Espy Price - Chairman & CEO
Steve Heiter - EVP, CEO, Warren E&P, Inc.
Ron Morin - SVP, Development & EVP, Warren E&P Inc.
Tim Larkin - EVP & CFO
Ray Deacon - Brean Capital
Brad Heffern - RBC Capital Markets
Warren Resources, Inc. (WRES) Q3 2012 Earnings Call November 7, 2012 10:00 AM ET
Good day ladies and gentlemen and welcome to the Third Quarter Warren Resources Earnings Conference Call. My name is Ann and I will be your coordinator for today's call. As a reminder, this conference is being recorded for replay purposes. At this time, all participants are in listen-only mode. (Operator Instructions) We will be facilitating a question-and-answer session following the presentation.
I would now like to turn the presentation over to your host for today's call Mr. Espy Price, Chairman and CEO of Warren Resources. Please proceed sir.
Thank you. Good morning everyone. Thank you for joining us for Warren Resources third quarter 2012 financial and operating results conference call. With me in Warrens’ Long Beach Office is Steve Heiter, the President of our Principal Subsidiary, Warren E&P in California and Ron Morin, our Senior Vice President responsible for development. Tim Larkin, our Executive Vice President and Chief Financial Officer is joining us from our New York City headquarters.
Before I turn the microphone over to Tim to cover the financial results and Steve to discuss our oil and gas operations, I would like to briefly comment on our performance for the third quarter of 2012 and the future direction of the company.
First, as I've stated before, my primary focus is to increase shareholder value. All of Warren’s operations are carried out and all plans are developed with a focus on enhancing shareholder value and increasing our stock price. Our company had a strong third quarter as sales volumes, oil and gas revenues and operating cash flow, each recorded significant gains compared to the third quarter of 2011.
Warren had a record breaking quarter in terms of oil production. Our oil production for the quarter increased 27% to 294,000 barrels of oil compared to 232,000 barrels produced in the third quarter of 2011. For the year, we are forecasting that we will exceed our targets of increasing our oil production by 20% above 2011 and maintaining a positive cash flow after capital expenditures.
Along with double digit growth in average daily sales volumes, Warren delivered improved gross margins as lease operating expenses continue to be carefully monitored and controlled. Our cash flow from operating activates increased 64% to $52.6 million in the first nine months of 2012 as compared to $32.2 million in the first nine months of 2011.
On September 08, 2012, we completed the purchase of Anadarko’s interest in the Atlantic Rim after early exercising our preferential rights. We also took over as operator of the Spyglass Hill Unit and of the Midstream assets which we now own 100%. We entered in to natural gas hedging to cover the additional gas for 2013 and 2014. This will ensure an early payout and attractive economics even in a low gas pricing environment.
Finally, we are continuing follow our strategy of operational and financial efficiency, while seeking opportunities to grow the company. Our performance through the third quarter and the acquisition of Anadarko’s interest in the Atlantic Rim is consistent with that strategy.
With that overview, I will turn the call over to Tim Larkin, our CFO. Tim?
Thanks, Espy. 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 cause actual result 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 Espy mentioned, we are excited about the balance of 2012 and beyond. Our cash flow from operations continues to be solid and we are in a strong liquidity position. We have cash flow from operations of $20.4 million for the quarter and $30.5 million available under our senior credit facility as of September 30, 2012.
Today, we reported net income of $2.4 million for the quarter or $0.03 per diluted share and adjusted net income of $5.8 million excluding losses from hedging activities of $3.4 million. Also, we produced 495,000 barrels of oil equivalent for the quarter or approximately 5,400 barrels of oil equivalent per day.
Additionally, natural gas production primarily from our Atlantic Rim Project in Wyoming was strong and overall natural gas production was 1.2 billion cubic feet during the third quarter compared to 1.3 billion cubic feet during the third quarter of 2011.
