Phil Rykhoek - CEO
Tracy Evans - President & COO
Mark Allen - SVP & CFO
Bob Cornelius - SVP, Operations
Jonny Brumley - President, CEO & Director
Bob Reeves - SVP, CFO & Treasurer
Ben Nivens - SVP & COO
Jon Brumley - Chairman of the board
Noel Parks - Ladenburg Thalmann
Eric Hagen - Lazard
Andrew Coleman - UBS
Brian Kuzma - Weiss Multi-Strategy
Mitch Wurschmidt - KeyBanc
Denbury Resources Inc. (DNR) Q4 2009 Earnings Call February 23, 2010 11:00 AM ET
Good morning, and welcome to the Denbury Resources Inc. fourth quarter 2009 earnings release conference call. All participants will be in listen-only mode. (Operator Instructions). After today's presentation there will be an opportunity to ask questions. (Operator Instructions). Please note this event is being recorded.
The following discussion contains forward-looking statements and our actual results may differ materially from those discussed here. Additional information concerning factors, such as price volatility, production forecasts, drilling results, and current market conditions that could cause such a difference can be found in our reports filed with the Securities and Exchange Commission, including our reports on forms 10-K and 10-Q.
I would now like to turn over the conference to Phil Rykhoek. Please go ahead.
Thank you, Amy. Welcome everybody to Denbury and Encore's combined fourth quarter conference call. It's obviously been a busy place here at Denbury and a lot of positive things are happening. By now you should have received your proxy for shareholder meetings scheduled for March 9. Assuming approval which we expect closing and emerge will happen shortly thereafter. You probably also noticed that we have essentially finished the financing for the Encore acquisition. The banks indication was over sold as well as the $1 billion subordinate debt offering we completed a couple of weeks ago. Now we were pleased with the positive response and the rate we obtained on that debt transaction and glad to have that behind us.
Our fourth quarter production as previously announced were slightly ahead of forecast, accrued reserves we're either on track or slightly better. If you noticed we had at almost tcf of additional CO2 reserves during 2009, the timing of which couldn't have been better since we need that CO2 for the recently purchased Conroe Field, our 130 million barrel potential EOR flood just north of Houston. We are focused on the Encore acquisition integration of personnel assets and operations that have been dedicating significant resources to that process. We are doing that ground work for our divestiture package which we hope to launch soon after closing. In summary, positive things are happening and things are falling into place.
Our staff has been extremely busy the last couple of months as all these activities take a tremendous amount of extra work and I want to probably thank them for their extra effort. I countered approximately 45 SEC volumes that Denbury has made since our merger announcement early November in case you haven't found it yet. But that's a lot of paper.
And today we are here to talk about fourth quarter and 2009 earnings and results. With me today from Denbury I have Tracy Evans, our President and COO; Mark Allen, our Senior VP and CFO; and Bob Cornelius, our Senior VP of Operations.
We also have from Encore, Jonny Brumley, President and CEO; Bob Reeves, Senior Vice President and CFO; Ben Nivens, Senior VP and COO and John Brumley Chairman of the board. These guys will give you more details about our respected companies, operating results as well as provide an operational update. We will start with Mark's review of Denbury's financials. Mark?
Thank you, Phil. As reported in our press release we had net income for the fourth quarter of $3.5 million which included a non-cash charge for the change in fair value of commodity derivative contracts at $59.5 million or $36.9 million after taxes. We also had merger related expenses associated with Encore transaction of $8.7 million or $5.4 million after taxes. When you exclude these items we had adjusted net income in the fourth quarter of $45.8 million or $0.18 per share essentially on top of first call estimates. This adjusted net income amount also included expense of $5.1 million or $3.2 million after taxes related to the Genesis management compensation awards with some analysts may not include in their estimates.
If you exclude this charge our adjusted net income would have been approximately $49 million or $0.20 per share. In other case, the current quarter results are higher than the prior quarters' adjusted net income of approximately $40.7 million or $0.16 per share. As I had typically done, I will primarily focus on the sequential results of the third and fourth quarters of 2009 rather than the comparative fourth quarter of 2008.
During the fourth quarter of 2009 our tertiary production averaged 26,307 BOEs per day, 8% higher than our Q3 tertiary production and on overall basis our production increased by approximately 6% over Q3 levels.
In mid-December 2009, we closed on the acquisition of Conroe field at the end of December; we closed on the sale of the remaining 40% of our Barnett Shale properties. On a pro forma basis, adjusting for the sale of the Barnett Shale properties and a full quarter of production from Conroe field our production might have been approximately 42,000 BOEs per day.
Bob is going to discuss more about our production in a moment but I stated in our press release we are reaffirming our tertiary production guidance for 2010 of 27,000 barrels per day. And estimate that our total company 2010 production will average approximately 41,500 BOEs per day after adjusting for the sale of the Barnett Shale and purchase of Conroe field. Approximately at 7% year-over-year annualized increase on a pro forma basis.
Also based on preliminary estimates and before any asset sales we would anticipate our Encore standalone production to increase by approximately 7% of its 2009 average of 42,929 BOEs per day. Please note that when I discuss combined numbers herein, I am generally referring to results for the entire year. However, the semi-completion of the merger in early March, will only report the result on core and our financial results from that point forward.
Our average oil price received for the quarter including derivative settlements were $72.67 per barrel in Q4 as compared to $70.54 per barrel in Q3. But if derivative settlements are excluded, our average oil price received for the fourth quarter was $72.56 per barrel as compared to $64.70 per barrel in Q3. Our NYMEX oil price differential is essentially the same as during the third quarter approximately $3.44 per barrel below NYMEX in Q4. This differential on a standalone basis may improve somewhat in 2010 as a result of a sale of the Barnett Shale which have liquid production reported in our oil sales that sold at a much higher discount to NYMEX.
