Norman Swanton - Chairman and CEO
Tim Larkin - Executive Vice President and CFO
Ken Gobble - COO and President of Warren E&P
Steve Heiter - General Manager
Leo Mariani - RBC
Phillip Jungwirth - BMO Capital Markets
Phil McPherson - Global Hunter Securities
Warren Resources, Inc. (WRES) Q4 2010 Earnings Call March 1, 2011 10:00 AM ET
Good day ladies and gentlemen and welcome to the fourth quarter and full year 2010 Warren Resources earnings conference call. My name is Veronica and I will be your coordinator for today. At this time all participants are in a listen only mode. We will be conducting a Q&A session towards the end of today’s conference.
If at any time during the call you require assistance please press star followed by 0 and a coordinator will be happy to assist you. I would now like to turn the conference over to your host for today’s call, Mr. Norman Swanton, Chairman and CEO of Warren Resources. Please proceed.
Thank you. Good morning everyone. Thank you for joining us for Warren Resources’ fourth quarter and full year 2010 financial and operating results conference call. We are conducting the conference call this morning from our Long Beach, California office and with me is Steve Heiter, our General Manager in California.
Tim Larkin, our Executive Vice President and CFO, is joining us from our New York City headquarters and Ken Gobble, our COO and President of our operating subsidiary Warren E&P, is also joining us from our Casper, Wyoming office to discuss our operating results. Before I turn the microphone over to Tim to cover the financial results and then Ken to discuss our oil and gas operations, I’d like to briefly comment on our performance for 2010 and the future direction of the company.
Taken as a whole, we had an excellent operational and financial year in 2010. Our 2010 production was an estimated 1.7 million barrels of oil equivalent, a 9% increase from 2009, and our revenue increased 39% to 88.3 million compared to 63.4 million in 2009. Our earnings per share were 20.4 million for the year or 29 cents per diluted share compared to a loss of 13.8 million for 2009 or 23 cents per diluted share, representing an earnings improvement of 34.2 million in 2010 over 2009.
I note that our net income for 2010 was decreased by non-cash mark to market derivative loss of 1.2 million or 2 cents per diluted share. Our 2010 oil production volumes of 969,000 barrels of oil were at the high range of our previously provided production guidance. For 2010 oil and gas revenue was approximately 80% from oil production. Our continued focus on managing operating costs along with improved oil prices allowed us to generate a gross margin of approximately $58 per barrel after LOEs during the current quarter.
With high mix oil approaching $100 per barrel of oil, our realized oil prices in California are currently around $90 per barrel. I am very pleased with our 2010 drilling results in our California Wilmington Townlot Unit or WTU. Our successful 3D reservoir modeling combined with high tech horizontal and sinusoidal drilling is translating into a large development inventory currently consisting of 150-200 identified drilling locations in the Wilmington field with very attractive economics and real potential for significant production growth.
Since resumption of drilling at the WTU in April 2010 the company has drilled and completed seven new tar horizontal producing wells, one tar water injection well that’s awaiting a pending injection permit, one proof of concept sinusoidal horizontal well in the J sand in the upper terminal formation and one proof of concept sinusoidal well in the HX sand in the upper terminal formation.
The 30-day initial producing rate for the seven new tar producing wells averaged 152 barrels of oil per day per well. The newly drilled tar wells are currently averaging approximately 73 barrels of oil per day each, which is in line with our expected decline rate given the current limitations on water injection. Additionally, the sinusoidal horizontal well in the J sand of the upper terminal formation was drilled and placed in production on June 2010.
The first upper terminal well exhibited 30-day initial producing rates of approximately 225 barrels of oil per day and is currently producing 150 barrels of oil per day. I’m also pleased to report that our new all electric, soundproof drilling rig, which has specially designed air bearings for very low cost and rapid rig moves, is fully assembled at our WTU central facility and should begin drilling oil wells next week.
Over the next two months the company plans to drill and complete four gross 3.9 net additional wells in the WTU that will consist of two sinusoidal wells targeting the J sand and the HX sand respectively in the upper terminal formation, one sinusoidal proof of concept well in the ranger formation and one tar horizontal well to test a new fault lock. As we stated in our February 15, 2011 press release, we have filed applications for water injection wells that are currently pending before the California Division of Oil and Gas and Geothermal Resources or DOGGR.
