UNT
#Thank you, Christine.
Good morning, everyone.
We want to thank you for joining us this morning.
With me today are <UNK> <UNK>, <UNK> <UNK>, <UNK> <UNK> and <UNK> <UNK>.
Each of these gentlemen will be providing you with updates concerning their segments.
After their comments are concluded, we will take questions.
Before we begin the segment reports, I'd like to [overview] some remarks about the Company and more broadly, the state of the industry.
We've entered into another challenging year in which our focus continues to be on balance sheet preservation.
We've made numerous difficult decisions about activity levels, capital expenditure price and G&A levels.
We cannot control commodity prices, therefore we must and will focus on things within our control.
The industry has responded to unsustainable price levels by substantially reducing capital expenditure budgets.
As a result, drilling activity has fallen to unprecedented levels within the US with the total US land rig count dropping 42% since the end of 2015.
Our capital expenditures are budgeted at a level which will keep spending within anticipated cash flow for the year.
At the end of the first quarter, we had no rigs operating for oil and natural gas segment.
Only in hindsight, we believe with absolute certainty be able to determine the ultimate duration of this cycle.
We will adjust our operational cadence to levels to ensure that we will weather the storm.
Although we approach the future with cautious optimism, we feel we are beginning to see some signs of improvement.
According to the most recent Baker Hughes rig count, there were only 391 working US land rigs as of April 29, 2016, a new record low dating back to 1949.
As a result, we are beginning to reach the tipping point on US crude production.
Prices have, for the moment, bounced off the first quarter lows.
According to the EIA reports, US crude production has begun to decline pretty dramatically.
EIA monthly reporting reflects US crude oil production declined by 565,000 barrels per day from April of 2015 to February of 2016.
EIA weekly data from February of 2016 to present reflects an additional reduction of 304,000 barrels of oil per day.
On the natural gas side, monthly and weekly production reports are a little more mixed.
It appears at the US dry natural gas production may be declining ---+ may be beginning to decline due to the effects of reduced drilling and completion activities.
Equally important, increases to natural gas demand associated with power generation due to coal and gas switching and exports to Mexico and LNG cargos totaling approximately 4 Bcf a day, suggest an increasing demand.
Furthermore, new chemical and fertilizer projects scheduled to come on line in 2017 appear to bode well for future demand.
In conjunction with periodic price improvements, we have taken the opportunity to layer in a few more hedges to protect cash flows for the remainder of 2016 and 2017.
We're trying to be opportunistic to create value for our shareholders.
I would now like to turn the call over to <UNK> <UNK>.
Good morning.
We reported an adjusted net loss for the first quarter of $20.3 million or $0.41 per share, which excluded the effect of non-cash derivatives and ceiling test write-down.
Our non-GAAP financial measures reconciliation is included in our press release.
For the oil and natural gas segment, revenues for the first quarter decreased 23% from the fourth quarter because of lower commodity prices and a decrease in production.
Operating costs for the first quarter decreased 8% from the fourth quarter.
This decrease is because of lower lease operating saltwater disposal, production tax, and general and administrative expenses.
For the contract drilling segment, revenue for the first quarter decreased 23% from the fourth quarter because of a decrease in the number of drilling rigs operating and lower day rates.
Operating costs for the first quarter decreased 14% from the fourth quarter because of fewer drilling rigs operating.
For the midstream segment, revenue for the first quarter decreased 15% from the fourth quarter because of declines in liquids sold and processed volumes and lower natural gas liquids prices.
Operating costs for the first quarter decreased 15% from the fourth quarter because of lower gas purchase prices and volumes.
The effective income tax rate for the first quarter was 27.6% compared to 37.8% for 2015.
The decrease was because of an increase in deferred tax expense related to the vesting of restricted stock in the first quarter of 2016.
We anticipate the effective rate for the balance of 2016 to be approximately 37.4%.