However, assuming completion of the Encore merger, the combined company's NYMEX differential would be less favorable as the average NYMEX differential for the Encore properties was $8.04 per barrel as in Q4. Our total corporate lease operating expenses were up slightly roughly $900,000 in Q3 to Q4 and our per BOE basis, our overall lease operating cost decreased from $21.22 per barrel in Q3 to $20.34 per BOE in Q4, primarily due to increased production in the fourth quarter.
Our pro forma basis adjusted for the sales of Barnett Shale properties at the end of Q4. Our LOE per BOE in Q4 would have been $22.37 per BOE, as compared to $23.40 per BOE in Q3. Going forward excluding the Encore acquisition, I would expect our LOE per BOE to be at least equivalent to our tertiary production cost and generally as most of our conventional production is about more than our tertiary production cost.
On a combined basis, our LOE per BOE will drop assuming completion of the merger as on course LOE per BOE averages less than ours generally due to higher percentage of natural gas production. Bob will cover few more details on our LOE in a moment.
G&A expenses increased by $12.2 million from Q3 levels, due primarily to $8.7 million in acquisition-related expense, primarily associated with Encore acquisition and $1.5 million incremental compensation expense related to Genesis management incentive compensation of awards. This quarter we recognize expense-related to the Genesis management compensation words of approximately 5.1 million or total of 14. million during 2009. When we saw the GP of Genesis in February 2010, we paid out the compensation awards to Genesis management in aggregate amount of $14.9 million. All, but $700,000 of which has already been recruited in our 2009 financial statements. Although our G&A expense will no longer be burdened from the Genesis management compensation expense after the [pat] in the first quarter, they will have significant transaction cost related to the Encore acquisition and the first quarter that will run through our G&A expense, likely to be significantly higher than what we expensed in Q4.
Interest expense, net of capitalized interest increased sequentially from $9.9 million to $10.5 million, primarily related to the [Celeste] capitalized interest this quarter. Capitalized interest was $20.9 million last quarter as compared to $19.9 million this quarter, primarily due to the Delhi Pipeline from Tinsley to Delhi Field replacing the service in Q4.
Going forward, we expect that our capitalized interest will continue to increase moderately from Q4 levels until the green pipeline is put into service. Our bank debt at December 31 was $125 million, higher than originally anticipated primarily due to incremental debt of approximately $60 million resulting from the purchase of Conroe field and the sale of Barnett Shale assets in December and approximately $50 million in equipment leasing that we did not complete in the fourth quarter.
We may least this equipment during 2010, if we're able to find attractive terms. As you are probably aware we recently issued (inaudible) senior subordinated debt due 2020. The proceeds from this issuance for closing as for the pending completion of the Encore acquisition which is subject to approval of both company shareholders on March 9. As a result, our interest expense will increase substantially in the first quarter. Assuming the shareholders of both companies approve the merger, approximately $600 million of the proceeds from this offering will be used to redeem Encore senior subordinated debt and the remainder will be used to close the transaction.
We also have commitments from a syndicate banks for a new $1.6 billion revolving credit facility that will replace our existing facility and will be used to fund remaining cash portion of the Encore acquisition. We're currently working on deducting (inaudible) for this facility. We currently anticipate that we will have between $900 million drawn on this facility upon closing the merger.
Our total anticipated expenditures for 2009 excluding acquisitions and capitalized interest totaled approximately $815 million. Net of sale as lease backs were approximately $50 million. This was higher than our $750 million in anticipated capital expenditures, due primarily to $50 million of equivalent seeing that we did not complete in 2009.
Our capital expenditure budget for 2010 is $650 million on a standalone basis and approximately $1 billion assuming we complete the Encore acquisition. Our combined basis to $1 billion would exceed our anticipated cash flow by approximately $150 million, $200 million. However previously stated, we anticipate selling at least $500 million in assets 2010 and (inaudible). Our DD&A for oil and gas properties increased slightly on absolute basis and more so on a per daily basis from [highly due] to the Barnett sale.
With regard to income taxes, we currently anticipate that we will be able to detect a large portion of our green pipeline when replacing the service and begin injecting CO2 and Oyster Bayou have currently anticipated around mid 2010. This should help implement our current tax expense and help shield additional tax asset dispositions. And with that I will pass it to Bob.
Thank you Mark and I will give you a quick update on the major fields and capital projects completed during the fourth quarter. Denbury's fourth quarter oil production averaged 45,012 net BOEs per day that was a 5% increase over third quarter of 2009 that EOR fields produced an average of 26,307 net BOEs per day during the quarter that is an 8% increase over third quarter and a 20% increase over the fourth quarter of 2008.
During the fourth quarter, we conducted several major operations that's filled this expansion in key fields imperative for future success. Several of the major projects had advanced completed during the fourth quarter were the commissioning of the Delta Pipeline from Tinsley to Delhi Field we had then allowed it to get first injection into Delhi field while that construction of the 320 mile green pipeline hit a big milestone with the 24 inch pipeline being installed into our Oyster Bayou field during December.
The other tertiary operations we completed were expansions at Tinsley and Heidelberg and in the Jackson Dome area we completed work to increase both our CO2 production rate and dehydration capacities. While the tertiary fields had significant increases during the fourth quarter in fact eight of the 12 operating CO2 facilities showed a quarter-to-quarter increase and five of those tertiary fields actually exhibited a double-digit increase quarter-to-quarter.