However, because of the DOGGR’s personnel constraints and new, more rigid review and interpretation procedures, these water injection permits are now taking longer to be approved than previous permits. Also due to the volume of water being injected into the upper terminal formation and the corresponding rise in reservoir pressure in the last few weeks, we have elected to temporarily shut in approximately 300 net barrels of oil per day, approximately 110,000 barrels of oil annually, from lower producing, higher water cut wells until water injection wells are obtained for the tar and ranger formations.
We estimate that with proper water injection the tar formation could produce approximately 20,000 barrels of oil more during 2011 compared to current levels. If DOGGR permit approvals are obtained as anticipated in the summer and fall of 2011 or earlier, we believe that these temporarily shut in wells will begin to return to production in late 2011 and eventually return to full production during 2012 and 2013.
In the interim we are actively examining other ways to temporarily handle the excess produced water such as trucking or transporting it by pipeline to another location. If the company is able to handle this excess water the wells that are temporarily shut in will be brought back on production sooner than currently anticipated.
On the natural gas side of our business even though we have not drilled any new wells in 2010 in our Atlantic Rim coalbed methane natural gas project in the Washakie Basin and in Wyoming, our fractious stimulation program and well optimization increased our natural gas production for 2010 by 21% to a record 4.7 billion cubic feet of gas equivalent compared to 3.9 bcfe in 2009.
To remind everyone, we have previously identified 560 CBM well locations and potentially up to 1600 well locations in the Atlantic Rim CBM project. Additionally, we own 80,000 net acres in the Washakie Basin below the CBM play, which is prospective for Niobrara oil. We will be participating in wells to be drilled in the Niobrara in 2011.
We anticipate most of our prospective Niobrara acreage will be held by our newly approved mega units in the Atlantic Rim CBM project. Our liquidity position is strong and although we have some permitting challenges in 2011 I continue to believe that our long-term outlook has never been better. We will continue to build an environmentally sound foundation that delivers strong growth in domestic production, reserves and profitability for the years ahead in our core US drilling areas. With that overview I will turn the call over to Tim Larkin our CFO. Tim.
Thanks Norman. Before I discuss the company’s financial results released earlier today I would like to remind everyone that all statements made during our conference call that are not statements of historical fact constitute forward-looking statements and are made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.
Actual results could vary materially from those contained in the forward-looking statements. Factors that could cause actual results to differ materially from those in the forward-looking statements are described in our Forms 10-K and 10-Q, other periodic filings with the SEC and our press releases. As Norman mentioned, we had a good fourth quarter. Our cash flow from operations continued to improve our balance sheet and liquidity position.
Also we placed seven tar wells in one UT upper terminal sinusoidal well on production since we recommenced our oil drilling program in April of 2010. The results have been encouraging. We plan to resume oil drilling in the WTU next week. During the fourth quarter of 2010 we paid down $13 million of debt under our senior credit facility. As of December 31, 2010 we have $50.5 million available under our senior credit facilities.
We have now paid down $45.5 million of debt during the last 15 months. Additionally, during September 2010 we acquired an oil drilling rig for $10 million including assembly costs. This rig was specifically manufactured for onshore drilling operations in southern California. Today we reported net income of $311,000 for the quarter or 0 cents per diluted share and adjusted net income of $5.4 million or 8 cents per diluted share excluding non-cash unrealized losses from hedging activities of $5.1 million.
Additionally, during the quarter we generated $11.5 million of cash flow from operations, an increase of 45% over 2009. Also we increased our oil and gas production to 435,000 barrels of oil equivalent or 4700 barrels of oil equivalent per day for the quarter. Production from our two oil fields in California totaled 240,000 barrels during the fourth quarter, a 1% increase from the 237,000 barrels produced during the fourth quarter of 2009.
Additionally, natural gas production primarily from our Atlantic Rim project in Wyoming, was strong and overall natural gas production increased 15% to 1.2 billion cubic feet during the fourth quarter compared to 1 billion cubic feet during the same period in 2009. The average realized oil price for the fourth quarter was $77 per barrel compared to $68 per barrel during the fourth quarter of 2009, an increase of 14%.
Our fourth quarter Wilmington oil differentials from NYMEX prices were approximately$8 per barrel. Also during the fourth quarter we had a realized gain from hedging activities of $1.1 million and an unrealized non-cash mark to market loss from future hedges of $5.1 million. Our average realized gas price for the fourth quarter was $3.51 per ncf compared to $4.05 per ncf in the fourth quarter of 2009. As a result of increased oil production and improved commodity prices, oil and gas revenues for the fourth quarter increased 12% to $22.6 million compared to 2009.