We ended the first quarter of 2016 with total long-term debt of $898.7 million, consisting of $638.5 million of senior subordinated notes, net of unamortized discount and debt issuance costs, and $260.2 million of borrowings under our credit agreement.
In early April, we amended our credit agreement, which among other things, set our elected commitment and borrowing base at $475 million and established our maximum senior leverage covenant to be no greater than 2.7 times EBITDA through the first quarter of 2019.
The borrowing base consists of our oil and gas properties and the midstream business, and does not include our fleet of drilling rigs.
We believe our liquidity will be adequate to carry out our 2016 capital plans.
For 2016, our capital expenditure budget remains unchanged from the beginning of the year and is below our anticipated cash flow and proceeds from non-core asset sales.
Our capital expenditure budget is $161 million to $187 million.
The budget is based on realized prices of $34.57 for oil, $8.01 for natural gas liquids and $2.24 for natural gas.
By segment, our 2016 capital expenditures are a range of $109 million to $131 million for the oil and natural gas segment, a range of $9 million to $11 million for the contract drilling segment, of which 56% to 69% is associated with certain components for future BOSS rigs, and $22 million to $24 million for the midstream segment, of which 52% to 57% is associated with fee-based projects in the Appalachia area.
At this time, I'd like to turn it over to <UNK> <UNK> for comments on the E&P segment.
Good morning.
Starting in the Wilcox, we are pleased with the operational results for the first quarter of 2016.
Production for the quarter increased 3% as compared to the fourth quarter of 2015, and is up 30% as compared to the first quarter of 2015.
Our initial two Gilly field horizontal wells have now been online for approximately one year, and the wells are still producing at impressive rates of approximately 16 million cubic feet equivalent per day and 9.5 million cubic feet equivalent per day.
During the first quarter of 2016, we drilled and completed four new horizontal Wilcox wells.
Two of the wells are located in Gilly field and two are located in separate nearby fields.
One of the Gilly field horizontal wells started producing in early February at a peak 30-day rate of approximately 12.7 million cubic feet of gas equivalent per day from the Wilcox Gilchrease sand intervals.
The second Gilly well was drilled in the shallower Wilcox Segno interval and also started producing in early February at a peak 30-day rate of approximately 5.6 million cubic feet of gas equivalent per day.
The lower IP rate for this well is most likely due to poor sand quality in this portion of the field.
The other two horizontal wells completed during the first quarter were recently fracture stimulated, and the results from these wells will be discussed on the next conference call.
As planned, we released the Unit drilling rig in mid-March in the Wilcox with currents plans to potentially add back the Unit rig in the fourth quarter of this year.
Behind pipe re-completion program, the Wilcox is also achieving great results.
During the first quarter, we re-completed three new behind pipe Wilcox zones in existing vertical wells that were producing from deeper Wilcox sands at marginal rates.
Our average working interest in the three-rig completions is 85%.
Prior to the re-completions, the combined production rate for the three wells was approximately 25 barrels of oil per day and 300 Mcf per day.
After the re-completions were done, the oil rate increased from 25 barrels of oil up to 900 barrels of oil per day and the gas rate increased up to 15 million cubic feet per day.
This is a 45-fold production increase.
The total cost for re-completing all three wells was approximately $700,000 or about $235,000 per well completion.
The CapEx amount is lower than expected because two of the wells that were re-completed did not require fracture stimulation at this time.
In general, the overall production results were higher and the capital costs were lower than what we had forecasted.
During the remainder of 2016, we anticipate completing four to six additional behind pipe re-completions.
Our Wilcox team is continuing to make progress in evaluating and leasing in several new Wilcox's lead areas.
Some of these new projects are anticipated to be tested in 2017.
In the SOHOT Hoxbar area, operational results for the first quarter were in line with what our expectations were.
Oil production on a per day basis increased 3% as compared to the prior quarter.
