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

Whiting Petroleum Corporation (NYSE:WLL)

Q1 2009 Earnings Call

April 30, 2009 11:00 am ET

Executives

John Kelso - Director, IR

Jim Volker - President and CEO

Mike Stevens - VP and CFO

Jim Brown - SVP

Analysts

Joe Allman - J.P. Morgan

John Freeman - Raymond James

John Rabavino - Wachovia

Biju Perincheril - Jefferies & Company

Joseph Magner - Tristone Capital Inc

Mike Scialla - Thomas Weisel Partners

Operator

Good day ladies and gentlemen and welcome to the first quarter 2009 Whiting Petroleum Corporation Earnings Conference Call. My name is Francis and I will be your coordinator for today.

At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today's call, Mr. John Kelso, Director of Investor Relations. Please proceed.

John Kelso

Thanks Francis. Good morning everyone and welcome to Whiting Petroleum Corporation first quarter 2009 earnings conference call. On the call for Whiting's this morning is Jim Volker our President and CEO; Mike Stevens, our CFO; Jim Brown, Senior Vice President; Doug Lang, VP of Acquisitions and Reservoir Engineering; Mark Williams, Vice President of Exploration; Dave Seery, VP of Land; Bruce DeBoer, Vice President, General Counsel and Secretary and Chuck LaCouture, VP of Marketing.

During this call we will review our results for the first quarter and then discuss the outlook for the reminder of 2009. This conference call has been recorded and we will available for replay approximately 1 hour after it's completion. Both the conference call with an accompanying slide presentation and our first quarter 2009 earnings release can be found on our website at www.whiting.com.

To access the call and the website, please click on the Investor Relations box on the menu and then click on the Webcast link.

Please be advised that the following remarks including answers to your questions, includes statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act.

These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission including our Form10-K for the year ended December 31, 2008. We disclaim any obligation to update these forward-looking statements. I would also like to mention that our first quarter 2009 10-Q will be filed later today.

In this call, we use the terms, probable and possible reserves, which are unproved reserves that we do could not include in our SEC filings. Please refer to our website slides for more information on probable and possible reserves.

During this call, we will also make references to discretionary cash flow, which is a non-GAAP financial measure. A reconciliation of this non-GAAP measure to the applicable GAAP measure can be found in our earnings release

With that, I will turn the call over to Jim Volker.

Jim Volker

Thank you, John. Good morning and welcome everyone to Whiting Petroleum's first quarter 2009 conference call. We are looking forward to this conference call as we have a number of good operating statistics to discuss with you as well as in our opinion especially considering current oil and gas price levels, excellent financial results. So, we look forward to answering your questions that you may have following the presentation.

Two days ago we announced the closing of a new credit agreement which will provide Whiting additional financial flexibility whether we have improving or deteriorating conditions on oil and gas prices. The agreement replaces Whiting's previous credit agreement and increases the borrowing base from $900 million to $1.1 billion.

In our announcement we said that we had $1.042 billion of commitments are closing. Yesterday we were informed of another $58 million commitment thus bringing commitments and our borrowing base to $1.1 billion.

Today we announced a new capital budget of $420.6 million. Our objective for 2009 continues to be maintaining our current liquidity by funding our capital expenditures primarily through discretionary cash flow. We will focus our exploration and development expenditures on our Bakken play in North Dakota and our CO2 enhanced oil recovery projects. With the $420 million budget, we believe we can generate at least year-over-year production growth of between 8% and 10% in 2009. I would remind those of you that it's Whiting's practice to obviously risk the drilling that we have scheduled between now and year-end since most of that is at Sanish where we have had a 100% success ratio. We obviously believe our guidance here is something that we hope we can improve.

To the extent net cash provided by operating activities for oil and natural gas prices are lower than currently anticipated. We would adjust our capital budget accordingly. If net cash provided by operating activities is higher than currently anticipated we plan to reduce debt levels.

The driving factor in our plans to reduce capital cost in 2009 versus 2008 is the reduction in our operated rig count. At the height of our drilling activity in 2008. We were active with 18 operated drilling rigs and 51 operated workover rigs.

In response to lower commodity prices, we have reduced the number of operated drilling rigs to 6 and the number of operated workover rigs to 35 as of April 28, 2009. We expect our operated rig count to drop to four or five drilling rigs and approximately 25 workover rigs by June 2009. Despite current oil and gas prices, we believe we have carried our operational momentum into 2009 and expect to continue during the remainder of the year substantially all of our year-over-year production growth was organic.

Our average met daily production rose 32% to 54,320 barrels of oil equivalent in the first quarter up from 41,120 BOE's per day in the first quarter of 2008. Most of that production was due to our successful drilling results in the middle Bakken and from the favorable response of our two CO2 projects. Our average met daily production rate in the first quarter was 73% crude oil and 27% natural gas.

In North Dakota, crude oil sales volumes in the first quarter were effected by winter weather which caused delays in trucking operations and well completion activity. Despite these issues Whiting increased it's average met production from the Sanish field in the first quarter of 2009 to 8,890 BOE's per day up 11% from 7,980 BOE's per day averaged in the fourth quarter of 2008.

I would like to thank all of our people in North Dakota, our entire North Dakota team here in Denver, we are doing such a remarkable job during one of the harshest winters on record.

The company's net production from it's interest in the Parshall field during the first quarter of 2009 averaged 5,360 BOE per day, a 27% decline from the 7,320 BEO per day averaged in the fourth quarter of 2008. The principle operator of the Parshall field elected to defer the completion of 13 wells in the field until spring.

Completion of these 13 wells would have likely offset the natural decline of the other producing wells in the Parshall field. This was the primary factor for the 2.2% drop in Whiting's overall production from 55,540 BOE per day in the fourth quarter of 2008 to 54,320 BOE per day in the first quarter of 2009. We had production in the Parshall field then held slab from fourth quarter 2008 levels we would have shown a sequential increase in our overall net production in the first quarter of 2009.

We continue to generate what we believe to be very strong results in the Bakken play. We believe that our acerage position is located in the sweet spot of the play and that our drilling and completion techniques are very effective. This is evidenced by two recent prolific oil wells we completed in the Sanish field.

During a 24 hour test of the middle Bakken (inaudible), 11-16H flow to the daily rate of 3,405 barrels of oil and 2.9 million cubic feet of gas or 3,889 BOE per day. This is the second highest flow rate of any Whiting operated Bakken well. Our highest initial production rate was recorded at the Richardson Federal 11-9H which was completed in October 2008 flowing 4,570 BOE per day.