Total operating expenses increased 9% to $17.4 million during the fourth quarter of 2010 compared to 2009. Lease operating expense increased 1% to $7.2 million due to increased maintenance and plugging and abandonment projects in California. We expect oil LOEs to average approximately $19.50 per net barrel in 2011. VD&A for the fourth quarter increased 33% to $6.5 million compared to the fourth quarter of 2009.
VD&A was $14.85 per BOE during the fourth quarter of 2010 compared to $11.94 per BOE during the fourth quarter of 2009. This increase in VD&A on a BOE basis resulted from higher estimated future development costs as of December 31, 2010 compared to 2009. General and administrative expense decreased 8% to $3.7 million during the fourth quarter of 2010. This decrease resulted from a $1.3 million litigation accrual recorded in the fourth quarter of 2009 offset by a $600,000 incentive compensation accrual recorded during the fourth quarter of 2010 relating to our year end incentive compensation plan.
Also during the fourth quarter the company recorded non-cash share based compensation of $504,000. Interest expense decreased 30% to $851,000 as we continued to pay down our outstanding balance on our credit facility as previously mentioned. Net cash provided by operating activities was $11.5 million during the fourth quarter of 2010 compared to $8 million during the fourth quarter of 2009. For the full year 2010 we reported full year 2010 net income of $20.4 million or 29 cents per diluted share and adjusted net income of $21.6 million or 30 cents per diluted share excluding non-cash unrealized losses from hedging activities of $1.2 million.
Additionally, during the year we generated $45.3 million of cash flow from operations, an increase of 101% over 2009. Also we increased our oil and gas production by 9% to 1.7 million barrels of oil equivalent or 4800 barrels of oil equivalent per day for the year. Production from our two oil fields in California totaled 969,000 barrels during 2010, a 2% increase from the 951,000 barrels produced during 2009.
Additionally, natural gas production primarily from our Atlantic Rim project was strong and overall natural gas production increased 20% to 4.7 billion cubic feet during 2010 compared to 3.9 billion cubic feet during 2009. The average realized oil price for 2010 was $71 per barrel compared to $54 per barrel in 2009, an increase of 33%. Our full year Wilmington oil differentials from NYMEX prices were approximately $7 per barrel. Also during 2010 we had a realized gain from hedging activities of $2.7 million and an unrealized non-cash mark to market loss from future hedges of $1.2 million.
As a reminder, during the second quarter of 2010 when the price of front loaded NYMEX contract for oil was below $70 per barrel, the company repurchased 31% of its 2011 oil swap for $2 million. The 2011 oil swap has a contract price of $61.80 per barrel. This reduced our 2011 swap from 1225 barrels of oil per day to 840 barrels of oil per day or a reduction of approximately 141,000 total barrels.
Then during October 2010 we entered into a NYMEX oil costless collar for calendar year 2011 for 700 barrels of oil per day or approximately 256,000 total barrels with a floor price of $70 per barrel and a ceiling price of $101 per barrel. Our average realized gas price for 2010 was $4.09 per mcf compared to $3.09 per mcf in 2009.
As a result of increased oil production and improved commodity prices oil and gas revenues for 2010 increased 39% to $88.3 million compared to 2009. Total operating expenses increased 10% to $66.2 million during 2010 compared to 2009. Lease operating expense increased 6% to $28.8 million due to increased maintenance and plugging and abandonment projects in California.
VD&A for 2010 increased 7% to $22 million compared to 2009. VD&A was $12.61 per BOE during 2010 compared to $12.88 per BOE during 2009. This increase in VD&A on a BOE basis resulted from higher estimated future development costs as of 2010 compared to 2009. General and administrative expense increased 21% to $15.4 million during 2010. This increase resulted from an increase in payroll expense and an increase in performance based incentive compensation for 2010.
Also during 2010 the company recorded a non-cash share based compensation on expense of $2.4 million. Interest expense decreased 41% to $3.5 million as we continued to pay down outstanding balance on our credit facility as previously mentioned. Net cash flow provided by operating activities was $45.3 million during 2010 compared to $22.5 million during 2009. Our forecasted 2011 capital expenditure budget is $59 million.