In phase 1 that is our Little Creek, Mallalieu, Brookhaven, McComb, Smithdale and Lockhart fields those better performers were the Mallalieu, Little Creek and Lockhart Crossing. At Mallalieu our largest field we completed a facility upgrade by adding compressors, inlet heaters and separation equipment which increased facility recycling capacity from about 160 million cubic feet a day up to 230 million cubic feet a day. That additional CO2 recycling capacity allowed us to increase production during the fourth quarter. We do expect Mallalieu to resume its decline in the near future as it is a fully developed field.
Another fully developed field is Little Creek, but Little Creek producing area had improvement due to initial response from results of the BOE project along with Mississippi state university. The project was a WAG which is Water Alternating Gas cycling where the water contains nutrients to feed natural occurring bacteria in a formation. The nitrate rich water and bacteria grows in the high permeability streaks, causing them to block and forcing water and CO2 into other intervals. The project is shown to increase the areal sweep efficiency and has increased production in the area of injection by over 100 barrels per day. Unit production averaged about  BOEs per day during December and the team is considering expanding the WAG project into additional patterns to determine if they are truly successful.
Now, part crossing average tertiary production increased 16% or 203 net BOEs per day quarter-to-quarter as production improved from 882 BOEs per day to 1025 net BOEs per day over the period. The majority of the production increase is due to opening additional wells in the best part of the reservoir while maintaining the reservoir bottom hole pressure. Our gold of course it has continued to monitor bottom hole pressure and open wells in the channel area or the best area of the reservoir. We also experienced response during the period in the bar sand wells which could add production in future months. The theme plants to add a portable CO2 pump to maintain injection withdrawal rates and certain patterns.
Phase 2 which is Mallalieu, Eucutta, Soso, Martinville and Heidelberg increased 11% quarter-to-quarter. Soso and Heidelberg had double digit increases quarter-to-quarter and Martinville increased approximately 1% and Eucutta had a slight decrease of 4% during the quarter due to a reduction in CO2 injection rates in the prior months.
Although Eucutta decreased through the quarter there has been a steady production increase during November and then again in December. Eucutta December production was slightly higher than the quarterly average and the team is working to maintain CO2 injection rates and reservoir pressure in the duct reservoir. Soso field continues to be one of the best performing tertiary fields. Soso increased over 400 barrels per day or 14% quarter-to-quarter and has further increased production during the month of December. The majority of the production increased is due to the installation of jet pumps. These jet pumps are used to assist the producing wells to kick off and unload the wells and these slow responding wells are coming around much faster than previously what they would.
At the Heidelberg, it is our largest Phase 2 field in terms of reservoir potential. CO2 injection began in Heidelberg about one year ago during December of 2008; first production would begin in May. Heidelberg's field expansion was completed during the fourth quarter and Phase 2 fields expansion continues into the first quarter of 2010. Heidelberg production rates increased each month since its first production sales in May and during the fourth quarter production increased 81% from 828 BOEs to over 1506 BOEs per day from the quarter-to-quarter comparison. Tinsley is our largest tertiary field currently being flooded and is the only field in phase II and has experienced an increase of 11% quarter-to-quarter. Production increase from an average rate of about 3,558 BOEs in the third quarter to 3,942 net BOEs during the fourth quarter.
During the fourth quarter, we commissioned a second trend of compression continued the expansion of the CO2 facility, we had a water handling capacity and began construction of another production test site and then began recompleting wells in the third phase of this field. Expansion of CO2 recycle facility and addition of CO2 injection well should allow the unit continue to perform. Our 2009 and 2010 capital development plan was not offered and thus we continued to see hopeful for success at Tinsley.
Cranfield is our phase 4 CO2 project. CO2 ejection began in July 2008; we now have 17 ejection wells placed in approximately a 100 million cubic feet a day of CO2 into that reservoir. Cranfield also saw a nice quarter-to-quarter increase improving 27% during the period. Average quarter production with 728 BOEs per day.
In Delhi our phase five expansion we initiate field two ejection during the fourth quarter of 2009. Reservoir repressurization and pattern development was progressing as planned. We hope to establish first sale during the second quarter of 2010. The main introduction of recycling facility is ready for production.
And during 2010 the team has continued to expand the facility and add additional injection and producing wells during this period. We have total of 29 wells to be drilled.
Jackson Dome our CO2 source produced an average of 788 million cubic feet during the fourth quarter that rate represented a 24% increase over third quarter volumes. The majority of the CO2 was injected in to Eucutta, Soso, Tinsley, Cranfield and Delhi. We completed construction of the phase Delhi facility during the period, which will allow us to produce three additional CO2 wells that we are waiting on that facility.
With the addition of the Trace Dehy and these existing wells Jackson Dome now has the ability to produce at rate at a BCF per day if required. 2010 capital projects in Jackson Dome includes the drilling of three wells and expansion of a dehydration facilities that will continue to improve our production and add reserves.
The 24 inch green pipeline construction activity began about 13 months ago in November of 2008. Construction of the pipeline reached Oyster Bayou Field the week before Christmas. We laid approximately 257 miles or 80% of the total miles in that 13 months.
Presently we are installing valves in operating facilities along the Louisiana portion of the pipeline and completing the final tie in into the NEJD Pipeline that will connect the system to Jackson Dome. The work on the existing pipeline should be completed in the second quarter and third projection in to Oyster Bayou around mind-year.
There are three relatively short segments of type to install this year to complete the pipeline to Hastings Field, south of Houston. 20 miles from the Oyster Bayou to the East side of Galveston Bay that will be completed during December month.
