Ranger Oil Corp (ROCC) 2011 Q4 法說會逐字稿

Thanks so much for standing by everyone and welcome to the Penn Virginia Corporation fourth-quarter 2011 earnings conference call. Today's call is being recorded. At this time, Now, at this time, I'd like to turn the conference over to Baird Whitehead, Chief Executive Officer. Please go ahead, sir.

Thank you very much, Abe. Good morning and welcome to Penn Virginia's fourth- quarter and full-year 2011 conference call. I am joined today by various members of our team including Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO; John Brooks our Senior Vice President and Regional Management of our Gulf Coast operations; and Jim Dean, our Vice President of Corporate Development. Prior to getting started we'd like remind you of our language in our forward-looking statements section of the press release as issued last night, as well as the form 10-K, which will be filed by next week, will apply to our comments this morning. We would like to begin our discussion by expanding on the earnings and operational update press release that was issued after the close yesterday.

2011 clearly has been a transitional year for the Company, and we are now finally beginning to see the positive benefits of moving to what was once only a natural gas company to what now can be considered more of a natural gas and oil company. We had a solid financial quarter with revenue, EBITDAX cash flows and adjusted EPS -- they were better than previous years quarter, primarily due to our material growth and our oil production, which in turn is attributable to the ongoing solid results of our Eagle Ford shale drilling program. Product revenues of $77.4 million were up 21% over the fourth quarter of 2010. As our realizations increased 48% from $4.88 per Mcfe to $7.20 per Mcfe. Oil and liquid revenue were $53.9 million or 70% of total product revenues and increased 99% over the fourth-quarter 2010, due to increased oil and liquid production and higher realized oil and NGL prices.

EBITDAX of $62.2 million was up 34% over the fourth quarter of 2010. This improvement in EBITDAX was attributable to not only the increase in oil and liquids revenues, but also our continued focus on reducing our direct operating expenses, which decreased from $1.99 per Mcfe from $2.02 per Mcfe in the fourth quarter 2010 and from $2.14 per Mcfe in the third quarter of 2011, due in part to the sale of our higher cost, our [comb] assets in the third quarter and various restructuring initiatives we have taken throughout 2011. Our gross operation margin per Mcfe increased 83% from $2.85 per Mcfe to $5.22 per Mcfe in the fourth quarter 2011, due to our shift toward oil and NGLs as well as our continued focus on reducing costs.

Adjusted earnings was a loss of $6.2 million and adjusted earnings per share was a negative $0.14, which includes a cash impact of derivatives and excludes charges for impairments, restructuring costs, and other non-recurring items. This is an improvement of $0.10 over the fourth quarter 2010 and primarily due to the increase in the gross operating margin. Production of 10.7 Bcfe or $117 million a day equivalent was 13% below production in the fourth quarter of 2010 -- taking into account the sale of our Arkoma assets -- primarily due to a 29% less natural gas production, since we have intentionally elected to reduce natural gas drillings significantly over the past 18 months and going forward.

That gas production decrease was partially offset by a 43% increase in oil and natural gas liquid production from 463,000 barrels in the fourth of 2010 to 662,000 barrels in the fourth quarter of 2011. We continue to see a monthly ramp up in oil production extending into the first month of 2012. Fourth-quarter production was 37% oil and liquids just compared to 21% in the fourth quarter 2010 and 33% in the third quarter of this year. And we expect oil and natural gas liquid production to increase further in 2012 to approximately 42% of our total production. In fact, for January production, our oil and NGLs was 42% of our total production.

This increase -- significant increase in liquids production clearly benefits our revenues and margins which we believe far outweigh our year-over-year production declines as we focus our capital on growing cash flows and generating higher rates of return, instead of pursuing lower or uneconomical rate of return growth in gas production, at this time. As of year-end, our crudes reserves were 883 Bcf equivalent, 49% of which were developed and 24% of which were oil and liquids, an increase from 21% at year-end 2010. The reserves are down 59% Bcf from the 942 at year-end 2010, but down only 20 Bcf from the 903 from the year-end 2010, taking in account the sale of our Arkoma assets which were 39 Bcf approved.

In addition to the asset sale, we had 94 Bcf of negative revisions. Most of that was related to the Granite Wash issue -- the interference issue that we have talked on numerous times on other phone calls, and to a lesser extent, negative revisions in East Texas and the Mississippi Selma Chalk. We added approximately 119 Bcfe of crude reserves, approximately half of which were oil and liquids additions. In Eagle Ford alone, we added a little over 10 million barrels of liquids and approximately 3.5 Bcf of gas. And to remind everyone -- we had no reserves booked on the Eagle Ford at year-end 2010. Despite the negative reserve revisions of Pb10, oil reserves of $874 million was relatively flat with 2010, which was $878 million and is due to an overall increase in our oil and NGL reserves of about 3 million barrels and the fact that higher oil price was used at year-end 2011 versus 2010.

