UNT
#Thank you, Ellen.
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 get into the individual segment reports, I would like to offer some comments about 2016 and where we stand with regard to 2017.
We are pleased to have completed 2016 and have it behind us.
It was a year with many challenges but also many positive accomplishments.
Our behind pipe recompletion and the workover program in the Wilcox has been successful with a limited capital spend.
Wilcox production increased in excess of 20% year-over-year.
Our extended lateral well in the Buffalo Wallow area of the Granite Wash has performed well, above pre-drill expectations.
In our contract drilling business, we lived through the full ---+ hopefully have gone through the full industry slowdown before rebounding to the present 26 operated drilling rigs.
We were able to generate excess cash flow from the segment sufficient to build out our ninth BOSS rig.
Our midstream business had a remarkable year by many measures.
Our systems have ample available capacity to take advantage of growth opportunities as operator capital budgets expand.
This segment is also well positioned to take advantage of natural gas liquid price improvement.
As we enter 2017, we are establishing a capital expenditure budget that is in line with visible cash flow for the year.
Due to a better pricing outlook, our budget will be increased 32% to $227 million for 2017.
The budget is allocated $188 million for the oil and natural gas segment, a 57% increase; contract drilling $24 million, a 26% increase; and midstream $13 million, a 23% decrease.
Our capital expenditure budget is subject to periodic review and change based upon prevailing conditions.
Following the curtailment of drilling activity during 2016, Unit resumed drilling activities in the fourth quarter of 2016.
Unit's oil and natural gas segment's 2017 production is anticipated to trough in the first quarter of 2017 and then begin growing sequentially in subsequent quarters.
Overall, Unit's 2017 production is expected to decline 5% to 8% year-over-year for 2016.
Following the two quarter suspension of drilling activities during 2016, lower average commodity prices of non-core divestitures resulted in a reduction of year-end reserves as compared to 2015.
We ended the year with total proved reserves of 118 million barrels of oil equivalent, of which 16% were proved and undeveloped.
While we are cautious to declare that the cycle is over, positive trends are emerging that has certainly brightened the outlook.
Commodity prices appeared to at last be headed in a better direction.
The industry has responded positively as seen by the US land rig count, which has grown from a low of 374 to 730 as of last Friday's Baker Hughes report.
We are beginning to see service cost increases in conjunction with equipment, reactivation and activity levels.
While the majority of the increase appears thus far to be on the pressure pumping side, some improvement on a spotty basis is being noted on drilling rig day rates.
OPEC appears to be largely complying with agreed-upon cuts in crude oil production, and there's even discussion of a possible extension of the cuts to alleviate world inventory surpluses.
New petrochemical capacity being placed into service bodes well for natural gas liquid prices.
Natural gas prices continue to be primarily influenced by weather, and at this point we appear to have had another mild winter.
All in all, it was a good quarter, with a positive outlook for the future.
We believe we have taken steps to position the Company to take full advantage of improving market conditions while we continue to maintain the financial discipline that our shareholders have grown to expect and we very much look forward to the return to growth in all three of our segments.
I'll now turn the call over to <UNK> <UNK>.
We reported net income for the fourth quarter of $1.7 million or $0.03 per diluted share.
Adjusted net income for the quarter, which excludes the effect of non-cash derivatives, was $12.2 million or $0.23 per diluted share.
Our non-GAAP financial measures reconciliation has been included in our press release.
For the oil and natural gas segment, revenue for the fourth quarter increased 11% over the third quarter because of higher commodity prices.
Operating costs for the fourth quarter increased 6% over the third quarter because of higher lease operating expenses, production taxes and bad debt expense.
For the contract drilling segment, revenue for the fourth quarter increased 29% over the third quarter because of an increase in the number of drilling rigs operating, somewhat offset by lower average day rates.
Operating costs for the fourth quarter increased 13% over the third quarter because of more drilling rigs operating.