This includes expenditures of approximately $28 million for drilling 14 producing wells and two injection wells in our WTU oil field in California and $14 million for related infrastructure costs in our WTU and NWU oil fields. Additionally, we forecasted $13 million for drilling gas wells, $3 million to drill an exploratory Niobrara oil well and $2 million for infrastructure costs related to our Atlantic Rim project in Wyoming.
As I previously mentioned, we expect to fund our 2010 capital expenditure budget primarily with cash flows from operations. Our borrowing base on the credit facility is $120 million. Our next redetermination is scheduled to be completed in April of 2011. Due to our strong liquidity position and the lender’s fees associated with increasing our borrowing base we did not ask our lenders for a borrowing base increase at our last redetermination in November 2010.
As mentioned, Warren has entered into certain oil and gas price swap contracts, costless collars and NYMEX to CIG differential swap contracts. As a result, the company has locked in a minimum level of cash flow from operations. Additionally, as operator of the WTU and NWU oil assets in California and co-joint venturer of the Atlantic Rim project with Anadarko, the company has the ability to modify its capital expenditure budget as commodity and financial markets change.
We reported first quarter and full year 2011 production guidance in our press release disseminated February 15, 2011. Now let me turn the call over to Ken who will provide you with a brief operational update. Ken.
Thank you Tim. Warren’s new drilling rig is now fully assembled and has been moved over the first well location in the Wilmington Townlot Unit. We expect to spud the first well of our 2011 drilling program next week. This well will be a sinusoidal horizontal well in the upper terminal J sand formation.
The company plans to follow this well by drilling sinusoidal horizontal wells to test the upper terminal HX section and then the ranger formation. The fourth well in this program will target the potential of new tar D1A reserves on the east side of the unit and fault block 2. The company currently has no reserves booked on the tar formation on this side of the fault. Once we have finished the first four wells we have scheduled a short pause in drilling activity in order to assess the results prior to the second phase of our 2011 drilling program.
In total we plan to drill 14 producing wells and two injection wells in the WTU this year. The company has experienced delays in the process of permitting new injection wells in the WTU. The California Division of Oil Gas and Geothermal Resources adopted a more rigorous permit application process during 2010. Some time was required to accumulate, incorporate and present the additional information now required in a format that was acceptable to the California Division of Oil and Gas.
This in combination of California state budget cuts reducing the agency’s available man hours and other issues has resulted in a backlog of pending injection well permit applications. The company continues to experience forward progress in resolving this matter and expects to receive an agency decision on the first of our 12 pending permit applications subjected to the new process around the middle of 2011.
In the meantime we are evaluating alternative methods to deal with reduced water from WTU in order to bring the field back to maximum production levels as quickly as possible. In the company’s North Wilmington Unit we have committed $7.8 million in capital to upgrade the production water handling facilities. This work should be finished in late 2011 in order to accommodate anticipated increased oil production from the NWU when drilling activity is resumed in early 2012.
We have approximately 28 available drilling locations at Satellite 7 and are evaluating the positioning of a second central drilling site for future NWU horizontal development. In the Atlantic Rim Warren and partners have formed the new Spyglass Hill unit. Spyglass Hill will include the areas previously committed to the Dobie Mountain, Sundog, Jack Sparrow and Brown Cow units as well as all additional leases in the southern portion of the project area.
This unit will allow for more efficient development and utilization of infrastructure in addition to allowing development to occur in a more concentrated manner from the central core of the project. The Catalina unit will remain unaffected by the formation of the Spyglass Hill unit. Warren plans to participate in the drilling of 25 new wells in the Spyglass Hill unit and 20 new wells in the Catalina unit in 2011.
We continue to evaluate the potential of Warren’s Atlantic Rim acreage for unconventional Niobrara oil development. We have become more optimistic as this work progresses. We expect to share more specific details on this work as our evaluation moves forward during 2011. Thank you for participating today and now I’d like to turn the call back over to Norman.
Thank you Ken. Operator, we’ll now take questions.
Question and Answer Session
Ladies and gentlemen if you wish to ask a question please press star followed by 1 on your touchtone telephone. If your question has been answered or you wish to withdraw your question press star followed by 2. Questions will be taken in the order received. Please press star, 1 to begin. And your first question comes from the line of Leo Mariani from RBC. Please proceed.
Good morning. I want to follow up on your comments on transporting some of the oil and water here out of WTU. What’s kind of holding you back from trucking some of that water out of there? Maybe just kind of walk us through some of the issues surrounding that.
We’ll have Steve address that question.