The Eagle Ford Shale was a primary driver of our growth in 2011, and 2012 will be more of the same as we plan to spend at least 85% of our total capital expenditures in this play with about 90% of our drilling capital alone and committed to the Eagle Ford. I think this play is establishing itself as a best in class among the existing resource plays. And given strong oil prices with the positive base premium to WTI, since we sell into the LSS market, we think our results to-date, along with the location of our acreage in Gonzales and Lavaca counties, and primarily in the volatile oil window, puts us in a good position to demonstrate ongoing oil and natural gas liquid growth with very attractive economics. We have drilled 39 Eagle Ford wells to date, and we just turned in line the 35th well.

The other four wells are either in the process of being completed or waiting on completion. Post-processing -- our current gross production is about 9800 barrels a day equivalent, which has an average component of 89% oil, 6% natural gas liquids and about 5% dry gas -- residue gas. 32 to 35 producing wells have had an average peak rate of about 1000 barrels a day equivalent, with a 30-day average rate of 675 barrels a day equivalent for the 26 applicable wells. Two of the wells drilled to-date are not included in these statistics; one due to a short lateral of 1700 feet, getting caught up in a fault, and the other one due to, in all probability, a geological issue. It seems we established communication with a deeper zone, which caused a H2S problem. A third well was just turned in line for which an IP has not yet been established, but as of right now, that well is making 50 barrels in oil per hour. So that is a very good well.

We have averaged lateral lengths of about 3800 feet with 15 frac stages. A recent focus of our Gulf Coast operation is just to reduce our drilling completion costs on these wells. We have made a lot of progress in reducing our well costs, dropping from just over about $10 million a well in the third quarter of 2011 to approximately an estimated 8 million drilling completion costs in the fourth quarter of 2011. Much of this cost reduction has been on the completion side. Considering that, in many cases, we will ultimately down space to 60 acre to 80 acre spacing. We feel that it is not necessary to put a large individual frac stages away. We, therefore, have reduced the size of each frac stage as to the amount of proppant pumped. In addition, we have reduced the amount of ceramic and are currently pumping about 50% white sand, which is cheaper, and 50% ceramic. We have also secured ceramic directly which has reduced the cost of that proppant.

During this last quarter, we've been able to reduce our completion costs alone from $6 million a well to about $4.7 million a well. Simultaneously, we continue to make improvements on the drilling side and continue to drive the rotating day's time, so as our most recent wells are anywhere from 10 days to 15 days from spud to TD. Our gross well costs are expected to average $8 million, going forward, which results in an attractive rate of return of about 48% after tax -- excuse me -- before tax and a present value discounted at 10% of about $6 million, assuming $100 per barrel WTI and using a $4 flat gas price. This assumes an approximate 400,000 barrel tight curve, which is a Company estimate based on the wells we have drilled to date.

We also thank the guys in the Gulf Coast operations are making strong efforts on reducing our drilling and completion costs further. We think ultimately we should be able to get this cost down to about $7 million to $7.5 million per well as the year progresses. We expect to drill 31 gross wells, about 27 net during 2012, including our first six test wells on our new farming acreage in Lavaca County. As part of our effort to reduce our outspend of cash flow, we will reduce our 2012 capital expenditure by going from three rigs currently drilling, to two rigs later in this quarter. By doing this, we do not jeopardize any of our acreage. At the same time, we plan on earning our farm-out acreage by drilling our first six obligatory wells.

We have tested down-spacing on our first three-well pad, and at this time, considering they have only been on line for about a month, there have been no signs of interference or communication between the wells. We plan to become more aggressive and test down-spacing going forward and believe this may be more appropriate over the majority of our acreage with spacing ultimately as low as between 60 acre and 80 acre spacing. As tight as this reservoir is, down-spacing will be necessary to effectively drain that oil's recoverable with the ultimate goal of continuing to drive our drilling and completion costs down. As pointed out in the press release was our current Gonzales County acreage and with a minimum expected working interest 56% in our Lavaca County acreage, we ultimately expect to bring our total acreage position at Eagle Ford to approximately 31,400 acres gross and 23,100 acres net.

With down-spacing, we believed that we may have up 190 well locations, of which 42 have been drilled, or are currently drilling. We have also allocated about $10 million in this year's capital program for lease acquisition to continue to acquire Eagle Ford acreage in and around where we currently exist. For your information, we expect to spud our first test one in Lavaca County -- probably it will spud in the next couple of days. In the Mid-Continent, in addition to selected participations with Chesapeake as the operator of our Granite Wash wells, we are planning to test our prospect in the first half of 2012, which is a Viola Lime prospect. It is an oil prospect. It is a fractured carbonate. We have about 8000 acres picked up in this prospect to date, and we will drill it horizontally.