Then we have the Galveston Bay crossing which is a 14 mile water processing that will start during April and be completing approximately six months. And then finally we have the 25 miles on the East side of Galveston Bay to Hastings which should be completed and have injection into Hastings by the fourth quarter of 2010.
We estimate 2010 capital investment to complete the green pipeline at approximately $115 million. The pipeline is still on schedule, during this construction period, largely due to the (inaudible) winter wet weather that we experienced during the fourth quarter.
At Oyster Bayou the initial flood design and injection patterns are being developed. The well work is underway with the initial CO2 wells completed and repairing to [steady] flow line to connected to the main green pipeline. At Hastings Fields, the first new well in the field was spudded in December. The core was taken from the formation to be analyzed to assist in reservoir stimulation, development and management of the Hastings field area under Tertiary flood.
Production recycling facilities are under design and we paired our first production is expected from Hastings during the fourth quarter of 2011.
And with that recap I'll get back to Tracy.
Thanks you Bob. As has been the case since year end 2000. DeGolyer and MacNaughton formed an evaluation of our reserves as of December 31, 2009. During 2009 we added 28.8 million barrels of oil from acquisitions at Hastings and Conroe and added an additional 17.6 million barrels of oil reserves in our CO2 assets. Additions from our adds and decreases to our sale of Barnett of 74.2 million BOEs was also in our prude reserves during 2009 decreasing on an absolute basis the 207.5 million barrel of oil equivalence, which consist of a 193 million barrels of oil condensate and natural gas liquids and 88 BCF of natural gas.
And at present value using at 10% discount rate of our proved reserves was 3.1 billion as of year end, in comparison on net present value of our approved reserves at year-end 2008 was $1.9 billion. The increase in net present value from year-to-year was primarily due to the booking of our additional CO2 reserves, our acquisition and then higher oil prices.
Pro forma reserves as of 12/31/2009 including the Encore asset are 427.8 million barrel of oil equivalent at a value of $5.2 billion. Then we will provide additional information on Encore's year-end reserves. Denbury's proved reserve estimates at yearend 2009 were based the updated SEC guidelines for reserve estimations which were valued based on the average unweighted first day product price for the preceding 12 month which resulted in an NYMEX oil price of $61.18 per barrel and a gas price of $4.19 per mcf compared to yearend 2008 product prices of $44.60 per barrel and $5.71 per mcf.
The PB10 value of Denbury's December 31, 2009 proved reserves using alternative price deck based on the futures market forward strip as of December 31, 2009 was $5.8 billion. Denbury's net average price contained in this alternative reserve for approximately $85.77 per barrel of oil, $57 per barrel in natural gas liquid and $6.59 per mcf . Proved reserves associated with our CO2 tertiary operations account for approximately 65% of our current proved reserves or 134.5 million barrels of oil as of yearend 2009. In comparison, and our tertiary reserves at year end 2008 were approximately 125.8 million barrels of oil.
We added 44.9 million BOEs of proved reserves during 2009 before netting out 2009 production, property sales and reserve revision replacing approximately 277% of our 2009 production, a majority of which was from our acquisition at Hastings, Conroe in our additional reserves in our CO2 tertiary properties.
Reserve additions are to CO2 related properties during the year were primarily to Cranfield approximately 11 million barrels, you got 2.5 million barrels and then Heidelberg which was 2.9 million barrel. The reserves added at Heidelberg in our tertiary were actually transferred from the prior water flood. Cranfield is in Phase IV and Eucutta and Heidelberg are in Phase II. As previously mentioned we sold approximately 74.2 million barrels of proved reserves during 2009 already to our Barnett Shale assets.
Now as of year-end 2009 approximately 93% of our proved reserves are oil condensate or natural gas liquid and 62% of our proved reserves are proved developed reserves. In addition to our proved oil and gas reserves DeGolyer and MacNaughton also performs evaluation of our proved CO2 reserves at Jackson Dome. Our CO2 reserves increased by 940 Bcf of CO2, a total of 6.3 trillion cubic feet of CO2 as of yearend 2009 after accounting of 2009 CO2 production.
Our 2009 CO2 production of 249 Bcf of CO2 was offset by reserve additions during the year. 400 Bcf at Gluckstadt field based on lowering the lowest known CO2 level as a result of our drilling operation from the only well we drilled during the year. 345 Bcf from expanding our acreage ownership and an existing CO2 unit and the remaining reserves were added in existing wells based on performance and a greater understanding of the reservoirs.
During 2010 as Bob mentioned, we attend to drill three additional wells, the Jackson Dome to further develop additional production reserves. We have spud our first well during 2010, which will attempt a large structure that may contain between one and a half and two tcf of CO2. The large portions are currently booked probable CO2 reserves at Jackson Dome. And with that I'll turn it back over to Phil.
Thanks guys. Well that concludes Denbury's, now we will go through our Encore's financial results and operations and I think we will start with Jonny Brumley, CEO.
This is Johnny Brumley, CEO of Encore. I'll go over the fourth quarter and full-year 2009 results for Encore. Then I will turn the call over to Ben Nivens, our COO who will update you on the operations. And then Ben will turn the call over to Bob Reeves, our CFO who will discuss Encore energy partners.
Before I do that I would like to thank our investors who have been very supportive long-term investors, and we appreciate you and I'm glad that we could deliver the profitable results that we set out to do with public in 2001. And also I would also like to thank our employees; who've done a great job. We've refocused the company back in 2006 and transformed it into a company with a large drilling inventory and less taxes the Bakken Shale and the Haynesville Shale and also a large tertiary play with Bell Creek and Cedar Creek and without your ingenuity and dedication that could not have happened and thank you for that as well.