This well continues to hold the record for the highest initial production rate for ready Bakken well in North Dakota according to the North Dakota industrial commission. Approximately 2 miles to the Northwest, we completed the TTT ranch, 11-6H flowing at initial daily rate of 2,825 barrels of oil and 1.7 million cubic feet of gas or 3,102 BOE per day.

As this well all 36 of the Bakken wells that have been drilled in this Sanish fields since August 2007 have been completed as producers. A success rate of 100%. 8 of these have recorded initial production rates of over 3000 BOE per day. This is in our opinion a world class field found here in the lower 48.

Results from both of the infield wells that we have drilled to-date in the Sanish field continue to be encouraging. The Fladeland 12-18H drilled on our primary development plan of 2 wells per 1288 acre spacing unit was completed next to the Abbot 11-18H well to the north and Maynard Uran 11-24H and the Smith 11-20H wells to the south. The results from the Fladeland well continue to show no interference from the existing offset producing wells. The Fladeland well's initial production rates are also consistent with the production rates of other comparable wells in the area. This is a key fact evidencing further development.

We are completing our second Three Forks horizontal well in the Sanish field. The Hansen 21-3H.

Fracture stimulation operations on this well are scheduled for mid-May. The Hansen was drilled on the southwest side of Sanish where there is more separation meaning a greater interval between the middle Bakken and Three Forks. And whether our fewer natural fractures than on the east side of Sanish.

Based on these characteristics we believe that there will not be communication between the Three Forks and the middle Bakken. And that the Hansen well should be a good standalone test of the Three Forks formation.

As of April 20 we were drilling four wells and completing four wells in the Sanish field with average working interest of 91% and average net revenue interest of 74%. Its' important to note that we have been bringing down the completed well costs for our Bakken wells. The reduction in costs are the result of drilling and completion efficiencies that have reduced the average time from spud date to rig release to approximately 41 days from 60 days earlier in our drilling program.

The completed well costs for our most recent wells in the Sanish field are expected to range from approximately $5.5 million to $6 million per well which is down from $8 million to $10 million per well when the development project was initiated.

We expect further reductions as lower service material and equipment costs are realized over time. The final item I would like to address about the Bakken is that we expect our 17-mile oil line connecting the Sanish field to the Enbridge pipeline in the Stanley North Dakota to be in service in the third quarter of 2009.

The 8-inch diameter line will have a daily capacity of approximately 65,000 barrels per day. Enbridge has announced plans to expand its oil pipeline in Montreal County North Dakota. To a daily capacity of 161,000 barrels of oil per day from its current capacity of 110,000 barrels per day.

This expansion is expected to be completed in the first quarter of 2010. At our two CO2 floods average net production has increased to 14,300 BOEs per day. Comparing March 2009, March 2008 our average net production from the Postle and North Ward Estes fields has increased 25% to 14,300 BOE per day from 11,400 BOE per day.

At our Postle field in Texas County Oklahoma, four of the fields five units are currently active CO2 EOR projects. As of April 20, 2009 we are injecting 147 million cubic per day, CO2 into the field. Production from Postle has increased 27% from the net 6,200 BOE per day.

In March 2008 to a net 7,900 BOE per day in March 2009. Operations are underway to expand CO2 injection in the northern part of the forced unit. Known as the HMU unit and to optimize flood patterns in the existing CO2 floods with drilling rig and four work over rigs. Working in the field as of April 20, 2009.

These expansion projects include the restoration of shutting wells and the drilling of new producing an injection wells.

Our North Ward Estes field is also responding positively to Whiting's water and CO2 floods. Which Whiting initiated in Phase 1 in May 2007. In early March 2009, the company began CO2 injection in phase 2.

As of April 20, 2009 whiting was injecting 170 million cubic feet per day of CO2 in the North Ward Estes field. Production from North Ward Estes has increased 23% from a net 5,200 BOEs per day in March 2008. To a net 6,400 BOE in March 2009.

In this field Whiting has developed a new and reactivated wells for water and CO2 injection and production purposes. Whiting plans to install oil gas and water processing facilities in four phases through 2015. And we estimate that the first three phases will be substantially complete by December of this year.

With that I would like to turn over to Mike Stevens, Whiting CFO, who will discuss some of our key financial results.

Mike Stevens

Thanks, Jim. As Jim mentioned earlier we entered into new credit agreement with our bank syndicate that was arranged by JP Morgan. The new credit agreement expires in three years on April 28, 2012.

As of April 27, 2009 $610 million was drawn on the facility and $3 million in credit were outstanding resulting in $429 million of availability. We expect to add an additional bank to the facility today bringing total commitments to the borrowing base amount of $1.1 billion an increase in availability to $487 million.

The next regular borrowing base redetermination day is November 1, 2009. Our borrowing base was increased due to improvements in our reserve quality. Which more than offset the effects of using lower pricing assumptions. We believe this action provides further affirmation of our strong credit and favorable operating outlook, and it will allow us greater financial flexibility to operate in the case of an extended period of low commodity price.

First quarter of 2009 we reported a loss of $43.8 million or $0.92 per basic and diluted share and total revenues of $163.8 million.

Whiting's net loss in the first quarter of 2009 included after tax non-cash losses on hedging arrangements of $14.6 million or $0.31 per share. This compares to the first quarter 2008 net income of $62.3 million or $1.47 per basic and diluted share and total revenues of $264.1 million.

Discretionary cash flow on the first quarter of 2009 totaled $71.9 million compared to the $161.4 million reported for the same period in 2008. The decrease in discretionary cash flow and net income of the first quarter of 2009, was primarily the result of a 64% decline in the company's oil price, and 52% decrease in natural gas prices.

During the first quarter the company wide basis differential for crude oil compared NYMEX $10.66 which compared to $11.38 per barrel in the fourth quarter of 2008.

We expect our oil price differential to average between $9 and $10.50 during the remainder of 2009. Within the Bakken Whiting has operated production during April at an estimated differential of $7.50 per barrel.

In addition we expect their 17-mile oil line connecting the Sanish field to the Enbridge pipeline to be in service in the third quarter of 2009. We expect this event to have an additional positive effect on the crude oil differential in this area.