Prior to turning this over to Steve for his comments on our financial condition, I wanted to give you an overview of our strategy and guidance for 2012 as well as our financial condition and liquidity. As mentioned, we are focused on increasing revenues, earnings and cash flows by devoting capital only to our higher return oily- and liquids-rich projects like the Eagle Ford into and to a much lesser extent the Granite Wash, in lieu of any investments in natural gas projects. We do this, even if the results in a decrease in total equivalent production, since we retain leverage to natural gas projects and we believe that revenues, earnings and cash flow is more important than production growth, merely for the sake of production growth. We've also significantly increased our hedging position on the oil side, which Steve will get into, and continue to add hedges as production grows and at opportune times in the market.

Moreover, since we may remain committed to retaining a strong and flexible balance sheet with ample liquidity position as to whether challenges should take advantage of market opportunities. As mentioned, we have elected slowdown drilling in Eagle Ford Shale, at least temporarily, and discontinue any investments in gas as to reduce our capital expenditures by about 30% from last year and reduce our outspend of cash flow by approximately 40%, and therefore reduce the rate in which we incur any debt while still expecting increased revenues and cash flows. In doing this, we will see a year-over-year decrease in production, as outlined in the press release.

But at the same time, it shows increases in oil and natural gas liquid production and net cash flow provided by operating activities. Finally, we also simultaneously are considering a sale of non-strategic assets to reduce our debt as the year goes on and to improve our liquidity further and to improve our pro forma growth trajectory for our firm (technical difficulties) by selling declining assets. We also expect, by doing that, our valuation multiples will improve accordingly.

With that, I'd like to turn it over to Steve Hartman to have him give you an update of our financial progress for the quarter.

Thank you, Baird and good morning. I'll be highlighting our fourth-quarter 2011 financial results starting on page 2 of the release. The review will generally be comparing our fourth-quarter results with our prior-year quarter results from fourth-quarter 2010, unless otherwise noted. Total revenues were $80.5 million for the quarter, up 25% over the prior-year quarter. This quarter's results include a gain on sale of $3 million as a result of selling our Marcellus acreage position in Butler and Armstrong counties, southwestern Pennsylvania. As Baird mentioned earlier, product revenues were $77.4 million for the quarter or $7.20 per Mcfe. Revenue from oil and natural gas liquids at $54 million was 70% of total product revenues, up from $27 million or 42% of total product revenues in the prior-year quarter. Our average realized price for oil was $98.49 per barrel, up from $82.84 in the prior-year quarter and $87.03 in the previous quarter.

We have generally been realizing a premium over WTI pricing, net of transportation based on the quality and due to selling the majority of our oil on an LLS pricing basis. Our natural gas liquid pricing for the quarter was $45.46 per barrel, up from $42.15 in the prior-year quarter. Natural gas prices were lower at $3.46 per Mcf, down from $3.57 in the prior quarter and $4.24 in the previous quarter. Hedges added $0.87per Mcf to our realized natural gas price and $2.72 per barrel to our realized oil price. Cash operating expenses decreased 20% or $5.2 million to $21.3 million for the quarter. This equates to $1.99 per Mcf on an equivalence basis, compared to $2.02 per Mcfe in the prior-year quarter. Lease operating expense and gathering processing and transportation expenses were up slightly on a per unit basis due to lower volumes and work-over expenses in East Texas offset by the sale of our relatively higher cost Arkoma Basin assets.

Production and ad valorem taxes were higher due to higher product revenues and a favorable tax adjustment recorded in 2010. G&A expense decreased 40% over the prior-year quarter to $7.6 million or $0.71 per Mcfe, due to consolidation of our regional offices and lower restructuring costs and a one-time accrual adjustment to salary expense. Our gross operating margin, which we define as total product revenue less direct cash operating expenses, was $5.22 per Mcfe, up 83% from the fourth-quarter 2010. As Baird mentioned, this is the reason we are less focused on total production growth and more focused on growth in our high margin oil prospect development. Adjusted EBITDAX, another metric of cash flow growth and a key driver of our liquidity was $62.2 million for the quarter, up 34% from $46.6 million in the fourth-quarter 2010, despite lower natural gas prices.

This is a non-GAAP number reconciled on page 12 of the release. Exploration expense was $10.7 million for the quarter, down from $12 million in the prior-year quarter, primarily due to lower dry hole costs and rigs standby charges offset by higher lease amortization and seismic costs. The DD&A expense increased $10 million to $49.3 million or $4.59 per Mcfe for the quarter, due to a higher contribution from Eagle Ford Shale oil wells and the negative reserve revisions, as Baird already discussed. We recorded $33.6 million in impairment expense and some of our horizontal coalbed methane and Selma Chalk assets during the quarter, as a result of lower natural gas prices. Bottom line, we reported an unadjusted operating loss for the quarter of $37.1 million and an unadjusted net loss of $27.9 million, which is a loss of $0.61 per share.