Now began talking about production. Our production was 45,143 barrels of oil equivalent per day for the fourth quarter of 2009, and that compares to 41,824 barrels a day at the fourth quarter of '08.
Production was a tad bit lower than we are expecting due to the extremely cold weather throughout the country, but what's important is how well the production hung in there with really hardly any completion and as the temperature warms up our production will increase within.
We always take winter weather into account, but this winter was unbelievably cold and is just hard to frac wells in negative temperatures, but its times like this that really do highlight our quality asset base and is really shining through now.
And we also have a exciting Bakken completion early March. This is the Werre Trust well, it's a 19 stage frac, we are really excited about its in a great area, its offsetting a big well that was there just on a single stage this well ought to be really good Ben will talk more about that.
And if you look at our numbers on an annual basis you really can see how well the company is doing. Our annual production averaged 42,929 barrels equivalent day, that's 1767 barrels per day over [budging] our capital expenditures were $33 million under budget. LOE was a $1.76 per barrel under budget and with our hedging program and cashing enter our hedges back to March of 2009 at the low, oil prices, prices were way above expectations.
So I think this is really what heaven must look like. More production less capital LOE and higher prices.
Now, I'll turn it over to Ben, thank you for working for us and investing with Encore you have done a great job.
Thank you Jonny, I'll start with a recap of our 2009 year end reserves as Tracy mentioned earlier our improved reserves are 220 million barrels of oil equivalent, this is a increase of 34.6 million or 19% over end 2008 reserves and represents a reserve replacement ratio of 321%.
Our reserves were 67% oil and 80% [proved] developed and let me just kind of do a reconciliation from the 2009 year end reserves of 185.7 million barrels. In 2009, we produces 15.7 million barrels and the company acquired 24.1 million in East Texas, Oklahoma and West Texas, we added 21.5 million barrels through the drill bed and had revisions of previous estimates of 4.8 million barrels mostly financial.
And given us the total of again 220.3 million barrels of reserves for year end 2009. Now I'll give you an update on our drilling operations, for the fourth quarter we had no significant operator wells to come online in our major areas of operation, this was due to lower activity in the third quarter and weather delay that Jonny spoke of earlier. As part of our capital reduction program of 2009, our rate cap went down to one rig at one point in the third quarter of 2009, before we began taking up rigs in the fourth quarter.
Currently, we have five rigs running, two in the Bakken, two in West Texas and one in Haynesville and we have several completions coming out in the first quarter of 2010 and I'll discuss those completions in the major operating areas.
Starting with the Bakken, we have four wells that we'll be completing in the first quarter of 2010. Jonny mentioned that we are trust 34 age that is a 1280 acre of well it'll be a 19 stage frac in Bear Creek and its directly offsetting our Werre Trust 213 age that we released results on last quarter that was a single stage 640 and [IP-ed] to 1500 barrels a day.
That frac is scheduled to begin in the first week of March. From there we'll move to two other wells in Bear Creek [45 ridge 1435 age and 45 ridge 11X2 age] these wells were drilled from a common pad and they are going in opposing directions and we will actually be doing these fracs simultaneously, they will not be simultaneous in the sense that they'll be actually fracing at the same time but we will be using the same equipment where we'll frac once while we are proliferating the other and the equipment is there in one common location unless we switch back and forth, so that's pretty exciting too. That work is scheduled to begin in the second week of March.
From there we will be moving Murphy Creek well, the Becker 247H that is a 1280 and will be a 20 stage frac that well will actually be completed in the second quarter of 2010.
And we currently have two operating rigs going and the Bakken as I mentioned earlier one is drilling in Murphy creek and the other is in the Charleston area. On our [other] places we have four rigs running so it's a very active program going on in the Bakken.
Moving to the Haynesville we have two operated wells that will be coming online in the first quarter in our Greenwood Waskom field. The [EDGAR] 31-1H is already on it (inaudible) 11.7 million was our flowing casing pressure of 5500 pounds so it looks like a very strong well. The [Dunn Number 2-1] is actually completed and should begin production in the first week of March. And that's a 100% operated well as well. We also had three wells in the non-op area come on in the Haynesville and three different fields in Caspiana, Greenwood-Waskom and the Kingston area with IPs ranging from 8.1 million to 23.8 million per day. It should be noted that the 8.1 million IP well is a well that was brought on by a private company that changed to bring their well down more slowly. This is a strong well that had very strong flowing casing pressure and we're still excited about it at the 8.1 million a day range.
In addition, we recently (inaudible) 5-1 well. And that well is way in completion and should come on in the second quarter in 2010. The rig is now drilling another well in the Greenwood-Waskom area and we intend to keep rig going in the Haynesville most of the year and then in the non-op areas really the activity is really picking up there. We have five rigs running on our non-op places and we have three wells waiting on completion in the Haynesville area, in the non-op area.
Moving on to our West Texas JV, we had two wells coming online this current quarter, our [Howard Hodge B4H] well is a Delaware Basin well and the Waha Field, this well came on at 10 million a day for initial flow back in its field producing in at 9 to 7.5 million a day range as we continue to have to treat that well because of some plant to issue never getting to lined out. But looks like a very strong well.
Moving on to the Pegasus field in the West Texas JV, we have the [TR wells at 46-1H] that is scheduled to be completed in the first week of March. And that will be our first well in the Pegasus field after dropping a rig and now picking up another one. We have two rigs running in the JV and our budgeting to continue with two rigs for 2010, one rig will operate at Pegasus and then one Rig will operate in the Delaware basin and its currently drilling in our Waha field.