The average realized oil price for the third quarter was $95 per barrel, compared to $89 per barrel during the third quarter of 2011, an increase of 7%. Our realized gas price for the third quarter was $2.82 per Mcf, compared to $4.18 per Mcf in the third quarter of 2011, a decrease of 33%.
Effective August 1, 2012, we entered into a new oil purchase contract with Phillips 66 Company, whereby the company sells its oil at the average Midway Sunset posted price for the month less $4.20 per barrel, plus a premium for gravity adjustment which should approximate $0.20 per barrel. Midway Sunset is currently selling at $10 premium to WTI. As a result, Warren is currently receiving a $6 premium to WTI compared to the weighted average premium price of 103% received in the third quarter of 2012.
Also during the third quarter, we recorded a net loss from derivatives of $3.4 million which was comprised of realized loss from derivatives of $700,000 and an unrealized loss from future derivatives of $2.7 million.
In order to protect the company against the decline in oil prices, but allowing for unlimited upside to oil prices, the company currently owns Brent puts for approximately 1,800 barrels of oil per day with strike price of $90 per barrel for the balance of calendar year 2012. The company also owns WTI puts for approximately 1,000 barrels of oil per day with the strike price of $70 per barrel for the balance of calendar year 2012.
For calendar year 2013, the company owns Brent puts for approximately 1,375 barrels of oil per day with a strike price of $70 per barrel from January 1, 2013 through September 30, 2013. The company also owns NYMEX natural gas swaps for 6 million cubic feet of gas per day at a price of $3.11 for the balance of calendar year 2012 and we also own natural gas swaps for 7 million cubic feet of gas per day at $3.39 for 2013 and $3.79 for 2014.
As a result of increased oil production, oil and gas revenues for the third quarter increased 21% to $31.4 million compared to 2011. Total operating expenses increased 29% to $24.7 million during the third quarter of 2012 compared to 2011. We expect oil LOEs to average approximately $20 per net barrel for the balance of 2012. Depletion, depreciation and amortization expense for the third quarter increased 74% to $13.2 million compared to the third quarter of 2011.
DD&A was $26.75 per BOE during the third quarter of 2012, compared to $16.94 per BOE during the third quarter of 2011. This increase in DD&A on a per barrel basis resulted from the write down of 54 bcf of proved natural gas reserves as a result of significantly lower pricing under SEC pricing rules. Additional, estimated future development costs associated with the increase in our proved undeveloped oil reserves increased from $75 million as of September 30, 2011 to $153 million as of September 30, 2012.
General and administrative expense increased 20% to $4.4 million during the third quarter of 2012. This increase primarily resulted from a $400,000 of stock options expense relating to the accelerated investing of equity relating to our former Chief Executive Officer. Additionally, consulting expense increased by $200,000 during the third quarter of 2012, compared to 2011.
Interest expense increased 14% to $900,000 during the quarter, due to an increase in borrowings under our credit facility. As mentioned previously, net cash provided by operating activity was $20.4 million during the third quarter of 2012 compared to $12.2 million during the third quarter of . Cash flows from operating activities for the nine months ended September 30, 2012 were $52.6 million compared to $32.2 million in 2011.
As Steve will discuss in more detail and assuming a minimal level of activity in Wyoming, our revised drilling and facilities capital expenditure budget is $50 million; $45 million related to our California oil fields and $5 million related to our Wyoming natural gas fields. Additionally as previously reported in October 2012, the company purchased additional working interest and midstream assets associated with our Atlantic Rim Project. We purchased mineral rights in coal bed methane natural gas and other deeper oil formations for $12.1 million and midstream assets consisting of pipelines and compressors for $4 million for a total acquisition price of $16.1 million.
During December 2011 Warren entered into a five year $300 million senior credit facility with the Bank of Montreal, as the administrative agent and five other participating banks. Our borrowing base was increased of $130 million. The next borrowing base redetermination is scheduled for later this month. As of September 30, 2012 we had $99.5 million outstanding under our credit facility. On October 5, 2012 the company borrowed an additional $10 million to help fund the acquisition of additional working interest in midstream assets associated with our Atlantic Rim Project.