Adjusted for derivatives, impairments, restructuring and other non-recurring items, our adjusted net loss was $0.14 per share. Moving on to capital resources and liquidity, starting on page 7 of the release, at year-end, we had total debt of $704 million comprised of $600 million of high-yield notes, $5 million of subordinated convertible notes and $99 million outstanding on our revolving credit facility. Our cash position at the end of the year was $7 million. Our current Revolver balance is $116 million and our current cash position is $13.5 million, yielding current net debt of $707.5 million. We have no debt maturity until 2016 other than the $5 million of convertible notes, which are due in the fourth quarter of this year. We currently have $182.6 million of availability under our $300 million revolver commitment. Our borrowing base is currently $380 million, which has been adjusted for the Arkoma Basin asset sale.

Our borrowing base redetermination is scheduled for this coming April, and due to the decline in natural gas prices, we do expect our borrowing base will decline from the current $380 million level. We do not know at this time what our redetermined borrowing base will be, and we do not expect it to be materially lower than our current $300 million commitment. As Baird mentioned, to further enhance our liquidity, we are planning to reduce the outspend of cash flow this year by implementing a two-rig program in the Eagle Ford for the majority of the year. To give you more guidance on our anticipated overspend, we are trying something new, as shown on page 8 of the release. We are guiding you to our anticipated net cash provided by operating activities, less some known uses of cash, to get to a range of cash flow available for investment.

From there, we subtract our guidance range for capital expenditures, less seismic expenditures, which are already captured in the cash flow from operations number, to get you to a range of our expected cash outspend for the year. As you can see in the release, we expect our cash outspend to be approximately $107 million to $157 million. This is based on our assumed 2012 commodity pricing of $3 per Mcf for natural gas and $91.25 per barrel for oil. This also includes a $30 million cash federal income tax refund we expect to receive in the fourth quarter of 2012. That was related to the sale of PVG, plus other assumed changes in working capital. We expect to fund the shortfall by borrowing under our revolver and through the sales of some non-core strategic assets, as Baird discussed earlier.

Finally, a quick comment on hedging before we move on to the guidance. We have been actively hedging oils since the last earnings call, generally with swaps and generally a price that is slightly over $100 for 2012 and 2013. We have currently hedged 47% of our anticipated crude oil as a percentage of the midpoint of production guidance and 32% of natural gas, again as a percentage of the midpoint of guidance. Given our current hedge portfolio and assumed product pricing, we would expect to receive $24.5 million in cash settlements from hedges in 2012. A summary of our current hedge position is included on page 14 of the release. And now on to guidance. Our 2012 guidance is summarized on page 13 of the release. You will note, we are now including revenue and cash flow guidance, which is a departure from what we have shown you in the past.

We are also now showing you key items of both Mcfe and BOE units to make your modeling a little easier. Our production guidance is 40 Bcfe to 43 Bcfe. We expect oil will increase to between 2,000 MBOE and 2,275 MBOE, which is a 56% to 77% increase over 2011 oil production. We expect oil and NGLs together will contribute between 41% to 43% of total production from 2012, up from 28% in 2011 and 37% in the fourth quarter. We expect product revenues of $287 million to $319 million based on price assumptions of $3 for gas and $91.25 for oil, as I already mentioned. This does not include cash settlements from hedges, which, as I did mention, would be another $24.5 million. We expect oil and NGL revenue to be between 77% and 78% of total product revenue, up from 54% in 2011.

We expect lease operating expenses to be between $0.80 and $0.85 per Mcfe and gathering, processing and transportation expenses to be between $0.28 and $0.33 per Mcfe. We expect slightly higher per-unit numbers because of the natural gas production declines. We expect cash recurring G&A costs of $39 million to $41 million, which is a run rate of approximately $9 million to $10 million per quarter. Our fourth-quarter 2011 reported number was lower than our typical run rate, due to that one-time nonrecurring accrual, I mentioned earlier. Expiration expense is generally unproved property amortization with some dollars included for seismic expense, which is also included in the capital expenditure guidance, delay rentals and drive hole risking for the Viola prospect that Baird had mentioned.

DD&A is expected to be between $4.75 to $5.25 per Mcf equivalent, which is higher than our 2011 run rate, primary because of the addition of higher rate Eagle Ford Shale wells and doing the reserve revisions. We expect adjusted EBITDAX of $200 million to $240 million in cash flow from operating activities to be between $175 million and $205 million, as compared to $145 million in 2011. And finally, we expect capital expenditures of $300 million to $325 million for the year, which is 27% to 30% below 2011 levels. Approximately 80% of that will be spent on development drilling, primarily in the Eagle Ford Shale, as Baird mentioned. We have $30 million to $35 million in exploration for Lavaca County AMI and the Viola prospect. We have $20 million to $25 million for land acquisitions, $5 million to $10 million for seismic costs and $5 million to $10 million for facilities.

That concludes guidance, Baird.

Thanks, Steve. To finish up, I don't have to tell you, 2011 has been a challenging year for us. We have a lot of work ahead of us this year. We had to make some tough decisions. We have decided to go from three rigs to two rigs. We have cut our CapEx considerably. At the end of the day, until we see clear of ourself on the liquidity issue, this is the right thing for us to do. Once it is solved, we can always add rigs back in the Eagle Ford because that acreage will be held by production. With these steps, I think we can reinitiate growth of the Company and shareholder growth.