This concludes our update in the operations now I will turn it over to Bob Reeves to give you a financial review.
Thanks Ben. I am Bob Reeves, CFO. I'd like to go with the results of Encore Energy Partners for this call we'll not only go over the quarter and the year but we'll reflect briefly on the history of the partnership and then take some time to look into the future of ENP and address some of the questions that Kim Weimer, our IR person has got at the last few months. Our production for the quarter was 9254 barrels a day for the fourth quarter which equaled 68% oil by production. This follows up a quarter, in the third quarter that was 9301 barrel a day which equates to just 47 barrel per day drop in production quarter-over-quarter over one half of 1%. We previously stated that we are looking to manage production over a 12 month period rather than quarter-over-quarter with the understanding that timing the drilling completions, seasonal weather problems, well barriers and performance estimates may cause some variance within the production guidance range that we put out from quarter-to-quarter.
For the fourth quarter, however, we were once again very fortunate with our production performance being at the high end of the guidance range. With the operations guys doing a great job to keep in production on line during the extremely cold and harsh winter we've experienced this year which we typically start seeing in the fourth quarter and in somewhere around the end of the first quarter.
All right some people on the call might not be familiar with the necessity pressed to recast proper period results on Form 8-Ks because of the drop downs from EAC to ENP as a result of GAAP requirements. Our controller Andrea Hunter and Director of Accounting Ron Holcomb, they do a great job of working hard to make these recast on timing in accurate basis. But when you go back and you take a look at these recasts that we've done and you look at the production results for 2009 as if all these drop down that acquisitions took place at January 1, 2009 you see the following results on your production. So the first quarter 9042 barrels a day for the second quarter 9142 barrels a day, for the third quarter 9301 barrel a day and for the fourth quarter 9254 barrels a day.
Outstanding production by any measure over any period of time. As previously stated, the partnership averaged 68% oil by production for the quarter. Once again this quarter its fantastic to be oil with a staggering 18:1 price ratio for the quarter when comparing oil to natural gas prices based on NYMEX average price. Currently the partnership enjoys 89% of the NYMEX price and its revenues with its differential remaining tied to $8.47 per barrel or a 11% off at just NYMEX prices. LOE of $12.40 for the quarter missed the high end of our guidance range on a per-BOE basis. We incurred a $1 million expense from an outside operator which represented expenses from several prior periods that were not build into the fourth quarter of 2009. Without this one-time expense LOE would have been $11.22 per barrel.
For the first quarter we do expect LOE to be about the same as the fourth quarter levels. With additional expenses associated with keeping the production online during the extremely cold weather that we previously talked about. G&A for the fourth quarter was $2.63 which is back to a more normalized level when you compare it to the third quarter. Our cash available for distribution was $36.7 million for the fourth quarter on EBITDA of $41 million; we maintain our distribution of $53.75 for the quarter or $2.15 annualized per unit. This is $24.6 million paid out to all our unit holders and the remaining amount of $12 million was used to reduce debt.
Our coverage ratio was 1.5 times for the quarter, our debt outstanding at the end of the fourth quarter was $255 million leaving us ample liquidity of around the $120 million still available under our revolving credit facility.
Now lets briefly reflect on the partnership. As most of you know we created this partnership to be a total return vehicle for our unit holders. When measuring total return, you look at both the quarterly unit distributions and the unit price appreciation as used to calculate the return to the unit shareholder. As we look back to the total return of the partnership from our IPO in September 2007, the partnership has an outstanding total return of 19.8% through February 17, 2010 using a unit price of $20.20. During the period since IPO, we've returned distributions of $4.95 per unit to all our unit holders. If you were able to participate in the two subsequent unit offerings on May 22, and July 6 of 2009, the total returns are even higher at 39.7% and 52.4% respectively.
In today's market its hard to find many investments that rival these results. We've been able to accomplish these staggering results by sticking to some basic principles in the partnership. Purchase world class long-lived producing properties with flat production profiles grow through acquisitions and drop downs and avoid large drilling programs that's steeping your production decline profile. Execute a long-term and consistent hedging strategy that seeks to protect two-thirds of the down side commodity risk while allowing the investor exposure to two-thirds of the upside from commodity prices. And then utilize a variable distribution policy that such a minimum distribution to our shareholders protect the balance sheet and return the excess to the unit holders. We firmly believe this business strategy has proven and will continue to prove to be the best strategy over the long run for all types of commodity price cycles.
Now lets look into the future of ENP. as we've discussed our strategy over the last couple of months with the Denbury management team has clearly agreed with the business strategy of the partnership and should the merger of EAC and Denbury be approved by their respective shareholders Denbury does not plan to change while its been a very successful strategy. Furthermore, they do plan to utilize the partnership most likely in a manner very similar to the parent-sponsor relationship with EAC at its share with ENP to the greater success of both entities. We have worked together with their management team to identify a number of properties that would make excellent drop down candidate as part of their de-leveraging process post merger.
Right now Denbury has its own ideas for different alternatives to use the partnership and the dropdown suggestions that we've made and they are going to look at these different scenarios over the next few months and do what makes sense to both the ENP unit holders and the Denbury shareholders. Looking to the future of ENP, we have every bit of confidence in the Denbury management team and their ability to continue on a successful path with ENP unit holders.
Now I will turn it back over to Phil.
Great there is a lot of information in all these different reports but lets open it up and turn it back to Amy for Q&A.
(Operator Instructions). Our first question comes from Scott [Wilmuth] of Simmons & Company.