On November 5, 2012 the company repaid $5 million. As a result the company currently has $104.5 million outstanding under its credit facility. As operator of WTU and NWU oil assets in California and the Atlantic Rim Project in Wyoming, the company has the ability to modify its capital expenditure budget as commodity and financial markets change. We reported fourth quarter and full-year 2012 production and capital expenditure guidance in our press release disseminated this morning.
Now let me turn the call over to Steve who will provide you with a brief operational update. Steve?
Thank you, Tim. Now I would like to update Warren’s operational details. In the third quarter of 2012, Warren produced 294,000 net barrels of oil, a nominal increase over the second quarter of 2012 and 1.2 Bcf of natural gas and 8% decrease from the second quarter of 2012. During the third quarter of 2012, the company drilled and completed six producing wells in the Wilmington Townlot Unit in California, consisting of two wells in a Tar formation and four sinusoidal wells in the Upper Terminal formation.
30-day initial production rates for each of the two new Tar wells averaged 35 barrels of oil per day. One of these two Tar wells was drilled in the thinner Tar DU reservoirs and the Tar D1A well was drilled on the flank of the structure and encountered thinner pay and some oil placement problems. Note that for 2012, the eight new Tar wells initially averaged 112 barrels of oil per day with a range of 31 to 175 barrels of oil per day.
30-day initial production rates for the four new Upper Terminal wells drilled in the third quarter averaged 77 barrels of oil per day. All five new UT wells drilled in 2012 initially averaged 89 barrels of oil per day with a range of 24 to 144 barrels of oil per day. The well is producing 24 barrels of oil per day has mechanical problems and is being evaluated for remedial work.
Capital expenditures for the third quarter of 2012 in California were $10 million consisting of 7 million for drilling and development operations and 3 million for facilities improvement. Full year capital is expected to be around 45 million in California and 5 million in Wyoming.
Warren has concluded its 2012 drilling plan, which included 17 producers and one water injection well at the WTU. 17 producers drilled in 2012 had average 30-day initial production rates of 90 barrels of oil per day and declined rates are expected to match historical declines for each reservoir. The program resulted in a projected 2012 production increase of 23% over 2011, with project economics at $85 realized oil pricing of 60% rate of return, 12-month payout and the creation of $35 million of net credit values.
Upgrades to the production and water handling facilities in the company’s North Wilmington unit have been completed. This work will accommodate anticipated increased oil production from NW when drilling activity is resumed. With these operating expenses at the field level for our California operations for the first nine months of the year with $12.46 per barrel of oil net compared to 14.10 per barrel for 2011 or a 12% decrease. Field level expenses exclude taxes and abandonment expenses.
As previously announced, the company completed the purchase of additional natural gas and midstream assets in the Spyglass Hill and Catalina units from Anadarko. The details of the purchase are included in the announcement released earlier today. As a result of the transaction, Warren’s estimated proved develop reserves in the Atlantic Rim increased by approximately 18.3 billion cubic feet.
Additionally the acquisition added natural gas production of approximately 7.8 million cubic feet per day, bringing the gas production to about 20 million cubic feet per day. Also we have been successful in hiring the necessary personnel for operating with field and are in the process of interviewing and hiring the necessary administrative and tactical staff. Anadarko will continue to operate the field and provide accounting, reporting and land management support through a transition period expected to be completed by the end of the year.
Warren also owns approximately 63,000 net acres of deep rights with the Spyglass Hill unit in approximately 15,000 net acres of deep rights outside the unit. The company is currently evaluating possible sales and joint ventures of deep rights.
Thank you for participating today and operator we will now take any questions.