And with that, Abe, I'd like to open up the line for any questions, please.

Certainly. (Operator Instructions) Neal Dingmann, SunTrust.

This is Joanna in for Neal. My first question is -- thank you for laying out your cash flow outspend for this year -- given your current liquidity and where you fall within that guidance, looks like you'll end up with less than $100 million in availability, so looking into 2013, can we expect that outspend to continue or how will that outspend change? I don't know if it is a little premature, but if you could give us some color on what to expect?

It is somewhat premature. We do not plan on ending up the year at that kind of level of level of liquidity. We're going to take some aggressive steps on fixing it, and we will go out with sale of some assets. But as far as 2013, we really have not -- the goal is to try to get through this year and improve our liquidity. I would expect the program in 2013, depending on -- once those steps have taken place to improve our liquidity -- that in all likelihood we would add back a third rig, for instance, in the Eagle Ford. So I think it's probably premature to say how much money we are going to spend the next year. But with these steps, we would add rig or rigs back drilling oil wells.

In terms of the divestitures that you mentioned, would that include gassy areas, given the current environment?

It could. Anything is on the table at this time. All options are on the table. It could. It depends on what kind of gassy assets -- there still a lot of interest even with low product pricing of some gassier assets than others. I realize I'm not explaining myself very well, but a low decline gas assets will still attract a premium price.

On your newer area in Lavaca County -- can you tell us about what your expectations are there and how you anticipate it stacking up versus your existing Eagle Ford portfolio?

Since we are going down a dip in Lavaca County, as you go to the East these wells ought to get gassier, the reserves ought to increase because the gas component percentage actually goes up. But I would expect the early wells we drilled will act very similar to what we have already drilled in Gonzales County.

Steve Berman, Pritchard Capital.

Baird, now that you have a bunch of wells with a history in Gonzales, what is your latest thinking on your 400,000 BOE-type curve. Is that conservative, or what are your thoughts there?

It is realistic at this time. We have some wells the do better than that, of course, on any statistical play or any resource place such as this. But I think 400,000 at least, is a good number. As we continue to drill wells that 400,000, it's not really moving a lot. We actually drilled a few better wells early in the play, and if you remember, our type curve has come down somewhat. We have honed in on this 400,000 barrel type curve and we feel comfortable with that, at this time.

What are you choking these wells at? What is your average choke size when you're bringing these on, typically?

Well, as cleanup goes on, we'll start it at 12 and to go our 1464s and 1664s. We do hold back pressure on these wells versus opening up to a larger choke earlier. We feel that is the prudent thing to do for frack reasons or protecting the integrity of that prop frack. But we bring them back gently.

Last one for me. The 190 potential locations here, how many of those are not booked yet or unbooked?

We've only got 25 puds booked and 30 wells. They are actually PDP, so the rest of them would be in the prop-possible category.

Okay. So 55 approved locations out of the 190, roughly?

That is correct.

(Operator Instructions) Eli Kantor, Jefferies & Co.

How many wells were included in the 40 Bcfe of Marcellus reserve additions?

We had four -- three PDPs, we had one PDMP and 13 puds

What kind of EORs were ascribed to the PDPs, PEDs, and PDNP?

It depends on lateral length. Randy Wright, our reserve engineer actually does it based on lateral length, but they will run anywhere from 3.5 to 4 Bs gross.

Safe to say, the 13 pods are expected to be drilled some time, '14, '15, '16 time period?

Yes -- the gas price depending, of course. But they are valid wells. We have the first few wells online. They are actually doing better than what I thought they we do once we got compression installed and actually have leveled off and in total of about $2 million a day gross, as they continue to clean up. It is still not exactly what we were looking for, of course. But as I have pointed out in past calls, if we could tweak the lateral direction, things to that effect, we think we can improve upon this factor too. But really, the first three wells have actually done fairly well.

Last question for me is -- can you give a little more timing or more color on the timing of when we should expect to hear results from the non-strategic asset sale program?

I would say they probably would be in the third quarter. We will try to get something done and will start something here ASAP. But I'd say it would probably be an early third-quarter event.

Can you give any ballpark on the quantity of proceeds you expect to generate from the program?

I prefer not to do that at this time.

Amir Arif, Stifel Nicholas.

On the Marcellus, can you lay out what you are thinking? You're not drilling there right now. You still have a lot of acreage -- you sold some -- so what are you thinking in terms of the remaining acreage there?

Well, fortunately most of that stuff does not -- we do not get into an expiration issue until 2013. So we have some time. We still continue to try to -- if we could find a JV partner or if the right price come down the road to take a side completely, we would entertain that. At this time, it is sort of status quo, we are not really doing anything.

The acreage expires -- starts to expire in '13 or is that the majority of the acreage that will expire by then?