However, overall SOHOT total production decreased 6% on a per day basis, primarily due to natural gas declines as a result of not drilling any new Medrano gas completions.
Three horizontal Marchand sand oil wells were completed during the quarter with an average 30-day production rate of approximately 800 barrels of oil equivalent per day, which is consistent with our current type curve.
A fourth horizontal Marchand well was recently fracked in late April and is currently in the early stages of flowing back.
As scheduled, the drilling rig was released in early March and current expectations are to potentially resume drilling in the fourth quarter of this year.
Our leasehold in SOHOT core increased 5% during the first quarter to 18,721 net acres.
At this time, I'll turn the call over to <UNK> for the drilling company updates.
Good morning.
The first quarter has continued to be a very challenging time for our contract drilling segment, as we faced the depressed demands for drilling services.
The average day rate for the first quarter was $18,392, a decrease of $212 per day from the fourth quarter.
The average total daily revenue before inter-company eliminations and including early contract termination fees was $20,473, which was a decrease of $506 from the fourth quarter.
Our total daily operating cost before inter-company eliminations increased by $1,007 per day for the first quarter as compared to the fourth.
This increase in daily cost is largely attributable to having fewer days over which to spread fixed cost.
The average per day operating margin for the first quarter before the elimination of inter-company profits and bad debt expense was $5,651, which is $1,607 per day decrease from the fourth quarter.
The reduction in total revenue and an increase in daily expenses attributed to the lower daily margins.
Our average number of active rigs during the first quarter was 20.6 rigs, which is 6.6 less than the fourth quarter.
We began the quarter with 26 operating rigs and decreased to 15 at the end of the quarter, which is fairly consistent with the industry drop in active rigs.
Currently, six or our eight BOSS rigs are under contract.
We are very confident that we will persevere through the current market conditions because of our history of being financially prudent, our long-term relationships with key operators, and the versatility of our fleet and our people.
We have initiated several cost saving programs and reduced our CapEx budget to maintain our financial liquidity.
We are maximizing the efficiency of our staff with consolidations and additional job responsibilities, and in many cases, elimination of positions.
We have combined three of our division offices into one and closed two of our offices.
We have also suspended operation of our trucking fleet in the Texas Panhandle.
We recently reduced the wages for the drilling crews and also salaries of all the drilling segment employees to further reduce daily expenses.
All of the above changes will show as potential savings going forward.
At this time, I'll turn the call over to <UNK> for the Superior Pipeline update.
Thank you, <UNK>.
Superior Pipeline began 2016 with positive results despite the low price environment [persisted] in the first quarter.
During the first quarter of 2016, we increased total gathered volume per day by 15% compared to the first quarter of 2015.
This increase in volumes, along with our focus on controlling operating expenses, resulted in better than expected overall financial results.
We're currently operating 26 individual gathering systems in Oklahoma, Texas, Kansas, Pennsylvania and West Virginia, which includes 1,465 miles of pipeline and 13 gas processing plants.
During the first quarter of 2016, we connected 22 new wells to our systems.
Additionally, during the first quarter of 2016, we completed construction of the new fee-based Snow Shoe gathering system in Centre County, Pennsylvania and connected three wells in this gathering system.
During the first quarter of 2016, our NGL gallons sold were lower by 9% compared to the fourth quarter of 2015 because we were operating in a more profitable liquids projection load due to depressed liquids pricing during the quarter.
During the first three months of 2016, we invested $2.7 million in capital projects as compared to $7.7 million in the first three month of 2015.
Our 2016 capital expenditures are estimated to range between $22 million to $24 million.
I will now focus upon several key areas of our midstream business.
In the Mississippian play in north-central Oklahoma, at our Bellmon processing facility, during the first three months of 2016, we connected five new wells to the system, and the average throughput volume was approximately 36.2 million cubic feet per day.
This facility has the ability to process approximately 90 million cubic feet per day from two processing skids.