I would also like to point out that our cash costs on the unit of production basis are down more than 26% from the first quarter of last year. We expect to see further reductions in our cash costs as we move through 2009.

I will turn the call back over to Jim Volker for some additional comments on our operational activity.

Jim Volker

Thanks, Mike and with that I would like to. View the slides on our webcast which I hope will provide some additional color on our primary operating areas. Please give special note to our forward looking statement disclosure reserved information and non-GAAP measures. That’s seen on page 1.

Page 2 is just a quick outline of Whiting's current market cap I am sure you are all familiar with that. And our current debt situation which gives us debt-to-total cap at 37%. Still I might say even at the reduced oil and gas prices that we have today. 239.1 million BOEs reserve. So lot of reserves behind every share of stock and great RP ratio of 13.6 years.

Current production of 54,500 barrels a day. We are pleased to see this slide on page 3, 32% increase in the quarterly average daily production year-over-year. Moving to the reserve pie chart as you can tell the bulk of our proved reserves here coming in the Rocky Mountain and the Permian Basin.

Moving on to slide, 4. still even at what I would call this moderate oil and gas prices attractive margins with sales price net of sales price net of hedging, $32.97 in the quarter, still an EBITDA margin of 42% or $14.13 after exploration G&A production tax and lease operating expenses.

Moving on to page 5 here we breakout where are the reserves total 239 million BOEs and what percent is oil. And how we arrive at the 1.6 billion value based on NYMEX prices of 44.60 and 5.63 at 12/31/08.

As you can see the largest portion of the value being in the Permian basin and the Rocky mountains.

Moving on the slide 6, the highlighted points A and B of course are key to Whiting. Where we are continuing to see very moderate risk in fact I would say very moderate, very moderate risk growth from Postle and North Ward Estes, and significant organic growth potential drilling programs in Sanish and Parshall oil fields, for the Bakken.

And new projects in the Three Forks oil, I do not meant to leave out the Three Forks at Sanish which we think will be especially as we essentially to the western half of our acreage position there. There is an excellent chance to be another great separate risk.

Then of course with respect to gas the Sulphur Creek field, slides Boies Ranch and Jimmy Gulch prospects.

Moving on the slide 7, this is key to Whiting as I believe that over the next few years we will be able to move the substantial portion of these highlighted reserved volumes of probable and possible in to higher categories and as a consequence you can see there is a potential there to basically double the size of our reserve base. Where most of those P2 and P3 reserve is located if you look on page 8 you will see that where most of them are located and obviously significantly 78 million BOEs at North Ward Estes and another $49 million at Sanish obviously here is where we are working currently.

Moving on to slide 9 I would like to show the highlighted numbers on slide 9 as it shows really the history or the evolution of Whiting from a Company that grew primarily from acquisitions in '04 and '05 and then began to develop those, the un developed portion of the properties that we acquired in '04 and '05. As well as step out begin development of new areas such as our Bakken and such as our areas in the Piceance in 2006, 07 and 08. Such that currently on approved basis we would expect our all in F&D cost per BOE looking in the lower right hand corner of page 9 to be about 21, 25 and our including P2 would be three reserves driving it down to about $13 per BOE.

We've updated our net asset value calculations for you on pages 10 and 11 and we've run them at two different prices for you here, essentially prices that are near at least essentially prices that are near and at least any way the current price on oil looking at the 12 month strip of about 55 and using $5 per Mcf held flat on natural gas and arriving as you could see across all three reserve categories for at a net asset value per share of $62 and $0.76 that obviously improves on page 11 in the lower right hand corner to 94.84 at 65.6

Our capital budgets is shown I think clearly on page 12 how the $420 million is divided. I will give you the well count here with respect to each of these numbers in the Northern Rockies to $227 that's approximately 49 wells that 17 at Parshall one Sanish not operated and 31 Sanish operated wells in the Central Rockies that 26 million actually two wells the rest of it, so its about $6 million for Hatch Point and a Wasatch well. The rest of it is, the remaining 20 million is for some carry over costs and from 2008 in to 2009 facility seismic, and a moderate investment, our continuing investment at Rangely, in the Rangely Field with Chevron. In the Permian Basin, that 13.5 million was essentially carry over and facility cost from expansion of a water flood in the Keystone field.

And moving on down of course to our EOR projects that involves the EOR project including a number of wells in which we use work over rates as opposed to drilling rigs at North Ward Estes for $97 million and at Postle that actually covers the drilling as well as some facilities cost the drilling of 11 wells at Postle.

The $30.3 million there is indicated by the footnote as a combination of exploration salaries, seismic, delay rentals, etcetera. And in total therefore our well count this year of approximately 62 is anticipated.

On page 13 please I like to point out that we continue to shift reserves out of P2 and P3 and to P1. And as a result we continue to maintain approximately a 67% proved developed and 33% proved undeveloped, proved reserve base. Our proved reserves by core area show clearly that looking at the blue section here and the yellow section 76% of our reserves are there in the Permian and the Rockies.

And looking at the production chart, pie chart, 72% of production. Moving down to slide 14 please, I simply like to point out the 41% even though we have moderate oil and gas prices we can still direct 41% of our budget toward non proved reserves converting them in the proved reserves and thereby adding reserves as well as production. And that’s a testament I think to the economic viability of our projects at Sanish and Parshall and our two CO2 projects.

Moving to page 15, I always like to make this point in the lower right hand corner under net acres you can see that Whiting has 420,000 undeveloped acres and looking at the center of the map it's Rocky Mountain insert there you can see 326,000 of those are undeveloped net acres here in Rockies which do give us a lot of running room. And I'm very placed I might say that you have been able to see what we've been able to do with those acreage positions. Obviously at Sanish, Parshall, Lewis and Clark, and frankly some of the ideas that we will be bringing forward.

The Whiting base and Bakken activity is a good summary of it here on page 16 as you can see we have 199,000 growth, 101,000 net acres in Sanish and Parshall. We brought our drilling cost down to about 5.5 million but the EOR continues to range between about 700,000 and 1 million BOEs per well including all three reserve categories and we've got up to approximately 33 operated wells in the Sanish field 31 to 33 scheduled for 2009.

And we plan to participating up to 14 non operated wells primarily in Parshall with our friends of EOG who are doing a great job of operating and managing that field.

On page 17 just, a real like jus to kind of show two things on this map and that is that the green wiggly line on the west on the Western portion of this page the left hand side shows where we believe the sort of zone of maximum oil generation is and obviously Sanish and Parshall have all of the characteristics there for having my opinion on world class oil field.