Leo, this is Steve Heiter. We have started that process a few days ago. We had to install some transfer lines to our facility at NWU and we are now transporting water from WTU to NWU. This is a short-term fix. Obviously we hope eventually to be injecting that water at WTU when we get our permits approved. But we should be able to transport maybe 1500-2500 barrels a day of water from WTU to NWU.
Okay. And what percentage of the produced water is that roughly?
That’s approximately 10%. We’re making about 20-25,000 barrels of water per day at WTU.
Okay. I guess with respect to Warren’s oil production volumes, they dropped from the third quarter to the fourth quarter and you guys are forecasting they’re going to drop again in the first quarter here. So we’ve got a couple quarters of decline due to some of the water handling issues primarily. Can you talk about what the change in oil cut has been in California over the last couple quarters here? Has that moved down here the oil cut?
Well, the producing oil cut - I don’t know exactly what it is Leo today, but it is going up because the wells we’re shutting in are the higher water cut wells. So I can’t tell you exactly what it is today but obviously it’s moving up just a little bit because of the high water cut wells that we’ve shut in.
We’ve shut in approximately 7,000 barrels a day over the last month and those are all high water cut wells.
Yeah. Cut’s not really the issue, Leo. I’d say it’s more natural decline coming off that drilling program in ‘10.
Okay. That makes sense. All right. So I guess the other comment you folks made is you’re feeling more optimistic about the Niobrara. I guess just can you tell us the timing of the well you plan to drill? Is there going to be more than one well? I wasn’t sure if there was. It sounded like there could be some non-operating activity as well. And just give a sense of what geological work you’ve sort of done on the play that gives you more confidence there.
We first started really concentrating on the southern portion of the area Leo thinking that the northern end was primarily in the gas window. And recently we have found one well that wasn’t in our log inventory that really looked attractive and we actually spread our focus area that we were looking at data from outside of our lease position to try to include more logs.
And initially there was no question that our feeling was what I would refer to as the chalk section in the Niobrara there compared to other successful areas, primarily the DJ, didn’t look very similar at all. I think the Atlantic Rim as I had mentioned prior is a lot more near shore in that positional environment. I wouldn’t even really refer to those as chalks. I think they’re probably more sandy shales and siltstones than carbonaceous chalk.
But we also recognize that most of the oil that’s been produced over there has been coming out of the shale and not out of that chalky section. And we also noticed that almost every place the Niobrara has been tested in our lease area has resulted in commercial production. And I would go further to add that now that we have a very more complete set of logs from a bigger area, I think probably you’ll see our initial move in exploration will probably be more in a vertical well than a horizontal well movement.
And I say that because the Niobrara there in the Atlantic Rim is almost 2000 feet deep and almost every mud log that we’ve seen where the Niobrara has been tested there shows and it’s not in a specific area of that 2000 foot section where you would know right where to lay the lateral. And all the wells in there that have been successful have been air drilled. So every structure that has been tested has been commercial.
And now our challenge will be to try to move off of those structures and see what the other areas where we believe we would find the shale fracture is going to look like. And perhaps I’m starting to lean more towards the recommendation of starting with perhaps 3D seismic surveys as opposed to drilling. But as you mentioned, we do expect some third party non-operated wells to go down in that area this year and we’re real excited to start seeing some drilling results. I think the chances are very good that we’ll see some commercial results in 2011.
Okay. And I guess you referred to some of the well bores you’ve got to take a look at that had produced commercially from the Niobrara in your acreage. Can you tell us how many well bores that was?
You know, it appears to us there are probably around eight wells that produced and if you take an average per well EUR they compare almost exactly with the results from the horizontal wells and silos that were drilled in the ‘90s - somewhere 130,000 barrels a well. And there are two wells in there that have produced over 300,000 barrels from the Niobrara. That’s some of the best vertical Niobrara production in the State of Wyoming if not the best.
Okay. And is that primarily oil or do you have the split on oil and gas there?
That’s just oil. The two wells did roughly - one of them did about 350,000 plus barrels of oil and about a quarter of B. The other well looks to be about 310-320,000 barrels of oil and over 200 million gas.
Okay. Thanks a lot guys.
Your next question comes from the line of Phillip Jungwirth from BMO Capital Markets. Please proceed.
Good morning guys. What are the expectations for the sinusoidal ranger wells? And then how does that compare to the tar and upper terminal wells?
Steve, do you want to handle that?