It starts to expire in 2013. We actually have a 10-year lease out there with the state of Pennsylvania that doesn't expire -- close to 2020 or so. The bulk of it was five-year leases and 2013 and 2014 acreage starts to expire.

Second question, on the expected asset sales, I understand you do not want to go into numbers or detailed timing, but would that be used to clean up the balance sheet or would you plan on using proceeds to bring back a third rig or start accelerating so of your drilling?

It would depend upon the significance of the proceeds. The main goal is to improve our liquidity.

Final question -- in the release, obviously, I am sure you can focus on asset sales and other opportunities first, but you also mentioned that possibly -- access to the capital markets. Can you just add some color in terms of what you are thinking and where that would stand relative to other opportunities you are seeking?

That is an option I think any company would they do not want to take off the table. At this time, we have no plans to do that. Our plan is to go the asset-sale route, but it is always an option for the Company.

Adam Lee, RBC Capital Markets.

I guess I can follow up with a couple on the asset-sale front. Have you factored that into your guidance or is that to be determined?

That has not been factored into our guidance. Depending on what and how much we sell then, of course, that guidance would have to be adjusted.

Going back to the 2013 question to phrase it another way. Is there a level of spending that you think might be required to sustain cash flow production rather (inaudible).

You faded out as the question went on and I didn't hear what you said.

Rather than giving us what you might be spending in 2013, what is the minimum threshold spending level to sustain cash flow?

Probably around $250 million, plus or minus.

Of the current year budget, how much of that is committed?

Well, the only thing that is committed is we have two rigs under long-term contract, one of which rolls off at the end of this year, the other one of which rolls off at the beginning of 2013. That would be the only committed, if that is what you mean. The only other issue that we will forge ahead on is our Lavaca County farming opportunity. We're not going to let that go by the wayside, so we will get those first six wells as obligatory wells drilled.

That's good. I was going to ask you to clarify a little more on than that. Just details of that, what does it take to earn in a greater proportion to the acreage, if that's plausible?

The first -- correct me if I am wrong, John Brooks. The first three wells, we have a carry. On the second three wells, the company which farmed out the acreage has a right to participate for 40% interest. So after we drill those first six wells, the first three of which are carries. They back in for 1/4 interest after payout. The second three wells, they have the right to participate for 40%, then we have the rights to the entire acreage block. If our early wells look good, we will probably redirect some money to that Lavaca County acreage because, in theory, the economics of those wells could be better because reserves are somewhat better. We've got some flexibility to move rigs around and focus on the higher value opportunities, of course.

And the infrastructure there is all in place? For whatever --

It will be in place. In fact, that's one of the reasons why the party farmed out to us is because we already have the infrastructure in place for our Gonzales County stuff. Some of this acreage is very close to what we already have. Yes, we will get these wells in line pronto.

Can you give a sense of what the decline rate is on the remainder of your portfolio outside the Eagle Ford?

It is about 25% in total. That takes into account stuff back east and maybe on a 8% to 10% decline versus Granite Wash or East Texas and maybe 30% of 35% decline.

(Operator Instructions) Gregg Brody, JPMorgan.

On the borrowing base, as you think about -- when you approach the borrowing bases this April, will your reserves have to be adjusted for what the price deck the banks are using, or do you use your current reserve bases?

We submit our current reserve base to JPMorgan who is our lead bank. They do their engineering work based on their price deck, their bank price deck, and make the adjustments for the economics of the reserves. Then, they come up with a number and they submit that to the other 10 banks in the bank group who have their own engineering and price deck processes, and then they approve, most likely, the number that JPMorgan would put out in front of them as a recommendation. Our hedges are included in that number and the first quarter production, any wells the come on line from year-end through the first quarter. Those will also be included in the borrowing base.

So you can actually adjust it to that?

Yes.

The assets -- a couple questions asked about it and you gave some non-specifics. Is there any asset in particular in terms of an area that you can quantify the size of it -- that you are looking at selling? In terms of per reserve number or in terms of production?

No. We would just as soon not go in that direction. We will soon get those assets out on the market, so you all figure it out here sooner or later. That would be the best way to handle this.

Scott Hanold, RBC Capital Markets

Obviously, you are scaling back activity to improve your balance sheet. Can you give me your perspective of what it's going to take to actually want to start ramping stuff up. Obviously, the Eagle Ford Well results, you talk about 50% IRR, so clearly you're going to want to get as much of that activity up and running again as you can. If you do get off the assets sale, could that rig come back on later this year or is that more of a 2013 type of consideration?

It could, Scott, depending on the timing and the amount of proceeds we get with whatever assets we decide to sell. If it is of significance and we can see our way clear as far as our liquidity concern, we would bring back a rig later on this year. In all probably it would be a -- early 2013 event. But there is a case we made, if our Lavaca County stuff turns out to be very good, I think there would be a motivation for us to try to get a rig back to work sooner than later, assuming that we have our liquidity issue under control.

How many wells -- like Eagle Ford operated wells do plan on drilling this year and completing this year?