For the midstream segment, revenue for the fourth quarter increased 9% over the third quarter because of an increase in natural gas liquids and condensate prices, somewhat offset by lower volumes.
Operating costs for the fourth quarter increased 8% over the third quarter because of higher gas purchase prices, somewhat offset by lower volumes.
We ended 2016 with total long-term debt of $800.9 million, a reduction of $53.7 million and $118.1 million from the end of the third quarter of 2016 and fourth quarter of 2015, respectively.
Long-term debt consists of $640.1 million of senior subordinated notes net of unamortized discount and debt issue cost and $160.8 million of borrowings under our credit agreement.
Our current borrowing base associated with the credit agreement is $475 million.
The borrowing base consists of our oil and gas properties and the midstream business and does not include our fleet of drilling rigs.
Our senior leverage ratio was 0.64 times at the end of the fourth quarter and the maximum senior leverage covenant is to be no greater than 2.75 times EBITDA.
At this time, I'm going to turn the call back over to <UNK>.
Thank you, <UNK>.
As you know, in today's press release, Brad Guidry, who many of you know, announced his retirement as of March 31, 2017.
Brad has been a great asset for us, with the nearly 30 years he has been here.
We will miss him, but we wish him the very best in his retirement.
While we will miss Brad, we are very fortunate to have <UNK> <UNK> as his replacement.
<UNK>, as many of you know, is our Senior ---+ our current Senior Vice President of Exploration and Production for Unit Petroleum Company.
<UNK> has been with us since 2007 and we believe he is ready to assume the mantle of leadership of this business segment.
At this time, I would like to turn the call over to <UNK> for his review of the oil and natural gas segment.
Good morning.
The Petroleum Company had an excellent fourth quarter.
Production for the quarter increased slightly from the third quarter due to the recompletion program in our Gulf Coast Wilcox area and despite having no new operated wells contribute to production during the quarter.
Additionally, fourth quarter operating expenses were 24% lower when compared to the fourth quarter of 2015.
In the Texas Gulf Coast Wilcox area, production for 2016 averaged 94 million cubic feet equivalent per day, which is a 22% increase as compared to 2015.
During the fourth quarter, we continued our very successful recompletion program by completing 10 new behind pipe Wilcox recompletions for $3 million, which resulted in a net production increase of almost 10 million cubic feet of gas per day and 300 barrels of oil per day.
During 2017, we plan to complete another 10 to 15 recompletions.
We picked up Unit rig number 319 and spud the first of three wells in mid-January of 2017.
After drilling these three wells, we plan to drop the rig for a few months to allow us to see production results and then pick the rig back up in the third quarter to drill four additional wells before year-end.
Drilling capital for the seven-well drilling program in our Wilcox area is approximately $45 million.
During January of 2017, planned maintenance of the third-party operated processing plant required Gilly Field to be shut in for five days, resulting in a production loss of approximately 0.5 Bcfe.
The processing plant was back to full operational capability by the end of January.
Even with this production loss, annual production from this area is expected to remain flat to slightly increasing during 2017 as compared to 2016.
In the SOHOT area, production per day for the fourth quarter increased 4% ---+ or decreased 4% from the third quarter of 2016, which was in line with expectations.
The decline in production is due to natural decline rates and because no new wells were completed in the third quarter.
Production from this area is expected to continue to decline through the first quarter before increasing in subsequent quarters as a result of our 2017 drilling program.
As planned, the Company drilled two horizontal Marchand oil wells within the SOHOT area in the fourth quarter of 2016.
<UNK>th wells were successfully fracture stimulated and are being tested now.
After drilling these two wells, the drilling rig was released in January for three to four months as performance of the two wells is monitored.
We plan to begin a seven-well drilling program utilizing a Unit rig in the second quarter and spend approximately $30 million drilling in SOHOT during 2017.