Sure. This well will be the first sinusoidal well that we’ve drilled at WTU. We have drilled six wells at NWU with economic results so our expectations are pretty high. We’ve got quite a few wells on the drilling inquiry in the ranger and we’re excited to see what’s going to happen over the next month or so.
There has been a lot of technical work done in the last 18 months on this and so we’re anxious to see what’s going to happen.
I think from an EUR perspective it’s probably safe to assume that they’re going to be very similar to the tar results. That J sand well that we drilled in 2010 I think our third party reserve engineers booked approximately 225,000 barrels on that and I believe it could be much higher as we continue to obtain production history from the well - maybe double.
Similar results to the upper terminal, not the tar, right?
That’s from the upper terminal, that’s correct. But I’m saying that I would expect both the ranger and the upper terminal EURs to be similar to what we’ve seen in the tar.
Our anticipated results are about 135,000 reserves per ranger well. That’s what we’re using in our economics and I think those are reasonable expectations.
Okay. And then the second upper terminal well that was drilled, was that drilled in the separate fault block than the first? And then how could this have impact on success? And then are all the new or 2011 upper terminal wells being drilled in fault block one or two?
The second upper terminal well was drilled to the east of the batting fault, which would be fault block two. And that is a separate fault block from the first upper terminal well, which was drilled to the west of the batting fault. And our initial UT wells in the next month will be on the east side close to 2161, which was the first well that we drilled.
Okay. And then the problem that you had with the second upper terminal well, which encountered water in the last 2000 feet in the lateral, is that something you think is preventable in future wells? Or how would you go about avoiding this problem in the future?
I think it’s preventable. The shows in the top half of the well were very, very good. And so we have plans later this year to fit this well into our drilling schedule where we’ll go in and cut and pull the screen and redrill it and just to the top half. And I would say it’s preventable - the problem with sinusoidal wells as you know, is as you’re drilling you’re repeating looking at the same formation over and over again. It’s just further out.
And so we should be able to see as we’re drilling the well any additional water that we’re drilling through and we actually saw it on this well. We just anticipated going back into less water cut as we got deeper and that didn’t happen. So we’re going to drill wells like this as we continue our drilling program. Some areas are going to be swept with water from the previous injection and some are not. But we anticipate now that we’ve drilled this one to be able to recognize that when it happens.
Okay. And then last on the 2011 capital program, it looks like you aren’t drilling any of the oil PUDs. It looks like all the wells are targeting unproved locations. Is there a reason for this? Is it mainly just due to the reservoir pressures in the tar that you laid out or can you expand on that?
Go ahead Steve.
Because of the lower reservoir pressure in the tar because of a lack of water injection, that’s why we’re staying away from the tar for now. We have approximately 20 additional drilling locations in the tar. We’re going to wait until we get the injection pressure back up and also when we are able to install our new cleaning flow burner, we’ll be able to produce more gas. So there are two reasons for it.
One is the injection pressure and one is the ability to handle the gas that we would expect from the tar formation. And we should have that resolved with the AQ&D later in the year.
Okay. Great. Thanks guys.
Again to ask a question please press star, 1. And your next question comes from the line of Phil McPherson from Global Hunter Securities. Please proceed.
Good morning gentlemen. I was wondering if you could give us a little bit of a 30,000 foot view on the infrastructure issues in Wilmington. In particular, what is your total water handling capability and what is your total oil capable handling ability?
At the Wilmington Townlot Unit, WTU, we have been producing as much as 30,000 barrels of water per day. Our facility handling capability when we get the new facilities in towards the end of the year, we’ll at least double that ability. And we would also be approximately increasing our oil handling from maybe 35-4000 barrels a day up to 5-6000 barrels a day.
We will be limited with our AQ&D permits to an average of 5000 barrels a day over a month’s period. So that’s WTU and at NWU our current capacity for water production and injection is approximately 20-30,000 barrels a day and on our budget for this year we have a significant amount of money to upgrade our water facilities. That will be done by the end of the year before we start our drilling program about a year from now. And that will increase our capacity by 50-100%.
And what’s the oil capacity at NWU?
Well, the oil capacity would be in the range of probably 2500-3000 barrels a day or higher. We’re pretty much unlimited on the oil side because we have replaced all of our oil tanks. We’re modifying and upgrading our heater/treater system. And so our oil processing ability is not going to be the issue. The issue would be on the water side. And we would have excess capacity for our plan development program over the life of the field. We will not be limited with respect to oil or water handling capacity.
