your expectation there? Has that changed at all?

Benjamin Hulburt

No, that wouldn’t have materially changed from our original estimates.

Jeff Hayden - Rodman & Renshaw

Jumping from there back to Marcellus, you talked about differences in completion techniques you did on this well versus some of the earlier ones. I am just wondering if you can detail that a little more as well as can you give us some color on the initial expectations for how you are going to set up horizontal wells as far as lateral [blades], planned frac stages, etc.?

Benjamin Hulburt

Without getting too specific on the completions the improvements have basically been in isolating certain sections of the Marcellus in separate stages. In terms of horizontal plan what our initial designs call for is about a 2,500 to 3,000 foot lateral and 5-8 stage completions.

Jeff Hayden - Rodman & Renshaw

The revolver currently stands at $80 million. When is your re-determination with your bank and do you have any indications on what could happen post re-determination?

Benjamin Hulburt

It actually is ongoing right now based on year-end reserves. I don’t want to give any indications yet. We will know very shortly. I personally do not anticipate a significant decrease in that borrowing base. We are protected a lot because of our hedges and having that high a percentage of your production hedged does help quite a bit. We don’t know an exact number yet but I’m not anticipating a draconian cut.

Jeff Hayden - Rodman & Renshaw

So maybe about $10-15 million but it is not going to get cut in half?

Benjamin Hulburt

It’s not going to get cut in half. Other than that I don’t want to prejudice the decisions from our wonderful financial institutions.

Operator

The next question comes from Marshall Carver – Capital One.

Marshall Carver – Capital One

You unwound some 2011 hedges. Any thoughts about unwinding any more hedges and how much the present value of that could change?

Benjamin Hulburt

Again, I think our hedges are important especially in 2009 and 2010. We do still have a large percentage of our natural gas hedged in 2011 so there is potential if we see the opportunity to take those off as well. Tom do you know what the market was?

Tom Stabley

It is in the range of $1.5 million to $2 million on the gas hedges for 2011.

Marshall Carver – Capital One

What about the entire position?

Tom Stabley

I think at year end it is approximately $15 million for the entire position.

Marshall Carver – Capital One

With the smaller POD’s in the ASP I know when you were talking about the larger, full scale development when you first started putting capital to work production would be 18 months or 2 years or even 3 years away for a substantial increase in production. With the smaller development areas if you did start to put some money to work in 2010 with ASP when would you expect to start seeing some cash flow from that?

Benjamin Hulburt

The timeline really doesn’t change much based on size of the POD’s because it is a function of well spacing and how long does it take you to fill that core volume. Given the number of wells you are putting inside the acreage area of that POD, the timing isn’t materially different based on the number of acres you are putting in a POD. It is really more dependent on what is the core space you are filling and how long it takes to fill that. That is not something that would have changed from our original expectations. I think you are still looking at from the time you start injecting in a POD that has well spacing of 5-10 acres it is probably 12-18 months until you see an initial production response. Don’t you agree Bill?

William Ottaviani

I think that is reasonable. It will vary based on a couple of parameters but Ben is correct in generally speaking it will be a longer-term timeline as we had originally planned.

Marshall Carver – Capital One

On 6-8 net well program this year how many gross wells would that be and what is your working interest in that $1.4 million a well to the well you recently tested?

Benjamin Hulburt

The drills would also be 6-8. The wells will be planned and so far we own 100% of them.

Marshall Carver – Capital One

Any updates on 2009, what was your current feel on 2009 production guidance? Or do you want to hold off on giving that?

Benjamin Hulburt

At this point we are going to hold off giving production guidance for 2009 for a couple of reasons. One, the uncertainty in the economic environment. Two, these Marcellus wells in relation to the size of our total company production obviously have great impact. If they come on at 1 million a day or 5 million a day upwards of that. If I were to give production guidance the variance between the low end and the high end I think would be so wide that it is really not of much use to you.

In terms of building your own internal production model our base production tends to decline at 4-6% per year and again we will do 6-8 Marcellus wells. First one coming on line hopefully around May and then evenly spaced from there. Some of it is a function of pick what you want to use as an IP rate assumption for those horizontal Marcellus wells.

Operator

The next question comes from Analyst - Natixis Bleichroeder.

Analyst - Natixis Bleichroeder

Just a couple of more questions on mainly infrastructure here. I think in your last call you mentioned a takeaway capacity at Westmoreland of around 5 million a day. Could you give us an update on that capacity in that area?

William Ottaviani

The current take away capacity for the Marcellus is 5 million but as Ben mentioned we have a number of tap sites that are in progress that will increase our overall take away capacity by year end to just over 20 million per day.

Analyst - Natixis Bleichroeder

Are there any pressure constraints on your infrastructure there? Say if you put down a really nice horizontal well is there any chance that you might have to choke some of that back? Are you going to be able to push it on through the infrastructure?

Benjamin Hulburt

I think the answer is with the first horizontal we are inclined to put it into our existing infrastructure. So we would probably let that flow at full rates that we could test it which might impact some of our other vertical wells going into that system. After that Marcellus wells will go into the other two taps that Bill mentioned and then there will be no restriction.

Analyst - Natixis Bleichroeder

How much of your capital budget in Marcellus are you spending on infrastructure in 2009?

Benjamin Hulburt

I don’t have that number off the top of my head. I can call you with it later. My estimation is probably $3-5 million.

Analyst - Natixis Bleichroeder

Did you pay some cash taxes this quarter?

Benjamin Hulburt

No we did not.

Operator

At this time there are no further questions. I would like to turn the presentation back over to Mr. Benjamin Hulburt. Please proceed.

Benjamin Hulburt

Thank you. I would like to thank you all for participating in the call. Before leaving I would like to wrap up by reiterating the strength of Rex Energy. Our continued commitment to maintaining a conservative balance sheet and strong liquidity position I believe positions Rex Energy at a clear advantage over other energy companies our size in the coming year. We acquired an invaluable learning curve in 2008 both in our Marcellus Shale development and ASP project. The knowledge gained will now allow us to make great strides in 2009.

With that I would like to thank everybody again for participating in today’s call.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Rex Energy Corporation Q4 2008 Earnings Call Transcript
This Transcript
All Transcripts