(Operator Instructions) and our first question comes from the line of Ray Deacon with Brean Capital. Please proceed. Ray Deacon your line is open, please proceed.
Ray Deacon - Brean Capital
Sorry, I was on mute. Espy I was wondering whether when you planned release 2013 CapEx and whether you have any plans to look at the Niobrara in Wyoming?
We are working on our total plan for 2013. I'm not able to give you a specific date. We will probably complete that about the middle of December and we will advise appropriately. As far as Niobrara rights I think as Steve mentioned, we have an attractive position in the Atlantic Rim. We have several people interested in joining us in some fashion and exploring the deep rights and we are talking to them now. So we think it’s a nice asset and we have, as I said earlier an attractive position.
Ray Deacon - Brean Capital
And I was just a little confused about the comments on spending at Atlantic Rim, are you drilling again in Atlantic Rim or where those just costs to hire new staff and just?
I'll let Steve answer that but we are not drilling at this time. Steve?
Ray, are you referring to the capital costs because I mentioned the $5 million for the year?
Ray Deacon - Brean Capital
Yeah, exactly right.
Most of that was the purchase of some compression that was being leased. It was the time came and we had to buy that equipment that we believe three compressors that we had to buy and that was most of that capital and the rest of it was well maintenance capital and other maintenance capital to operate the field.
And our next question comes from the line of Ben [Mackovak] with Cavalier Capital. Please proceed.
Can we just talk a little bit more about the acquisition? I think it caught a lot of people off guard. Basically Double Eagle made a bid for these assets and then one thought that was such a good deal that they wanted to get involved?
Yeah, so we have always had preferential rights in those units because of our arrangement with Anadarko. Once we were knowledgeable of the amount was [bid] we did the economics on that and it looked very attractive to us, you know even without putting any value on the deep rights. We looked at it very closely even in the low gas price environment and we think we have evinced a very attractive economics and it positioned us very well for the future.
What gas price did you assume when looking at the economics?
We assumed the actual gas price obviously at the time but as we pointed out in our notes that we hedged that amount of the new gas for the years 2013 and 2014. I think Tim mentioned the price that we hedged which was more than enough to make the economics attractive on net purchase.
Okay. Do you have any update on the water injection well approvals and also an update on the gas line connection at WTU?
Okay. I will let Ron Morin talk about the water injection situation and then either he or Steve could update you on the gas line.
We are continuing to work with DOGGR. Our next one is coming up is the Ford project. We are hoping to, we submitted that. We're working with them. We have another Tar injector we're working on as well and then we're continuing to work with DOGGR on both NW which is going quite well because those wells are essentially grandfathered by the quarter mile rule as well as the UT, most of those conversions that we're going to do with (inaudible). So, pretty good shape. It is critical to try to get the Ford done because we want to include that in our drilling program. For 2013, we got some commitments from DOGGR to try to get some movement on that by around March of next year. So we're working with them as we speak.
Is that okay? The injection wells, I'll let Steve talk about gas sales.
Okay. We're proceeding with our plans to sell gas to SoCal gas company through a pipeline rather than injecting the gas on the ground since the division of oil and gas was not in a position to review that application and so we went to gas company, we have gone through all the necessary agreements, they are all signed, the engineering is being done at this time and the application was submitted to the AQMD. We had a hearing and in that hearing, the AQMD asked for a review.
It's going to take probably in the range of six months because of the equipment we had proposed for a gas sales was slightly different than what we would have used for gas injection and even though we feel the emissions are significantly less, they still wanted to review it and so we're in the process of providing the necessary information for that review, which kind of delay it a few months but we're proceeding with the gas company and working through that process and we don’t anticipate any problem since the emissions are less, it’s just going to take a few more months than we had originally hoped. And so that gas sales system we are hoping look to be in operation by probably early 2014.
Okay. And my last question is this is a write-down of the gas reserves that’s kind of really changed the depreciation levels that we have seen, is there with the rebound in gas prices is there a chance to reverse that what’s the outlook for that?