In our Granite Wash plays in Texas Panhandle, production per day for the fourth quarter decreased 8% from the third quarter, which was lower than expectations.
The decline in production is due to weather events that caused slow oil hauling during the quarter and due to natural decline rates with no new wells being completed.
The Dixon 5554 XL [number 1H], our first Buffalo Wallow extended lateral with a 7,500-foot horizontal, completed in April of 2016 from the C1 member (inaudible) of the Granite Wash, continues to perform well, with cumulative production to-date approximately 50% higher than forecasted by the type curve.
Unit rig 152 has picked up in December and began a non-well extended lateral Granite Wash drilling program in the Buffalo Wallow field that is planned to continue throughout 2017.
Drilling capital for this non-well program is approximately $50 million.
For 2017, we will focus on drilling the C1 and A2 members of the Granite Wash, which appear to have similar characteristics.
At this time, I will now turn the call over to <UNK> for the Drilling Company update.
Thank you.
The fourth quarter was a very nice continuation of the improvement that the contract drilling segment began experiencing during the third quarter.
Even though our rig count only increased by four rigs during the quarter, we were able to obtain several contracts for additional rigs that have begun working during January and February of 2017.
Average day rate for the fourth quarter was $16,866, a decrease of $612 per day from the third quarter.
The average total daily revenue with no elimination of intercompany profit and early contract termination fees was $18,413, which was an increase of $908 from the third quarter.
The increase in total revenue was attributable to an increase in other income and mobilization revenue.
Our total daily operating cost decreased by $1,028 for the fourth quarter as compared to the third.
This follows a substantial reduction in operating costs that was achieved during the third quarter.
This large reduction in expense is attributable to lower indirect cost, yard expense and G&A expenses.
The average per day operating margin for the fourth quarter with no elimination of intercompany profits and bad debt expense was $6,478, which is a $1,932 per day increase from the third quarter.
This is a result of increased daily revenue and a reduction in cost.
The fourth quarter results included $885 per day in non-reoccurring cost savings.
Our non-GAAP reconciliation can be found in today's press release.
We began the quarter with 17 operating rigs and increased to 21 by quarter's end, and we presently have 26 active rigs.
Our activity level has remained relative consistent with industry activity levels.
In addition to the 26 rigs currently operating, we have recently received contracts for four additional rigs that are scheduled to return to service during the next few months.
Our ninth BOSS rig was placed into service in the Permian at the end of the fourth quarter.
We already owned the major components for this rig and completed fabrication and commissioning prior to year-end.
This was ahead of schedule and under budget.
Currently, all nine of our BOSS rigs are operating, with seven of them under term contracts.
Our recent cost savings programs and our greater-than-projected cash flows allowed the increased CapEx budget needed to build additional BOSS rig while remaining within our cash flow.
We completed the sale of an over 1,500-horsepower SCR rig and several other excess items during the fourth quarter, which allowed us to do upgrades of various rigs going into service.
During the last six months, we have either put into service or contracted for the first quarter of 2017, 13 1,500 horsepower SCR rigs and one 1,000 horsepower SCR rig.
Eight of these 14 drilling rigs did not require any upgrades or additional equipment.
The other six rigs were upgraded to varying degrees with walking systems, 7,500 psi mud systems and/or hydraulic catwalks.
We remain confident that we will manage through the current market cycle because of our history of being financially prudent, our long-term relationships with key operators, and the versatility of our fleet and our people.
During this recent addition of active rigs, we have been able to prove these rigs with all former employees.
We're optimistic that the current demand for rigs will be sustainable but it will certainly be dependent upon commodity prices.
I'll now turn the call over to <UNK> for the Superior Pipeline update.
Thank you, <UNK>.
The midstream segment completed a successful year, increasing operating profit by 17% and increasing total per day throughput volume by 19% compared to 2015.
These increases were achieved despite the low price environment we experienced in 2016.
While these results were primarily due to increased fee-based volumes, 29% of our gross margin is made up of contracts that are impacted by commodity prices.