We have 31 in the budget and those are all Company operated.

You'll be able to keep up completions in that, so 31 drilled, 31 completed is the right way to look at it? Is that right?

Yes, some wells slopped over [in front] -- that we drilled in 2011got completed in 2012 so you always have some entry-exit issues. In general, yes. We have not had a problem. We have a long-term contract with C&J, so we are completing anywhere from two to four wells a month.

Non-operated activity, just in general, not specifically talking about the Eagle Ford here anymore. How much of your CapEx is due to non-operated activity versus operated -- so the $325 million? What percentage is non-op?

Around $25 million to $30 million is Granite Wash stuff, and that is all outside operated. Whether that gets spent or not -- it is not crystal clear at this time. That is based on our most recent conversations and schedule from Chesapeake, but it is fairly small.

Okay, the Granite Wash is pretty much the only area where you have not operated stuff coming into that, right?

That is correct. Even that one prospect we're going to drill. We will be the operator there.

You are reducing activity looking for asset sales to continue to improve the balance sheet. But as you look ahead, acreage capture opportunities -- what do see in the Eagle Ford, in general? Are there any other things that you are out there looking at right now?

We continue to pick up acreage in bits and pieces in the Eagle Ford. We have allocated around $10 million. We continue to look at -- newer place, we have a stealth team -- I hate to use that word stealth because everybody else uses it in today's world -- but we have a stealth team in place that is looking for new opportunities, internally-generated opportunities. We would like to get into the Mississippian lime if we could find the right area, but we have been very selective as far as where we want to be. Until we get our arms around our liquidity issue, we couldn't afford do a larger deal. But we could go in and pick up 10,000 acres to 20,000 acres at a reasonable price and not have to spend a lot of money up front, and that would be a sizable position as far as we are concerned, in the Mississippian lime. Most of our activity, of course, is continued to be focused on the Eagle Ford, and that is where most of our money is going to be spent.

Do have a line on some acreage in the Mississippian or are you just talking, in general, that you think you could go out and do it right now if you had the cash?

There are some opportunities out there that we would like to pull the trigger on, but we are still looking it, technically. We have a new vice president of exploration who is looking at it in detail. Until he gets his study wrapped up, we have not decided to pull the trigger on anything.

David Snow, Energy Equities.

A couple of wells in Lavaca might look the same as the ones you have been drilling. Overall, how do you see the percentage gas and the total reserves changing in that new play?

I cannot remember exactly. 95% of our Gonzales County wells are oil and the other 5% is residue gas. I would expect that is probably more and 80/20 split, in general, in Lavaca County. The western part of Lavaca County would be more like Gonzales County as you go to the east. The liquid total oil and NGL component would decrease and the residue gas component would increase.

It's 95% oil in Gonzales and no NGLs, it's all oil in the 95%?

The 95% includes oil and NGLs.

How does that break down?

It is 89% oil and the other 6% is NGLs.

How would that 80% in Lavaca break down between oil and NGLs?

It is probably lower oil -- I can't give you exact metrics -- the percent oil would probably be less, the NGL component would probably be somewhat higher.

Is there a lot of running room if you are successful in your other prospect in the mid-continent?

Yes. There is acreage yet to be had. We have not disclosed nor will we disclose where it is at this time, for competitive reasons. But there is quite a bit of running room. In fact, we've probably got -- on the acreage we have, if this thing works, it is a fractured carbonate. As I said earlier, there's probably anywhere from 25 to 40 gross locations, probably 10 million to 15 million barrels of oil. It is material.

That is what you have right now?

That is correct.

You could add to the that. Do you have partners or are you doing to yourself?

At this time, we are doing it ourselves because of [pulling] issues in the state of Oklahoma. You'll have some partners by nature, but at this time, we do not have a JV partner per se.

Wells Fitzpatrick, Johnson Rice & Company.

Do your frack commitments change at all moving to two rigs. If you do have some extra slots, how do you plan on subleasing those, or what would you do with that?

We have a commitment for a number of pumping hours and days in a given month that we can roll over from one month to the next. What we have found is that with the efficiencies on the drilling side, that we can still have a complete inventory of frackable wells -- if you would -- to meet that obligation even with the lower rig counts. There's been a couple of instances we've had to, in the recent past, get a third-party out there. I think we used Halliburton to frack one of our wells because we had generated more than our existing contract could accommodate in one given month. Even with the two-rig program, we should be able to generate anywhere from 3 to 5 frackable, completable wells per month.

You talked about getting the costs down to $7 million to $7.5 million. Obviously, the first move from 10 and change to 8 was based on you tweaking the completion method. Is that the next move -- do you think those are coming from cost breaks or continued efficiencies?