Hey, guys, just looking at your estimated divestiture proceeds range of $500 million up to $1 billion, are you planning on using all proceeds to delever? Or is there a specific dollar amount you are targeting?
Well we'd say we would at least 500 that was two things one is to delever a little bit and as Mark pointed out we have budgeted a bit more expenditures than cash flow. So its kind of a two-prong purpose. We've kind of said $1 billion is kind of the upper end, we are going to probably market few more properties and maybe necessarily we'll sell. But we'll just see what the interest is and see what the sort of prices we get.
Okay. Then can you give us an update on CO2 sources in the Rockies in regards to the DKRW plan? I know they are in the DOE loan guarantee program. And then the LaBarge facility with Exxon?
Tracy do you want to do that.
Scott we still continue to talk to DKRW along with several other potential sources in the Rockies, we do not have any contract signed at this point other than the Lost Cabin contract that Encore has. But hopefully here over the next several months we have to be able to reach conclusion on some of those contracts.
When should we know how the DOE loan guarantee falls through for them?
That's an interesting question cause I keep getting different things from different developers out there. The best I can say is they all hope to have something definitive by the end of the second quarter, but you know they keep getting timelines changed on them too, so we just have to wait and see.
Okay. Then lastly, when can we expect results from [Dry Dock], the exploration well at Jackson Dome?
Its probably another 30 to 60 days of drilling and then we'll have to test it and all that so. We got a couple of months anyway.
Your next question comes from Noel Parks at Ladenburg Thalmann.
Noel Parks - Ladenburg Thalmann
Couple questions, especially for Bob with the various fields. You had a quarter where a lot of fields were all going in the right direction, including you even had some pickup at Mallalieu you said. But going forward, can we expect that we're going to have a lot of quarters where, because of different maintenance projects and facility expansions and compression expansion, and so forth, that you kind of have these all sort of coming online in a staggered enough way that the overall production rate is going to be sort of more predictable, less lumpy going forward?
Well I think what we have here you look at some of the material field and some of those material field I'd like to mention Mallalieu kind of those filed yeah they may be a little bit lumpy but I think what we are now Noel, though, we will have over 13 injection projects, but I don't think you are going to see it as lumpy as we were before because we have now Delhi and we have things that we have highly plain field. Those are fairly large fields and large production potentials and I think those are going to help us be not as lumpy and I think that you'll see it hopefully we have improving production already. I think we are going to get away from some of that lumpiness because at you may just say 6 or 8 now we double that so I think you'll see that it will be moving in our production.
Noel Parks - Ladenburg Thalmann
Okay, great. And you mentioned at Soso that you are using these jet pumps and that they were having a big positive impact. I'm not familiar with those. Can you just talk a little bit more about those and their applicability in other fields?
Yeah what we do is sometimes a reservoir has and expression Soso if the water is little bit heavier it's a so what we do with some of these wells, we have to wait for them to kick off and the jet pump it's a pump that allows us to produce the wells normally we wait and let them flow naturally with the CO2 refresh [lodging] of reservoir, while with the jet pumps once we feel like we have reservoir pressure that should allow the well to produce, we can put the jet and that jet pump allows the wells to kick off or unload for hydrostatic head and that's when its produced faster and we think its going to help us I do think we have application in other field especially when we get out in the margins at some of these fields at the reservoir rock may be not as a quality, there are so I do think that we will see that these jet pumps are going to help us and I do think that's going to help us go back to your question, it'll be less lumpy I think its going to help us. With simpler production.
Noel Parks - Ladenburg Thalmann
Okay, great. And can you just go over or repeat what you said before about the pipeline schedule for the Green Pipeline, the Oyster Bayou hookup and the Galveston Bay Crossing and so forth?
Okay, we were able to complete the pipeline and that to completed mechanically complete. We do have to do a lot of work to put in valve and fix stations and metering stations and cathodic protection that work is going on right now and moving again. That's the line now it intend to complete or welded out between Donaldsonville all the way to Oyster Bayou. We did finish that in December. Now what we have to do and so once we get that work and we hope to have that done by mid year we'll be up to inject Oyster Bayou sometime mid year.
And then the other three segment we had a 20 mile segment Oyster Bayou over to Galveston Bay which is on the end and there we have to cross the water in Galveston Bay and that would start in April and then we have a 25 mile segment from the west side of Galveston Bay up into Hastings and that will also be started. As we hope to have everything completed, hope to have commission, the valves and everything and it will be injecting in December of 2010 at the Hastings.
Noel Parks - Ladenburg Thalmann
Okay. And on the Encore side for a second time, I just had some questions about the Bakken and just two things. Now that you have another quarter of production, wondering whether you can talk anymore about declines and how they meshed your model for some of the earlier wells and then some of the more recent wells that have had better production. And then if you could just talk a bit more about your current focus either particular areas that you are planning to do more drilling in or areas that are going to be less emphasized going into 2010?
As far as our model goes, our model is holding up well as far as you know what we used to forecast the declines with. We continue to re-frac wells as mentioned earlier we did ref-frac three wells last quarter and they came on a 2 to 3 months then rode at an average of 160 barrels and re-frac them for about 300,000 that what's been averaging for the rest of the year, and that equates to about 80,000 barrels per re-frac, so that's drilling very well and continues to go as we have seen in the first part of the year.
You know this program of two rigs is concentrating on some high quality locations in Charleston Bear Creek, Murphy Creek area and there are plans to possibly pick up a third rig in the second quarter of this year. That rig will probably go out to [Cherry] and bounce back and forth from some of the cherry wells into the Bear creek and Murphy creek area. So those are the areas that we are concentrating on now and I think Danbury will continue to concentrate for the rest of the year.