So we as show that where we believe Sanish and Parshall is on the right hand side of page 17 and that they are definitely in the zone of active oil generation. So that's key to this area that is finding it not only where its been generated but where the conditions are correct for good for a good trap and where conditions are also good enough such that it has a sufficient porosity permeability whether it comes through metrics or fractures to result in the kind of flow rates and reserves that we've been able to see there.

In my opinion again world class Bakken cross section on page 18, it simply shows really the difference between the geologic conditions at Sanish and Parshall. Parshall is somewhat more fractured and does lack the dolomitic sandstone we see at Sanish. And which we believe is going to be and has proven to be already responsible for greater storage, greater reserves and obviously some very high flow rates. Our most recent well, of course coming at 3889 BOEs a day.

Moving on to page 19 we like to point out that here you can see with respect to both the white and yellow dots on this curve that obviously Sanish and then after it Parshall basically have a better results than about three quarters of the well Bakken wells in the state of North Dakota.

So again really at the top end of performance of all Bakken within the state of North Dakota. Our plans are laid out for you here on page 20. We've updated the count in the lower left hand corner of this particular slide. And I would like to point out to you here that as you can see from adding up to 17 and 16 number there that's approximately the 33 wells that we expect to act on. Some which are have been drilled or drilling or waiting on completion that's the 16 and 17 remaining budgeted wells in 2009, 56 of course current producers 84 additional permitted plant possible wells getting you up really it would just sort of a lines on this map to about a 173 wells that doesn’t really reflect any potential value here for the underlying Three Forks or for what I would call the third well, which we will put across in some cases across two units because the spacing pattern up there and drainage will permit it.

Just like to draw your attention to the greater results of all the wells that we've shown is inserts on the map 3100 to 1000 for Three Forks well 1000 BOEs a day for the Three Forks well that was very encouraging we think from the Braaflat and we hope that those results will improve as we move toward the Western part of the field and the Rigel State at 3889 the Fladeland, an infill well with 1765 there you see the location of our Robinson Lake gas plant where we continue to put more volumes through every day, and the McNamara infill well, which did. 2170 BOEs a day.

Page 21 really I think the far right hand side of this particular slide is the most important take a look at what's happened to our drilling cost please as we've driven it down now to about 5.5 million per well as we cut through the footnote at the bottom of the page. The number of days on location from 60 days to 41 days are less. Our last well was drilled in 38 days.

And as a consequence of both the rocks and I would say the way in which we drill and complete these wells we've been able to produce the results that you see on page 22 looking in the third column from the right. 2254 BOEs a day, during the first 24 hour test on average over the first 30 days 919 BOEs a day, and I would say most importantly on average over the first 60 days 801 BOEs a day. And really as we move to page 23 that performance is what is responsible for the tight curve that we see here where we believe currently that our results would typically range from roughly 700,000 to perhaps up to 1 million BOEs per well.

We created some new slides for you here, on page 24 and 25, moving to the left hand side of the page 24 here, you can see that as we look at the IRRs I will concentrate on the lower end of the IRR scale here. The IRR at $50 oil, $50 mix oil the IRR is here run from approximately 40% to 80% based upon either a 700,000 BOE or 1 million BOE well. ROYs run from about 2.5 to 4 to 1. Obviously at higher prices these things range up to IRRs between roughly 140% and ROYs between 4 and 6 to 1.

Moving on to how much PV 10 value is added per well, based upon oil price and reserves looking at the more conservative prices here at 50 we are adding between essentially $4 million and $8 million of PV 10 value that is over and above the recovering, the drilling completion cost. So, what is that result in, that results in the information you see on page 26, which I would point out to you indicates in the lower right hand corner that in looking at the finding cost in the Bakken and in this area Sanish on Whiting operated wells are finding cost per BOE using a 10 to 1 conversion, I think you all are aware that today it's about 13 to 1 conversion. So, in kind did natural gas the Bakken beats the Barnett, the Haynesville, and the Pinedale by coming in at without $7.90 per BOE compare to higher costs for those other three areas.

Moving on to page 27, we have done the same thing in terms of Mcfe and again at 10 to 1 the Whiting results here indicate F&D costs of about $0.79 in comparison to higher finding costs in the other three areas. I like to move on to page 28, please. We are in I can simply say that I believe that the Lewis and Clark area where Whiting has about 280 square miles under lease and we have 181,000 gross acres here. And where we have drilled one well in the Three Forks that came in at 1,000 barrels a day, another one didn’t quite that well because we drilled it out of a essentially well with lower casing, with smaller casing, so we couldn’t frac it as well. But nevertheless I believe that we are getting close to what I would call the solution number six here and that as I mean drilling grass roots wells here at about 6 million bucks per well and getting at least 600,000 BOEs per well, that is if we can achieve that I believe we’ll be in the range here roughly a solid three to one on our money at well prices assuming we can basically get a net here in the Bakken in this particular, Three Forks in this particular area of around $50 at the wellhead. And therefore about, so that would require let's say about $57, $58 NYMEX, so we're close here. Then we'll get in and I believe we began driving our drilling cost down here. Obviously if we get it closer to Bakken well close to 800,000 BOEs, you are looking at about 24 million in future net revenue for again a $6 million well costs were about four to one on our money.

So with that area it creates a lot of potential for Whiting and we’re just sort of keeping at the, from the status that it is until such time as oil prices recovers slightly. Moving to page 29, Sulphur Creek, Boies mentioned Jimmy Gulch in Rio Blanco County, Colorado, here we have got 31 Mesa Verde wells that have been drilled and 220 acre locations remaining at the Jimmy Gulch area, that’s the long narrow area in the left hand side of the map in both the, there at Boies Ranch on the left hand side of the map with both the dark, yellow, and light yellow areas that’s were we come up with the 220 acre locations.

More recently, we have moved out and stepped out to Jimmy Gulch which is square mile that we have under lease and where we drilled three successful wells that came in on a combine gross rate are just under 4 million a day and there is some additional 29 unidentified locations there on 20 acre spacing. I think a lot of people would like to know what the way think about the economics of gas in this area, and in generally, in general I would say we think that it sings at $5 gas. Because specially at Boies Ranch because we don’t any royalty here, we are on the minerals. At five bucks we hope to net $4 and $2.5 these, that’s about 10 million in the future net revenue and we hope to have CapEx here in the range of $2.5 million to $3 million of well. So, the potential for three to four to one at $5 NYMEX gas.