While liquid prices remained depressed in 2016, we expect to see an increase in ethane and propane prices, which will result in higher gross margin for our price-exposed processing systems in the future.
This year's increase in total throughput volume was mainly due to connecting additional wells to our fee-based gathering systems located in the Marcellus Basin and our Wilcox Segno system in Southeast Texas.
At the end of 2016, we operated 25 active gathering systems with approximately 1,465 miles of pipeline and 13 natural gas processing plant skids, with total processing capacity of approximately 340 million cubic feet per day.
I will now focus on several key areas on our midstream business.
At our Hemphill facility in the Granite Wash area, our total throughput volume averaged approximately 59.5 million cubic feet per day for the fourth quarter of 2016.
We produced approximately 145,700 gallons per day of natural gas liquids.
At this processing facility, our total processing capacity remains at approximately 135 million cubic per feet per day.
There is active drilling in the Buffalo Wallow field and we expect to connect several additional Granite Wash wells from this area in 2017.
At our Segno gathering system located in Southeast Texas during the fourth quarter, our average throughput volume increased to approximately 91.3 million cubic feet per day.
We connected three new wells to this facility during 2016.
The overall gathering and dehydration capacity of this system is currently 120 million cubic feet per day after the completion of several facility improvement projects.
In the Appalachian area, at our Pittsburgh Mills gathering facility, we continued to connect additional wells and increased total throughput volume.
During 2016, we connected 18 new wells from four well pads to this gathering system.
With these additional wells, the total throughput volume of this system for the fourth quarter averaged approximately 152.7 million cubic feet per day.
We expect to connect the next well pads to this system in the first half of 2017.
Initial construction activities are underway, and we anticipate pipeline construction to begin in the first quarter of 2017 with an estimated completion date in the second quarter of 2017.
In summary, in 2016, our financial and operational results were very attractive given the pricing conditions we experienced this year, mainly due to our ability to connect fee-based volumes in the Appalachian area.
Given our mixture of contracts with 29% of our margin exposed to commodity pricing, we expect to see increased margins at our processing plants and methane and propane prices to improve in 2017.
With the continued success of the fee-based Appalachian area systems, along with our improving processing economics at our processing facilities and our continued focus on controlling costs, we believe the midstream segment is well positioned for continued success in 2017.
At this time, I'll now turn the call back over to <UNK>.
Thank you, <UNK>.
Before moving to the Q&A, we would like to, once again, just highlight a few points.
We have discussed many accomplishments by each of our business segments.
Physical discipline is of critical importance to us, and I believe we have delivered by reducing capital expenditures to a level within cash flow and managing our costs very carefully.
Our oil and natural gas segment has had the opportunity to observe well performance and now we have restarted our drilling activity.
The suggested rates of return that we're achieving will compete with the most popular basins across the country.
We continue to have an ample prospect inventory to deliver strong results for years to come.
The rebound in drilling activity is exciting to see, and the visibility of four additional rigs under contract is suggesting that it will continue for the near-term.
Midstream segment has performed remarkably well, managed to hold its own during the cycle despite reduced operator capital expenditures.
Anticipated improvement in natural gas liquid pricing will provide a platform for continued growth in cash flows.
Overall, we believe we have taken and continue to take the steps necessary to navigate this business cycle.
We have come out of this part of the cycle leaner and well positioned to take full advantage of improvements to create additional value for our shareholders.
Ellen, I would like now to turn the call over for questions.
On the E&P side, we've seen the prior ---+ the primary service cost increase has been on the fracture company pressure pumping, and 2017 currently looks like it's ---+ the pressure pumping's going to end up being maybe 50% to 60% higher than it was, say, in the mid-part of 2016.
That kind of cost increase on the pumping side will result in about a 10% increase to our drilling and completion costs as a whole.