Noel Parks - Ladenburg Thalmann
Okay. And just one last. Ben can you update your total acreage count in the Bakken?
Its about the same as it was before more or less 300,000 acres.
(Operator Instructions). Our next comes from Drew (inaudible) at Lazard.
Eric Hagen - Lazard
Hi, it's actually Eric Hagen. Two quick questions. The first one is in terms of potential Tertiary reserve bookings this year. What fields do you think you might be able to book reserves? Then in particular, do you think you'll have any significant bookings at Oyster Bayou and Delhi?
The most likely would be Delhi as we expect first production sometime mid second half of the year. Oyster Bayou we don't expect any I guess its possible but we don't expect any that field is in a relatively low pressure that's very large we think it'll be closer to the high-end of the 9 to 12 months first production if you put that into next year.
We are getting close to we believe and talking to talking to D&M, we don't have a confirmation but we do believe we are getting close in fields like. Eucutta and some of those where we've only booked that 75% of our what we think is there the roughly 13% recovery effect we think that we could start may be seeing some bookings in those fields soon because those are much smaller one there is something like a Delhi.
Eric Hagen - Lazard
How big is Delhi again, the potential? Or have you disclosed that before?
Yeah 17 set number recovery factor in the 33 million - 34 million barrel.
Eric Hagen - Lazard
Okay, great. The other question I had was just for Encore on the Bakken. Out of your 300,000 I'm assuming that's pretty close to a net acreage number, but how much of that do you think has been de-risked or where you have some decent well control from your drilling or other operators' drilling?
I think this is again Ben when you look across our the field that we are in only the [Almond] area hasn't been significantly de-risked a lot of that going on and the cherry area now that's de-risking a lot of that de-risked a lot of that area. So only the [Almond] is what I can say there is not de-risk and that only represents about 15% of our acreage.
(Operator Instructions). We have another question Andrew Coleman from UBS.
Andrew Coleman - UBS
Hey, just wanted to slip in one quick question here. Just if I heard you right earlier, you said that pro forma the two companies would be about 430 million barrels and about 5.2 billion of PV10 on the new reserve rules. Is that correct?
That's correct. That's SEC pricing.
Andrew Coleman - UBS
And it was 5.8 million for Denbury at the strip?
Yes, that's. Denbury only at 5.
Andrew Coleman - UBS
Right, do you know or does someone have the pro forma at the strip? Just save me a whole lot of work.
We don't have that, but we can think get it for you, but we don't have that today. But I would assume that the ratios would be pretty similar.
Our next question comes from Brian Kuzma from Weiss Multi-Strategy.
Brian Kuzma - Weiss Multi-Strategy
I was just curious; actually similar question to Andrew's. Do you guys have a PV10 number on just your developed reserves, for both Encore and Denbury?
We do have it, but I don't have it here in front of me, just what the proved developed would be.
Brian Kuzma - Weiss Multi-Strategy
Okay that percentage is what 61% on a BOE basis.
62% is pre developed.
Brian Kuzma - Weiss Multi-Strategy
Okay, but I'm talking about like percentage of the PV10. I'd assume it's like 90% or something like that, right?
They won't be that I guess.
We look and see if we can find it, Ben do you have…
I don't have a break out about the (inaudible) but again 80% is pre developed so more than 80% is going to be pre-developed.
You are going to check backwards is after the call we can look those up for you.
(Operator Instructions). Next question comes from Mitch Wurschmidt of KeyBanc.
Mitch Wurschmidt - KeyBanc
Hi, guys. I was just wondering if you could give any more color on specific properties you are looking to divest once the deal closes. Like production or proved reserves on those properties, too.
I don't have the exact production in reserves in front of me for those properties. It looks like we could primarily going to market the majority of the southern region which is West Texas, Esst Texas, Oklahoma, mid-continent and we are also probably going to look at marketing the Haynesville. But as Phil mentioned whether or not we sell all that still remains to be seen.
Mitch Wurschmidt - KeyBanc
Then when you say $500 million to $1 billion range, is that based on just the value attribute possibly to those properties? Or just based on if you can get all the properties sold, high or low end?
No the range for that whole set is not 500 million. The value if we sold everything would probably be around a $1 billion, obviously, if we sell [$500 million] we would be selling a subset of that.
Mitch Wurschmidt - KeyBanc
Okay and does that include possible dropdowns in ENP?
(Operator Instructions) At this time we show no further questions I would like to turn the conference back to management for any closing remark.
Okay thanks everyone. As you can see there is a lot of things happening, we hope to have some good news for you here in a couple of weeks after the shareholder meeting. Looking forward a little bit I'd like to also announce that we have postponed our analyst meeting and rescheduled it for late March. And we are going to postpone that to late May. Basically we just felt like the later meeting would be more productive and informational, as we will have first quarter results and hopefully we'll have a bit more direction on our planned asset sales. We do plan to launch that divestiture process right after closing. So potentially in 60, 90 days we'll know what proceeds would be in hand and maybe have some contracts. So watch for upcoming details on the meeting the format will be the same we'll have a group presentation in New York followed by one on ones with the entire senior management team at Denbury followed by a day in Boston and then we are also going to catch Chicago, San Francisco and Los Angeles with Tracy and myself. So if you want to schedule a one-on-one at these meetings, or check on any other planned conferences or trips, please contact Laurie Burkes, our IR Manager in the office. But importantly, obviously, stay tuned. A lot of positive things are happening, and we look forward to a great 2010. Thank you.
The conference has now concluded. Thank you for attending today's presentation, you may now disconnect.
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