Similarly, at Flat Rock which I would like you to look at on page 30. In my opinion a great area to have in our pocket as oil prices recover. Here, kind of looking at the bullet points we’re currently delivering 11.3 million in cubic feet a gas a day. As of April 20, we believe that rate is going to go up not because we are going to drill more wells but because we are going to put relatively smaller amount of capital into improving our facilities and we hope to have that up there for into 15 million cubic feet a gas a day net here within the next few months. We do have 95% of our current production in from the Entrada. And just a kind of review here the potential of those 52 additional drilling locations, again if we can see $5 gas because of our lower operating expenses, I think we met about 70% of that and so if we can get as we have had in some wells are close to 8 Bcf per well and net about 350 per Mcf, that gives you about 28 million in future net revenue here and we hope to bring our drilling cost in at about 6.5 million. So $5 gas that’s four to one on your money project and we like a lot.

Moving on to Postle and North Ward Estes fields, just like to point out that our hat is off to our team in Midland, who really hit all marks, hit all the marks here in terms of executing on Postle to North Ward Estes. You can see production is up from when we bought them in June of '05 and these are just approved reserves showing in the graphs on the right hand side. We believe that it will be driving production up based just on proved reserves alone to about 9000 BOEs a day at Postle and little over 10,000 BOEs a day at North Ward Estes. Looking at the insert on the left hand side of this slide as you can tell, currently these two projects represents 47% of our reserves and 26% of our net daily production.

Overall, what are these projects do for us. You can see that clearly on page 32, essentially proved reserves alone and F&D, fully, an all in acquired and developed costs for proved reserves alone of 1782 and with the addition of the probable and possible reserves there driving our costs down to about $11.18. I am going to move quickly through next few slides here because they simply show in a lower right hand corner of page 33, that a lot of CapEx is behind us especially a Postle all the way through 2019 and including regards to purchase in CO2 only about 143 million remaining. And of course look at the results that Postle team has produced. What a great increase in production in 4,600 BOEs a day in March of last year to over 7,600 BOEs a day in May of this year.

Moving on to page 35, the same thing is true in the lower right hand corner. We just not quite as far along as we are at Postle here at North Ward Estes but that’s just because of the size of this field 23 miles long and three miles wide. But we are well over half way through the, what's called the hard CapEx period. It's only about 434 million you have to do and roughly half of that just in form of CO2. So not a lot of drilling completion and water restoration, gas plant cost to go only about 200 million of that. North Ward Estes as you can see on page 36 has responded well. It's flattened out here recently as we basically have prepared to go Phase II and it's on the up trend again.

Probably I would say the most encouraging thing we can see on page 37, with respect to the North Ward Estes flood, and that is that we have been fortunate here due to way in which the flood has been design and executed on by Midland and team on the field there. Our performance we believe, although we're early on having injected only about 25% of total hydrocarbon core volume here. Our early results here we believe do indicate that we’re more on the dark green line then we are on the dark blue line. So that means we have a good chance to add those probable and possible reserves that you see overtime here by that I mean over the next few years. And take them out of probable and possible. We have got a good opportunity here I think to shift those in proved reserves. That’s a lot of additional reserves as you can tell here basically in other 77 million BOEs alone. so that’s almost the third of Whiting's current existing prove reserve base. And then total therefore, the results on page 38 a Postle and North Ward Estes from March of last year to May of this years, we’ve driven it from roughly $10,000 BOEs a say to 14,000 BOEs a day.

And that results in what you see on page 39, which was that the combination of these two assets that is the Bakken, which I talked about in Postle and North Ward Estes given us 29,200 BOEs a day in March of this year and that 29,200 as a percentage of our 54,500 its 54% of our current net daily production.

And then, in finality, looking on slide 40, as of March 31 our debt-to-total cap 31.7% and just to reiterate ladies and gentlemen, we do have in our opinion at lease the five year inventory of drilling in front of us, properties that I have already mentioned and as I am outlining now on page 41, in the highlight of the section and we continue to be able to add what I call growth both in reserves and in production, a Postle and North Ward Estes. And of course, we have what I would call even more market, even more precipitous that is growth potential at Sanish, Parshall, and Lewis & Clark to say nothing of our gas prospects that Boies Ranch, Jimmy Gulch, and Flat Rock as gas prices I believe we will comeback long term.

With that Francis, I would like to open the conference call for questions, please.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And our first question is from the line of Joe Allman with J.P. Morgan. Please proceed.

Joe Allman - J.P. Morgan

Thank you, good morning, everybody.

Jim Volker

Good morning, Joe

Joe Allman - J.P. Morgan

Hi, Jim, you are producing somewhere around 13,000 barrels of oil from the Bakken, could you tell us why you're moving that and how much is through pipe and how much through rail and truck and what not, what do you think with differentials recently.

Jim Volker

Thank you for asking. It's all being trucked and we believe by the time we get no later than the end of the third quarter of this year, most of it will be in the pipeline, the differential there for us is currently $7.50. And it's come down obviously markedly from it was almost $18 during the worst times last year. And we're looking forward to further improvement on that. We hope to say essentially overtime, somewhere between $2 and $4 a barrel, as a result of first the recovery of our cost delaying that line. And then brining what I would call the transportation through the line down and that should save us in comparison to trucking between $2 and $4 a barrel. And we don't rail out anything. Our friends at EOG do rail-outs in barrels and that I believe this probably one of the reasons if they elected not to perhaps complete wells as we did during the winter time up there, they were suffering somewhat greater differential than we were. So I concur on their decision there not to complete this many wells during the winter. And I think it's a good decision on their part. We however weren't suffering quite as big a differential. So we when had completed our wells.

Joe Allman - J.P. Morgan

So the cost of trucking, you are saying as a roughly $2 to $4 per barrel?

Jim Volker

Its about 4 bucks now and we hope that as we get it into the third quarter of this year, then you will see a decline hopefully a couple of bucks and then after the recovery of cost of the gathering system and that line that we're putting in, it we should do better than that somewhere into ranges $3 to $4.

Joe Allman - J.P. Morgan

Great, and do you have any firm transportation on that line? I mean how much capacity do you think you will have?