Yeah this is Ben this is Tim. Yeah definitely if we see an increase in natural gas prices certainly would put on or rebook the PDP reserves and I guess possibly the associated (inaudible) relating to natural gas. Just as a reminder, the way it works is the under the new SEC pricing rules you use the average price over the prior 12 months and so the increase that we are seeing in natural gas pricing in the fourth quarter should certainly have a positive effect on year-end reserves.
(Operator Instructions) And our next question comes from the line of Brad Heffern with RBC Capital Markets. Please proceed.
Brad Heffern - RBC Capital Markets
Just going back to the Wyoming acquisition for little bit, it sounds like you guys were thinking about that more as a production acquisition on the actual undeveloped acreage there, is there any plan to start drilling those 25 wells again or are you okay with the acreage sort of shrinking down around to where the production is?
This is Espy, it’s something that we need to continue monitoring, we only have a certain time to make a decision on that. The only way we would consider drilling those wells of course if they are economic and we all are prepared if we don't think the new wells are economic and we are prepared to let the acreage shrink as you suggested.
Brad Heffern - RBC Capital Markets
Okay, great and then switching over to the Tar with these two new wells, you guys have sort of talked historically about having something like 20 locations left. Are these two new well reserves sort of as a result of getting to the end of the Tar inventory or was this more trying to step out and add more locations?
No, this is Ron, its part of its our continuous progression, we are probably 80% of the way through the Tar development, as you know, we started that in 2005, so well as you know we drill the best wells we can every year, the well is get trickier, they are on the flank, those sort of things. One of these was DU0 which is the reservoir above the classic [Tar DU1 ATM] that we always talk about and that well, it looks like its stabilizing at lower IP that we thought but the sister well that we drilled about three years or four years ago has done quite well, its expected have about 150,000 barrel EUR.
So we are continuing work with future Tar locations. We probably had between 10 and 15 remaining inventory as we’ve talked about publicly. So we are advancing on the other terminal for instance we are at the early stages, I think we drilled about 10 wells, and the upper terminal a lot of, I think we have got 60 or 70 that we talked about publicly. So we are at the early stages there but it’s just part of the business and the nature of business to have these ranges as you go to out to that, you have flanks of the field for instance this year like as Steve said, we averaged 31 to 175 last year, we averaged 74, we didn't average, we ranged from 74 to 251 barrels of oil per day. So that's just a part of the business and gets a little tougher as you get in the advanced stages of developing these reservoirs. Does that answer your question?
Brad Heffern - RBC Capital Markets
Yeah that makes sense. And then just going back to injection permits, I understand the chicken and egg situation here but can you talk about how many permits you feel like you guys are going to need for 2013 and how things are in that process? It sounds like NWU is going okay but what about the other field?
Yeah, I would say NWU is going flank because those are grandfathered as I mentioned earlier. For the Tar, we would like to get another injector in the east Banning fault that we start putting some wells in about a year ago. That thing is in the works. We are trying to get that approved. The ranger we did get approval late last year so we are going to probably start early in 2013 we've drilled some injection to get partial support of that southwest area and then we will have other AORs that will also work with as well as conversions which are easier, conversions of existing wells. The upper terminal as I mentioned, most of the drilling we are doing right now is in what we call the modern area where we drilled the majority of the wells in ’06 and ’07 and we can convert those. Those have been a pretty straightforward approvals.
Probably, the trickiest one is the Ford; we really need to get that moving. We've got that application and as I mentioned and we would like to get that. We are pushing DOGGR to get that some time in the first quarter, so we can include the Ford drilling in our 2013 drilling program. So that's the one we are really needing to move off center here pretty quick.
Ladies and gentlemen with no further questions this concludes today's question-and-answer session. We would like to thank you for participation in today's conference. This concludes the presentation. And you may now disconnect. Have a good day.
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