If we picked up and set another rig, that rig would go to the Granite Wash in our Buffalo Wallow field.
Our rates of return there with the current NGL prices are very good and additionally, Superior gathers all of our gas and they process our gas.
So, we get an extra $0.80 per Mcf margin on gas for us ---+ or they get a ---+ Superior makes $0.80 per Mcf margin.
So, as a corporation, the economics look really good for a second Buffalo Wallow rig.
The activity ---+ bidding activity in the last couple of weeks has probably not been as great as what it was during the month of January, which is probably very understandable.
We still have a pretty continuous request for bids but it's just not as great at what it was.
I do want to point out that the four additional rigs are definitely going back to work.
Those are contracted rigs.
Not to be picky, but likely to go back to work; those are contracted rigs.
So, we feel comfortable we will go forward.
Yes, this is <UNK>.
Yes, we would definitely prefer that, by all means.
If we couldn't find somebody later on in the year to do a term contract on it, we'd consider going in and completing it.
But we are ---+ right now, we're pretty confident that we'll be able to get that rig contracted and hopefully out running, maybe a year or so.
There are really two things working in favor of doing it this year.
And of course, one of them is higher cash flow.
Commodity prices, we honestly expect it to be higher than what we used in our budget.
We're typically pretty conservative in what we budget going into the year.
And the other, we would have some planned divestitures in some areas that right now is not in that budget number, and if those divestitures should happen, I think that would enable us to put another one or two rigs to work mid-year or so.
We're pretty confident that the trough is going to happen in the first quarter.
A couple of things that really contribute to that is that we have the plant shutdown for five days in our Wilcox area that will reduce our first quarter production by about 0.5 Bcfe.
In addition, another event that happened that I didn't mention in my script was in our Texas Panhandle area in the Granite Wash.
There was a severe ice storm in January that resulted in power outages out there for three to four weeks in many cases.
And that cost us another 0.3 Bcfe.
So, because of those two events, our production in January in the first quarter is going to look low.
And then, because of our drilling program, where we'll have some wells coming online at the end of the first quarter, and in the second quarter, we feel confident that we'll see a pretty good jump in production from first quarter to second quarter.
If we were to pick up a second rig in the Buffalo Wallow, we would continue to see jumps similar to what we'll see in the second quarter, but without that, we're still going to have increases quarter-to-quarter through 2017.
Did that answer your question, <UNK>.
That's a good question.
I think on the pressure pumping side, I think most of the cost increases have already been seen, although it will depend on the rig count and what happens with that.
But because of the increased margins that the pressure pumping guys are seeing, they're starting to bring equipment back into the areas where we operate.
For instance, in the mid-continent out in Oklahoma, we've seen Schlumberger bring two frac crews back into that area, and BJ, who is the fracture company for GE-Baker, they're bringing four frac crews back to that area.
And so, while we've seen this jump, I think there's going to be a limit to it because more equipments going to come back into play.
If we see additional pressure on the total well cost side, it'll likely come from other services other than pumping that you might see start to increase.
The budget that we put together incorporates about a 10% increase in our drilling completion cost.
So, we've tried to already plan that in.
<UNK>, I think, where the debt is today, we're pretty comfortable with that.
I don't know we necessarily would want to see it increasing by any means.
But as far as paying down debt this year, with the opportunities that we have, with the rate of returns that we're seeing in the E&P area and drilling wells, we don't see any reason to reduce debt further than where we are now.
That's within, whatever, $10 million or $15 million one way or the other.
But no more ---+ it's not our plan anyway right now to do any significant reductions or increases into our debt structure.
Thank you, Ellen.
We very much appreciate everyone being on the line.
Next week, I guess we're going to be in Dallas at the EnerCom ---+ the new EnerCom Conference that's now in Dallas instead of San Francisco.
We hope to see many of you there.
If not there, several more conferences are coming up near term and we plan on participating in as many as we can.
Thank you again for listening in.