Jim Volker

Well, let's thank you again for asking the line has a capacity of 65,000 barrels a day and our plan here is, there is a large industry marketing company crude oil marketing company they wants on that line. So Whiting essentially has permitted, we will lay it in the ground and at that point we'll sell it to them at our cost, which should plus a moderate mark up which should be around $6.6 million and so its not a very expensive thing to do. And in return for that, what we will get is priority, first priority on a 100% of this particular companies allocation, how much crude they can put into the Enbridge line, we will have a 100% of theirs and then combined with the allocation of another four purchasers, who put there crude into Enbridge we think that we will be able to mark up all of our crude unless we elect the market sum elsewhere, I would say at our option will be able to market all of our crude down that line.

Joe Allman - J.P. Morgan

Okay, got you, okay, and then I guess the cost of that, is there to the separate cost that we should look forward?

Jim Volker

Yes. Just try to, initially we think there will be roughly a $2 recovery of the expenses. So if we say truckings for, we will say $2 and then probably after around 36 to 48 months we'll bring it down probably another buck and half. I expect that there will be at least $0.50 or so operating cost.

Joe Allman - J.P. Morgan

Okay, very helpful. Thank you, Jim.

Jim Volker

Thank you.

Operator

Our next question comes from the line of John Freeman with Raymond James. Please proceed.

John Freeman - Raymond James

Hi guys.

Jim Volker

Good morning, John.

John Freeman - Raymond James

Good morning, can you elaborate some more on a what's drive in the big efficiency improvements that you are seeing in your Bakken wells getting down from 60 days to 41?

Jim Brown

Yeah, sure, John, this is Jim Brown, the guys have been doing a lot of things, when we run our swell packers out there, our liner with swell packers. We have been taking the time to ream to do a real careful job of reaming that hole that we drilled out there, that horizontal lateral. And we've been working on techniques, where we can eliminate that reamer run, that saves is about three days. Some other things our guys have done, one of the well we've recently drilled in 38 days. We’ve drilled the entire lateral with one mud motor run. So we were able to get the whole lateral done in one shot. And the guys are trying to figure out ways to make sure they can do that consistently. Also they are working just on the vertical part of the whole working on some efficiencies to try to reduce the time they takes and to get the vertical whole the curve built, and get the seven-inch casing set. So that's the approach they're really tackling right now.

John Freeman - Raymond James

Okay. That’s helpful, and then moving to that Lewis & Clark prospect in the slide, you said you have identified the next six wells. Is there any sort of timing you can give us, on when we would expect to hear, additional results from the area?

Jim Volker

Yes. When you see NYMEX around 58 bucks on the front end, that’s about when we’ll gear up and start going there yet.

John Freeman - Raymond James

Okay.

Jim Volker

Okay. Let me just explain briefly on Jim Brown's answer, all of those things that he talked about are part of our program here at Whiting that we call wells on paper, where we involve everyone from the office to the drilling contractor to the pumping service people in the field and our operations people in the field in order to have a plan for every foot of that well and how long it should take. That’s based upon our experienced in the field and what happen when it was done most efficiently, I mean we apply that to be entire, horizontal and vertical link through the well. That’s really been effective and driving our time on location and our cost down.

John Freeman - Raymond James

Okay. And then since you did kind of bring up the price sensitivity just, looks like during the quarter, you didn’t add any hedges and just with the strip in 2010, now north of 60 is that a price you would be comfortable starting to add additional hedges and do you have any sort of target in terms of percentage you like to be hedged.

Jim Volker

Okay, those are great questions, John, let me say that, well no final decision has been made here, because we put our hedges on about Thanksgiving time. What we did in order to get what I would call the profitable hedges that we have been getting paid on the front end then cash, is that we went to long, we went up to 2013, right? And that basically gave us an average from the front end to the backend high enough to get some profitable hedges on at that time and profitable hedges that are still on today. Some of the non-cash losses that you see in the income statement are the result of the fact that the backend has been coming up.

So well, we haven’t made a final decision on that, should well prices continue to sort of waffle where they are here in my opinion as we see what I would call earnings come in from the industrial companies in the United States. I am thinking that the backend may comedown a little, so we may lift some of those back end hedges and liquidate them even though, at what I would call breakeven or little better, I mean in 2012 and 2013, if possible. So might be a combination of '11, '12 and '13. And then put on replacement more hedges on the front end but using, again, costless collars to give us an opportunity to put on a floor that's acceptable. Currently, obviously, we have tried to show you here that we are I think making money and making good money on our CO2 projects and in the Bakken at essentially $50 oil in those areas. And so if we can get, floors that are around that area and ceilings somewhat higher than I think we do that predominately, let me answer your question, is yes, we would put on some more hedges, Mike can comment after me on the volume of hedges that we have, that we could put on, I am going to say the remainder of 2009 and 2010 and 11.

So that sort of the idea, John would to be not so far out, life those here, well we can that little or no cost and maybe put a few more on at the front end. I hope that's helpful.

John Freeman - Raymond James

I appreciate the color. And that's all I had. Thanks guys.

Jim Volker

All the best, John. Thanks.

Operator

Our next question will come from the line of [John Rabavino] from Wachovia. Please proceed.

John Rabavino - Wachovia

Hi, good morning, guys.

John Volker

Good morning, John.

John Rabavino - Wachovia

Can you walk me through the first quarter CapEx, I mean I am looking at $176 million in E&D. And I just want to see the run rate there it seems high little bit for the full year. I just want to see if you could break that down either geographically or by (inaudible)?

John Volker

Okay. Well, in summary I try to be relatively specific what you hear that how see it going. 176 in the first quarter, roughly 100 in the second quarter, roughly 73 in the third and roughly 71 in the fourth getting you to the so, that's how we kind of intend to bring it in and in terms of how that was done kind of you should by region that would have been in the range of around and this doesn’t necessarily include quite everything, but roughly in the range of around $9 million I think and mid continent around we gets about $100 million in the Rockies and about roughly the difference than in the Permian.

John Rabavino - Wachovia

I appreciate it.

John Volker

Permian was about 176.

John Rabavino - Wachovia

Okay. Can you compare that number to what I saw on PR for it, the total cash, it was investing activities is like $220 million number what's difference there?

John Volker

Difference is that the way that works from investing activities you have to put in your change in payable position from the end of the year to end of March.

John Rabavino - Wachovia

Okay.

John Volker

So as our payable decreased in increasing amount of cash that we had to lay out during the first quarter.