Also in the first quarter of the year, with the installation of additional compression, we're able to connect and receive additional production from third-party producers in the area.
In central Oklahoma, at our Cashion facility, our average throughput volume for the first quarter of 2016 was 32.8 million cubic feet per day.
This processing facility has the ability to process 45 million cubic feet per day.
We are in discussions with producers who are actively drilling Meramec wells on the northwest end of our gathering system.
We are currently in negotiation contract terms and are optimistic we will able to connect this new production to our system.
At our Segno gathering system located in Southeast Texas, we continue to increase our gathered volume.
In the first quarter of 2016, we finished two new wells and we averaged approximately 85 million cubic feet per day.
During the first quarter of 2016, we completed several upgrade projects, including the gas pipeline extension.
With the completion of this project, we increased overall gathering capacity of the Segno system to 120 million cubic feet per day.
In the Appalachian area, Pittsburgh Mills northern expansion has been completed.
This expansion project extends our system into Butler County, Pennsylvania and provides an additional outlet for our gas.
During the first quarter of 2016, we connected 10 new wells from two well pads, and averaged approximately 92.3 million cubic feet per day.
Once all the wells are fully functional and are flowing for the full month, our volume will average between 145 million to 150 million cubic per day.
We are also working on connecting two more well pads that have a total of eight wells to the northern portion of our system.
These pads are scheduled to begin production in the third quarter of this year.
Construction of the gathering lateral to connect the first pad has been completed, and we expect to begin construction of the pipeline to connect the second pad as soon as the permit is approved.
With all these wells connect to our system, we anticipate our throughput volume to remain at approximately 150 million cubic feet per day for the remainder of the year.
All of this gas is being produced as dry gas, [not being to be] processed.
Also in the Appalachian area and our newly completed fee-based Snow Shoe gathering system located in Centre County, Pennsylvania, we connected the first part to the system in February with two additional wells connected in March.
Our throughput volume averaged 7.1 million cubic per day for the first quarter of 2016.
We've completed construction of the gathering lines to connect three additional wells from a different producer in the area.
These wells have been connected and started flowing in April of this year.
As compression will not be required initially, we are postponing the construction of the compressor station until it's required at a future date.
In summary, we are off to a strong start in 2016 in Superior Pipeline, as we continue to focus on key areas in our midstream business.
Total throughput volume increased in the first quarter mainly due to the additional wells connected to our gathering systems in the Appalachian area.
We have been able to maintain consistent financial results due mainly to our fixed fee systems, which have low commodity price impact, while retaining the upside in our commodity based systems when price improve in the future.
As liquid prices continue to be depressed, we are operating in full ethane rejection mode at our processing facilities, which reduces the amount of liquids recovered, but it's the correct economic decision in this price environment.
With the success of our Appalachian area, along with our focus on the controlling costs, we feel our midstream segment is situated very well to have another successful year.
At this time, I'll now turn the call back over to <UNK> for some final comments.
Thank you, <UNK>.
Before moving to the Q&A, I would like to once again highlight just a few points.
The first quarter has been very challenging.
We continue to be diligent about taking appropriate steps to build value.
As <UNK> discussed, a very important step was working with our bank group on our borrowing base redetermination and covenant modification.
We are positioned well to manage through the cycle with no near-term maturity issues.
With continued focus on executing on the appropriate measures, we are very confident that we will get through the duration of this cycle and our shareholders will see the benefit of our efforts to that end.
I would like now to turn the call over to questions.
Well, we are not using the combination of different vehicles to hedge.
We're using collars, we're using three-way collars, we're taking in some cases some pretty wide collars, leaving lots of upside on the commodity pricing and not trying to protect the oil price, the bottom of the oil price at $40 or $45, but taking some wider type collars [on our shale] gas.
On gas, we're a little bit more narrowly focused on ---+ we're not as confident I guess as the potential for a dramatic movement of gas prices as we think the potential could be there for oil.