It is mostly on the operations efficiencies. We have not seen a huge cost break, primarily because our rigs are under long-term contracts, our pumping services are also under a long-term contract. We did secure some wholesale profit from China that did drive down the cost of our profit to cover a period where those were rapidly rising. We have seen some of the profit costs moderate here recently, so we do see that profit cost coming down. But on the drilling side the goal is to drive our cost down in the $2.5 million to $3 million at rig release, and then try get her total completion costs in the neighborhood of $4 million. We have been able to do that just by multi-pad drilling, using the wholesale profit and optimizing the frack designs.

One more if I could -- the divestitures, any chance that you are going to do something like MLP or BPP or are those probably going to be just plain vanilla sales?

They, in all likelihood, will be plain vanilla sales. We don't have anything, probably, large enough to MLP, BPP, debt look-a-like, so we do not want to take on any more debt. Those, in all probability, are off the table, Welles.

Gary Stromberg, Barclays.

Back to Gregg's question on the borrowing base -- do know what price deck the banks are using for this round of borrowing base redeterminations?

Each bank has its own price deck. It is very individual and kind of complex. I would really hate to tell you JP Morgan's because I would not want to get you down some path where your are trying to calculate something that has a lot of moving parts, so at this point it is probably best to just leave it at what we stated in the press release, that we don't expect it to be materially below average our $300 million commitment and try to leave it right there. We will be updating you on our first quarter call with the actual determined rate.

And when you go in for that redetermination, will you look to relax the leverage covenants into 2013?

Probably not. We think we are okay right now, going into midyear of 2013. If we got towards the end of 2012 at looked like it was going to be necessary, then we might talk to the banks about it then. At this point, we don't plan to be anywhere near the point where it would be an issue. So we probably wouldn't want to stress the banks at that point, by asking for it now.

Stephen Karpel, Credit Suisse.

Can you quantify the cost savings you gained from the additional rig that you drop, maybe not cost savings, maybe the CapEx savings from going from 3 rigs to 2 rigs. Look at that on a 2012 basis to say the capital that is foregone versus the cash flow that is foregone from the wells that would have been gone?

A rig generally costs us about $100 million for a year, on a net basis. We were talking about releasing that third rig at the end of the first quarter, so it is 3/4 of that, just some very rough numbers. You're right. We would be giving up cash flow, so it is probably about a $65 million savings-to-debt at the end of the day, roughly.

Can you quantify that on a second year as well to see what the cash flow benefit -- foregone cash flow that would be in year two. Don't worry, I won't ask year three, I only wanted to get to two. [ Laughter ]

Unfortunately, I don't have that number at my fingertips, and I'd be afraid to mislead you if I tried to take a guess.

You mentioned --

Just to say one thing, our motivation is to get a third rig back as soon as it makes sense, for the very reason you are discussing.

Separately, earlier with the Eagle Ford, you talked about Mississippian lime acreage. Do you have additional targeted acreage in the Eagle Ford -- I don't want to say you are in negotiations with ort maybe you have partners and leaseholders that you have dealt with in the past that you could pick up more stakes if you had the capital?

Really it's just in and around where we already are. These are not typically larger tracks. Occasionally, we will have something brought to us like this large company brought to us here later last year. But we are not looking at any new areas. We continue to look, whatever divestitures may be out there on the market, a lot of them we do not like. We like exactly where we are. If Lavaca County works out, there may be some things that we could do in Lavaca County to add on to what we already have.

A couple of liquidity related -- I think it was the first question of the call mentioned about $100 million or so of availability at year-end '12 and you said, no, that is not our number. Can you give us some semblance of an idea of what is your target is it 200, is it 300, can you give us some idea of what you look at for liquidity?

Generally, we would like to have a leverage that is 300 or less, and we would like to have at least $150 million of a medium liquidity under the revolvers. Those would be some broad categories or targets that we're looking at when making decisions. We give you those cash outflow outspend ranges to communicate to you that we know what we're looking at and the gap we need to fill. As Baird mentioned, we're not going to go into proceed or anything right now. I can't tell you where we expect to be at the end of the year, but that is going to give you some guidelines on what we're looking at, what we're thinking about.

Then the revolver I think this is being appeared on -- but one way to ask it, the $300 million number that you alluded to in the civil be (technical difficulties) is that based on your conversations with the bank or is that based on your own internal calculations of what you think the borrowing base will be based on JPMorgan and the rest of the banks' decks.

It is based on early communications with the banks. We have not started the official process yet, but we have talked to them a little bit about where our reserves came out and what our plan is for the year. So it is a very rough estimate, but it is based on more than just our own internal analysis.

The 380 number you have had for 2011 or since the last redetermination, how is similar to that was your own internal calculation of what you thought the borrowing base it should be, was it in line, was it very conservative?

It was spot on. (Laughter). Kidding, sorry. I don't know that I can comment on that.

Are there any assets that were not in the borrowing base that could be pledged beyond what is already in?

They are all pledged.

We have no further questions in queue at this time.

Thank you, Abe. Appreciate the interest in the Company, and we look forward to the following phone calls. Thank you very much.

Thank you very much. Again ladies and gentlemen, that does conclude today's conference.