John Rabavino - Wachovia

Okay. And then looking at your first quarter production guidance back in February. What kind numbers I was backed in to that as far as weather impact and you see that EOG kind of pushed of 13 wells, was that something that you foresaw, or was that something I was baked into the guidance or just can you talk about that little bit more?

John Volker

It wasn’t. We didn’t know we are going to do that.

John Rabavino - Wachovia

Okay. And then one more just kind bigger picture on the full year CapEx budget. If you go back to the beginning of the year targeting call 8% to 10% growth on $320 million budget. Then the equity issuance came you guys raised the budget to $474 million and then also increased the growth rate to call it 12% of the midpoint. Now were backed at 420 but my growth targets are backed down where they were with the same budget of 320 if you follow me. Where is that additional $100 million going and how come there is not bigger uptick on the growth rates?

John Volker

Well, in general, I guess, I can always say this, yes, we have brought our target down. Yes, we have been conservative in terms of spending that CapEx, the capital that we raised with the equity offering. And in general that's because when we did it the 12 months trip was at little better than 58 bucks, okay. So we want to keep that power dry. Are we in comparison to where we were before being somewhat more conservative? I would say, yes, on our guidance we are, but in part keep in mind as I said early on my talk here that. We do risk our results going forward in the second, third and fourth quarter. We may have hit it little heavier than we needed to this time with risk in our guidance and we are hopeful that to maintain the same kind of success ratio that we have to date especially there in Sanish. So I realized that we have been somewhat more conservative on this guidance, but we are hoping that with continued results there we will be able to improve on that guidance and get us back into somewhat higher range. I hope that answers your question.

John Rabavino - Wachovia

Great. I really appreciate it. Thanks very much for color.

John Volker

All the best.

Operator

Our next question is from the line of Biju Perincheril from Jefferies. Please proceed.

Biju Perincheril - Jefferies & Company

Hi, good morning, everyone.

John Volker

Good morning, Biju.

Biju Perincheril - Jefferies & Company

Most talking of it the North Ward Estes production looks like its flat to down here, if that what you would have expected from phase one and before we see it turn around. Do you need to see response from phase two or?

John Volker

No, actually I would say really as I commented there that we were sort of moving into phase two, executing first part of phase two there, but really what happens to us was that as we got out there in the phase one we put a fairly big love to see two into the reservoir. We saw obviously a nice buzz out of that and we begin to put some water as there is a lag process out there. We did see bit of an issue with some build up on the tubing there, that took us roughly a month, month and half to work our way through that which we now I am going to say treat for as we complete wells. We basically put some chemicals in before we put the producers on production and that issue was gone away. And so, even I would say, Biju, without respect to the increase that we expect to see from phase two, I do expect to see lives and production from phase one as and hats off to the team there in Midland. I believe they did an excellent job of responding to that schedule.

Biju Perincheril - Jefferies & Company

Okay. And then where do you think phase one can peak out at?

John Volker

Again I don’t want get into too much detail here because we will be frank about it. There is just not movement because we are doing so much in the field both at phase one, phase two and then our two water flood restoration areas that best I would like to do is refer you back to that slide or you can see that we are going to get up to roughly 10200 BOEs a day.

And out of all proved categories and then we are hopeful as I said this is just obviously very interesting time for us here Whiting because the flood is responding writing because the flood is responding in a manner that would indicate that we are getting a higher response which would indicate a somewhat greater than the 5.5% based upon Chevron flood recovery factor and we're not far enough to long that I can call that in finality or tell you how many reserves we're going to add or for that matter be exact as to what the peak rate might be over and above that 10.2 roughly, 10,000 barrels a day improved.

We're hopeful that with the continued operation of the field in the manner that we're operating it which is different than the way Chevron did it, basically, they operated at about 50 psi and we're operating at about a 150 psi holding those pressures on the wells, what does that do? That causes pressure in the reservoir, in our opinion that means that liquids don’t fall out of the reservoir, it carries them up to the well bore better, we're not putting liquids back into the reservoir, Chevron was recycling those back in and that reduces the efficiency of your flood and so those two factors alone we think will resolve in a higher recovery factor than Chevron has.

How all those factors play out especially over about the next 24 months remains to be seen. I can only tell you that I am highly optimistic about the results that we're seeing today and the ability hopefully over the time to add that 78 million BOEs out there to our improved reserve base and I hope that’s an adequate feature.

Biju Perincheril - Jefferies & Company

It is. Thank you.

John Volker

Thank you.

Operator

Our next question comes from the line of Joseph Magner with Tristone Capital Inc. Please proceed.

Joseph Magner - Tristone Capital Inc

Good morning

John Volker

Good morning, Joe.

Joseph Magner - Tristone Capital Inc

Good morning. Just touching the follow-up on the early question that Jai asked. Understanding, you maybe more conservative in resting in capital investments, would have expected the difference in equity proceeds and cash to have shown up in lower bank debt balances and/or cash balances on the balance sheet. It looks like cash the bank facility the borrowings outstanding there were lower a the end of Q1 than they were at the end of 08 but they’re now back up in mid-April further in the release you added earlier this week. Can you provide any additional details on other capital investments and any other projects of acquisitions, or any other uses of cash in the first quarter that reserves revisions you’ve already disclosed?

John Volker

I’ll talk about two things, one is we had some additional two wheelers that we had under contract that we had to pay for in the first quarter. That was probably in the range of $20 million to $30 million and secondly, if you look at the page 17 of our press release, you can see our balance sheet there. If you look at the first seven line items, and you look at the difference in those payable balances from December 31st to March 31st there is a decrease from about $301 million and we're around $200 million so, as we wind our operations as the traffic slowdown has decreased or the payables that built up during the higher activity period have to be paid-off and that’s about a $100 million reason for the, where we're with our debt positions as well.

Joseph Magner - Tristone Capital Inc

So, I guess, the expectation, the banks debt would be or that I was saying debt would be paid-off with you know half of the proceeds with equity offerings essentially that those proceeds were used to pay down payables that were already expensed last year. Is that one way to look at or other way to look at it?

John Volker

Well, the proceeds were used to pay down debts and then debt was borrowed back as the payables came due. So, that’s the way I look at it.

Joseph Magner - Tristone Capital Inc

Got it, that’s an accurate, I think that’s accurate, so…

John Volker

Sorry, some of those payables are from last year and some were the first quarter, you know, as we've reportedly spend a $176 million. We incurred a $176 million of CapEx and our discretionary cash flow was $71 million. So, all those factors are why we're where were at with the debt.