We're still ---+ Unit, again, is somewhat unique.
Even if we hedge to 100% of our oil and gas, we're still totally unhedged on our natural gas liquids, we are totally unhedged on our rig side, and we're totally unhedged on our midstream side.
We're not a typical just E&P company.
If we hedge all of our oil and gas production, we've taken all the upside out.
There is going to be demand for the SCR rigs.
We still have customers for SCR rigs or AC rigs today when they could be using AC rigs, but the customer base ---+ the major customers, the major companies that are out there are going to be more prone for AC rigs.
More of the independents are going to be indifferent.
Their biggest concern will be price, what the charge is on the rigs.
We are still putting ---+ we've still got SCR rigs running today.
So, I'm not ---+ so whether all of our AC rigs go back to work in the next 12 months or not, this is going to depend on price.
But if your price projections on oil happens, you will see the majority of our SCR rigs go back to work.
<UNK>, the re-completions we did in the first quarter certainly exceeded what our expectations were.
But in general, the re-completions are primarily in Gilly field, that general area.
But the wells that we drilled anywhere three, four years ago, vertical wells that have a lot of stack pay in it.
So we're originally producing the wells out of lower zones, those wells had to produce, and in many cases, produced very well, but have come down.
We target a rate somewhere between 0.5 million and 1 million a day.
When one of the wells gets down to that level, we look at re-completing the well, and what that entails is setting a temporary bridge plug above the zone that's currently producing, so you block off that production, you come up, you perforate the new zone, you frac that zone, you produce it till the pressure of the new zone gets down to a level where you could comingle it back with that lower zone, and then you go back and drill the plug out.
Essentially, the previous zone and the new zone produce together for some length of time, and then you go through the process again until you essentially re-complete the whole wellbore.
And in many cases, in the Gilly field, you might be talking about six different re-completions.
The cost for the quarter is lower.
Our average cost for re-complete is about $600,000 per well.
The cost for this quarter was below normal because two other wells we re-completed, we didn't have to frac at this time.
When you go back to frac it, then your cost will be somewhere in that $600,000 range per completion.
The cost, overall costs is certainly down and probably about a third overall, but the drilling cost ---+ to give you example, the early Gilly wells we drilled out there were in $3.5 million to $4 million range.
We're currently now drilling that at about $2.5 million to $2.6 million or $2.7 million.
The main cost, certainly, of the deeper Wilcox wells is the frac cost because it's high pressure.
You have to use bauxite.
And those costs, although they've come down probably in the range 40%, it's still the biggest cost item of these horizontal wells.
But our cost in general for the newer Wilcox wells will range somewhere around $6.5 million up to the high end of maybe $8 million.
Some of the previous wells were in the $9 million to $12 million range.
We are rejecting as much ethane as we can.
It's still substantially under water price-wise to try to recover ethane.
Over the next two quarters, I don't see anything changing, unless gas totally crashes in price.
Difference in the gas price and ethane values determine whether you recover or reject, and gas has strengthened from (inaudible) improvement.
Now, next year, as the new petrochem plants come on line and start demanding ethane to produce ethylene, I think there might be a substantial jump in ethane and propane 18 months out.
So, there is light at the end of the tunnel.
From all indications, the people that are using the BOSS rigs now are so pleased with them, they will want to continue.
Needless to say, the prices will be different because those prices were established 1.5 years, 2 years ago and the market has changed so much.
So we'll have to expect lower day rates.
But I don't see any of our present operators wanting to release those rigs when the time expires.
Thank you, Christine.
Thank you very much everyone listening in this morning.
Things are looking better.
Compared to where we were 60 days ago, things are starting to definitely look a little more optimistic, and we're not by any means calling a bottom to the market.
Everything is going to be up to the right.
But the general feeling is, it's feeling better than where we have in the several months.
So thank you again, and we will be talking to hopefully most of you over the next few months.