Great. And at WTU the AQM, the air quality stuff, are you going to I guess apply for a greater permit down the road? Or do you need to start doing that now in anticipation of 2012 or 2013?
We will start that project after we get the permits for the existing equipment that we have applied for. As soon as those permits are received, which we expect to be maybe third quarter of this year, then we will start the process for increasing the capacity further.
Great. And when you talk about these permits, how do they - I’m just a little naive on like when you submit a permit for a water disposal well is there a volume number associated with it? Or how does that work? Like is each one 500 barrels that you can use for an injector or 10,000 barrels? Or what’s kind of the thought behind that?
There is no limit on the injection allowed. What the limitation has to do with is injection pressure. You certainly do not want to exceed (unintelligible) - that’s one of the stipulations. So what’s holding it up now - typically when you apply for an injection well permit it might take a couple of weeks.
But starting about 12 months ago the Division of Oil and Gas started looking at these applications with respect to impact on old, abandoned wells within a quarter mile radius of where you wanted to inject. And some of these wells were abandoned in the ‘30s and ‘40s and were not abandoned to today’s standards. And so the concern is that as you’re injecting water that if you have an old abandoned well that was not abandoned properly you could have injection water going up that old abandoned well and exiting into one of the zones that’s not intended.
And so the Division of Oil and Gas has to look at all these wells surrounding the injection well within a quarter mile. We submit schematics of all these old wells, how they were abandoned and there might be as many as maybe 100 old wells within a quarter mile that were abandoned and we have to submit schematics for all those wells. And they review them one by one to make sure that they were abandoned and can isolate the water to the intended zone of completion.
And that’s what’s taking them so long to approve these wells. And right now we have the wells that are on top of our list to be reviewed and approved so we’re in a pretty good position. We have half of the wells sitting on the Division of Oil and Gas’s desk to be reviewed. Half of them are our wells. So we’re in a very favorable position even though it’s taking longer than we hoped. We’re in a good position for getting these wells approved.
And if you found a well that was not or that was of a concern, would you guys then be able to go out and re-P&A it and clean it up? Is that how it would work?
Theoretically you can. We found some that were under apartment buildings. And so those obviously would be difficult or impossible to do. So in a couple of instances we changed the design of our exemption well - the path of the well so that it wouldn’t come within a quarter mile of some of those wells that were poorly abandoned.
Now we can’t do that in every case so we’re working with the DOG on a couple of alternatives perhaps to monitor pressure at the monitoring wells to make sure that if we do have issues that they’ll be recognized. So we’re working very closely with the Division of Oil and Gas. Two or three times a week we have either telephone or face to face discussions with them to come up with alternatives to perhaps some of these problematic, old, abandoned wells.
And Steve, how deep are you permitting the water disposal wells and could you potentially just go deeper and get below a different gradient as far as the pressure?
Well, we’re typically injecting the water back into the zones it’s produced from and that would be the tar, the UT and the ranger. Now when we start development of the deeper ford zone, that would also be a water flood so that would be another place you could put it. But you want to put the water back in where you produced it from because there are subsidence issues in Long Beach and you need to keep the reservoirs pressured properly. Every barrel you take out you want to put back in.
Got you. And have you guys looked at I know some other basins use polymer treatments to cut back water. Have you guys ever done anything like that in your fields? Is that applicable?
Well, we tried that on this UT well that was drilled into the wet zone, the bottom couple thousand feet. We tried that, a plug back with a polymer treatment. Mechanically it was partially successful. We cut back on the water quite a bit. But the oil production didn’t improve significantly so we’re still working on things like that, trying to resolve those issues that we will have again in the future. On that particular well we have decided the best course of action is to redrill it just the upper half.
Great. And just to switch to the Niobrara, it sounds like from your previous comments that from a timing perspective you need to do a little bit more work before you can tell us when you might spud a well.
That’s right. I think we have a non-operated proposal coming that we should probably see action on some time in the second half of the year. And then we would like a good chance to finish our work before we commit to the direction we’re going to go.
And are you at liberty to tell us who the operator is?
It’s Double Eagle.
Okay. Double Eagle - great. That’s what I figured. Great guys. I appreciate it. Good luck getting your permits.
Ladies and gentlemen, this concludes the question and answer session. I would now like to turn the call back to Mr. Norman Swanton for closing remarks.
Thank you. I would like to thank you all for joining us today and for your interest in Warren Resources. Thank you and good day.
Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.
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