Joseph Magner - Tristone Capital Inc

Alright

John Volker

And, really it’s just a momentum thing and as I sort of detailed our CapEx going-forward, you can see that we've had our foot on the break and I think we're going to be bringing that debt at $420 million number or we’ll see maybe a little bit less by the time we get to the end of the year.

Joseph Magner - Tristone Capital Inc

Okay, and you spend a lot of time on what’s left in the budget. Can you touch on $70 million in reduced spending and you know Rockies with a tag of $13 million to $14 million in the Permian Basin. What are those activities? Were you specifically pulled-out beyond, will you address that?

John Volker

You want to tackle that one.

Jim Brown

I’ll take a shot at it. In general, in the Permian Basin, it’s been just a kind of a decline in the number of work-over rigs that we're using there. As we wind down the when I say wind down, as we move through the project at the pace that was anticipated, we're just using some fewer work-over rigs out there as we work away through the project and then the Northern Rockies it’s basically just some fewer wells.

Joseph Magner - Tristone Capital Inc

Thanks for your comments.

Jim Volker

You’re welcome.

Operator

Our next question is from the line of Mike Scialla with Thomas Weisel Partners. Please proceed.

Mike Scialla - Thomas Weisel Partners

Good morning guys.

Jim Volker

Good morning.

Mike Scialla - Thomas Weisel Partners

Is the Hanson well down yet and if so is there anything you can tell from the logs in terms of fitness or proximity compared to the Braaflat well?

John Volker

Sure, go ahead Mike, we drilled the Hansen roll outs down in the Southwest side of the field, second Three Forks well and we saw encouraging shales when we drilled it and we're in the process, we've kind of started the process of completing it. We don’t yet have, it’s stimulated so we don’t know how it’s going to compare to the first well but we have stimulated the first three stages of the well and so far it has been encouraging, we dream a lot on how the remaining seven stages are going to do?

Jim Volker

We're optimistic. It’s – I mean this all looks thick and rich out there. It’s all we can say. So, we don’t have the final result for you yet. We’ll put some fun out when we get a good test on it.

Mike Scialla - Thomas Weisel Partners

Okay and then in terms of the Braaflat, Jim from your comments, I was wondering are you concerned that that well is drilling from Bakken or is there enough data that you can tell us at this point?

Jim Volker

Well, you got to take a look at that well, see, that well was only about 600 feet away from the Bakken well, okay, so, it’s closer than we would normally drill either Bakken to Bakken or going forward Three Forks to Bakken. Both would be spaced roughly 1500 feet apart and so as we go forward here we saw only before I could talk about going forward, when we frac that well, we saw an indication in one of the stages of the frac, we did see communication between what I would call a vertical fracture that runs from Three Forks up into the Bakken, but only one, one out of a ten stages.

So, the fact that that happen and it happen and we were able to see that in only one phase, is actually in our opinion an optimistic outcome and as a result, I would say as we move to the West, where the interval between the Bakken and the Three Forks expanse, where more and more optimistic about the Three Forks here being a truly separate targeted reservoir from the Bakken and not subject to drainage one from the other.

Mike Scialla - Thomas Weisel Partners

Okay. And you also mentioned in your comments about a third well per 1280 in the Middle Bakken and I assume that just to considering the Middle Bakken, that any plans that test that concept this year?

Jim Volker

No, not this year. First thing we want to do is drill a part of acreage out there, but I would say we have already proved that concept by the fact that those wells will be essentially the same distance apart, roughly 1500 feet, one from another as they are within each unit. So it just has to do with the setbacks on the leases, one unit from another, that you end up with another 15 with roughly about 3,000 feet and between the well, the southern most well in the unit on the north and the northernmost well in the unit on the south. So it is really the same spacing pattern just being applied across the two unit boundaries and it is really on just the land process where you go in and bring the two units together and the royalty owners and the unit to the north and the royalty owners in the unit to the south share the royalty from the cross unit well, so as required.

Mike Scialla - Thomas Weisel Partners

So, is the ultimate spacing going to be 640 acres or something less than that?

Jim Volker

Yes, slightly less.

Mike Scialla - Thomas Weisel Partners

And based on what you are seeing right now on the two wells, would that 700,000 to million barrels per well if you don’t see any interface going forward, that would be, you think, a good number to go with on a 640 acre spacing or not.

Jim Volker

We do.

Mike Scialla - Thomas Weisel Partners

Okay.

Jim Volker

Thank you.

Mike Scialla - Thomas Weisel Partners

Thanks.

Operator

Our next question comes from the line of David Tameron with Wachovia Bank. Please proceed.

Jim Volker

Good morning, Dave.

Operator

Please check your mute feature. And at this time, there are no other questions in the queue. I would like to turn the call back over to Mr. James Volker for closing remark.

Jim Volker

Thank you Francis. I would really like to underscore the excitement all of us here at Whiting, feel about continuing to execute on our Bakken drilling field as well as our Postle and North Ward Estes CO2 fields. These key projects showing declining completed well costs and operating costs.

We are very optimistic about Whiting’s operational results going forward. And I would like to mention several events that Whiting would be participating in over the next several weeks to may give us an opportunity to meet with you personally. We are going to be at the RBC Capital Markets Energy Conference at the Ritz-Carlton Battery Park in New York on Monday, June 1. We are also going to be presenting at the 21st annual COGA Rocky Mountain Natural Gas Conference here at the Colorado Convention Centre in Denver in the week of July 6. We look forward to seeing you at those events.

In closing, I would like to thank all of you on this call for your new or continuing interest in Whiting and in particular, I want to express my personal thanks to all of our shareholders, our banks, and Whiting employees and our directors, who have put us in a position to prosper at these oil and gas prices and to respond appropriately to improving, or for that matter, deteriorating oil or gas prices. I think Whiting is in a great position where we are right now. And we look forward to executing for our shareholders. Again, all the best and we look forward to seeing you and speaking with you again soon.

Operator

Ladies and gentlemen, thank you all for your participation in today's conference call. This concludes the presentation and you may now disconnect and have a great 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!

Source: Whiting Petroleum Corporation, Q1 2009 Earnings Call Transcript.

Check out Seeking Alpha’s new Earnings Center »

This Transcript
All Transcripts