Unit Corporation is a diversified oil & gas company based in Tulsa, OK. Founded in 1963, the company was originally a contract driller. Over the years, it expanded into oil & gas exploration and production and mid-stream services (i.e. gathering, processing, treating and sometimes buying and selling natural gas).
Like all U.S. oil & gas companies, Unit Corp. got hit hard in the current downturn that begin in mid-2014. From 2014 to 2016, its revenues fell 61.7% from $1.57 billion to $0.60 billion and its EBITDA fell 70.8% from $762.2 million to $222.3 million. Over that three year period, Unit incurred impairment charges totaling $1.95 billion, including $1.63 billion taken in 2015. It reported net losses of $1.03 billion ($21.12 per share) in 2015 and $136 million ($2.71 per share) in 2016.
Although its corporate credit rating is below investment grade (B2/B+/B+), Unit manages its balance sheet conservatively. It shifted its focus quickly when the downturn began to preserving capital, scaling down its capital spending and cutting operating costs in order to avoid taking on more debt. It did increase debt by $111 million in 2015, but was able to pay all of that back and a little more with debt reduction of $124 million in 2016.
Yet, its balance sheet focus came at a cost: Unit’s proved reserves declined 40% from 179.1 million barrels of oil equivalent (boe) in 2014 to 107.8 million boe in 2016. Although a significant portion of the decline was due to the drop in oil and natural gas prices, the decline would have been less steep had the company maintained a higher level of capital spending. In order to even sustain current production levels going forward, the company will have to grow its reserve base.
Since the price of oil bottomed at $26.05 per barrel in February 2016, Unit’s profitability (as well as the profitability of its peers) has begun to improve. Unit saw lower sales and EBITDA in 2016, but both measures improved sequentially throughout 2016. 2017 first quarter revenues and profits did not improve sequentially, but they were both up sharply over prior year levels. In that quarter, revenues were up 29% to $175.7 million and EBITDA doubled from $34.8 million to $70.7 million.
With the (hopefully sustainable) rebound in commodity prices, Unit has now shifted its emphasis back to growth. Each of its three operating units is on a mission to grow revenues and profits in 2017 and beyond.
Oil and Natural Gas. Unit Corp’s Oil and Natural Gas business has three focus areas: the Hoxbar trend in southwest Oklahoma, the Granite Wash in the Texas panhandle and the Wilcox in east Texas. As the downturn persisted, Unit cut back sharply on drilling. Net wells drilled declined from 121 in 2014 to 35 in 2015 and then to 10 in 2016. After a lag, oil and natural gas production also declined. Production rose 9.8% from 18.3 million boe in 2014 to 20.1 million boe in 2015, but then declined 13.9% to 17.3 million boe in 2016.
Meanwhile, Unit’s average price received per boe (a blend of oil, natural gas and NGL realizations) declined from $39.26 per barrel in 2014 to $21.05 per barrel in 2015 and then to $16.92 per barrel in 2016. This was the primary driver of the decline in the division’s revenues from $740 million in 2014 to $294 million in 2016.
With the sharp drop in revenues, the Oil and Natural Gas’s profitability also fell sharply. Its EBITDA fell from $552 million in 2014 to $174 million in 2016. As noted, impairment charges totaled nearly $2.0 billion over the three year period. Thus, the division posted a $1.63 billion operating loss in 2015 as well as a loss of $101 million in 2016.
During the course of 2016, however, revenues improved steadily. The Oil and Natural Gas division finally posted an operating profit in the fourth quarter and again in the first quarter of 2017. With the improvement in oil, NGL and natural gas prices, the division has reactivated its drilling program. It intends to run three rigs throughout the course of the year. Thus, its total production should improve steadily through the year.
In the 2017 first quarter, total production fell 16.3% vs. the prior year (but revenues were up 50%, due to substantially improved price realizations). Unit Corp. expects that the year-over-year comparisons of production will improve steadily for the balance of the year. For all of 2017, it now expects total production of 16.1-16.7 million boe, which would represent a decline of 3%-7% from 2016.
Despite that decline, I project that revenues for the Oil & Natural Gas division will rise 35% to $396 million in 2017, EBITDA will jump 38% to $240 million and operating income will be $123 million, reversing last year’s loss of $101 million.
The division’s performance in 2017 will get a boost from a strategic acquisition of oil and natural gas assets located in its core Hoxbar region (in Caddo and Grady counties in Oklahoma). The company paid $56.75 million (plus 180 acres located in nearby McLain County) for 3.2 million boe of proved reserves and 47 proved developed producing wells with total estimated annual production of 499,000 boe. Although the seller is undisclosed, Unit has evidently partnered with it for some time in this area. Of the 47 wells acquired, 23 are operated by the seller and 20 by Unit. The 8,335 acres included in acquisition are adjacent to and overlap with Unit’s existing acreage in the area. With them, Unit increases its position in the Hoxbar to 28,000 net acres. The new acreage provides Unit with 65 gross potential horizontal drilling locations, 13 of which are new. The remaining 52 locations were already included in Unit’s project inventory, but the acquisition increases Unit’s working interest in them. The acquisition also enhances Unit’s ability to achieve secondary recovery from the acreage through waterfloods, which it says could add as much as 500,000 barrels of oil per well to the play’s estimated ultimate recoveries.
With the rebound in oil and natural gas prices during 2016 and the recent Hoxbar acquisition, Unit’s Oil and Gas Division is poised for improved performance in 2017. Better performance in 2018 and beyond almost certainly requires further gains in oil and natural gas prices.
Contract Drilling. Unit Corp.’s subsidiary, Unit Drilling Company (UDC), drills onshore oil and natural gas wells in seven states (OK, TX, LA, KS, CO, WY and ND) for its own account and for other companies. The company has a fleet of 94 rigs. Of those, four rigs are equipped with engines with more than 2,000 horsepower (hp), 70 have between 1,000 and 1,700 hp and 20 have 800 hp or less.
The fleet also consists of 29 mechanical rigs, powered by diesel engines, and 65 electrical rigs. Of the 65 electrical rigs, 57 units, I believe, are SCR units, which utilize a silicon-controlled rectifier system to produce direct current (DC) to power the rig. The remaining 8 units utilize alternating current (AC).
In order to complete today’s longer laterals, electrically-powered units and especially AC-powered units are increasingly in demand because, according to one source, they are more energy efficient and they give the operator greater accuracy in drilling, which increases safety and reduces drilling times.
SCR rigs are still in demand, but they are older units and often require upgrading. More than 60% of UDC’s fleet consists of SCRs.
As noted, UDC has eight AC-powered units, which it has branded as “BOSS” drilling rigs. I postulate that a ninth BOSS unit is an SCR rig. UDC also has a tenth BOSS rig under construction. BOSS rigs are optimized for pad drilling (i.e. the drilling of multiple wells on a single pad). They offer a multi-direction walking system that allows the rig to move to a new location on the pad without disassembling it. BOSS rigs also utilize a compact design with fewer parts and subassemblies that facilitates quick assembly and faster moves between locations. BOSS rigs are typically equipped with two 2,200 hp pumps each rated at 1,500 gallons per minute.
UDC’s BOSS rigs have remained fully-contracted throughout the downturn. The tenth rig which will be completed later this year is also under contract. The mechanical and SCR rigs, however, saw utilizations fall to just 4 units (out of 85) in May 2016. At that low point, the company had only 13 rigs operating, which equates to a 14% utilization rate. UDC’s average rig utilization rate declined from 63% in 2014 to 19% in 2016.
The decline in rig utilization from 2014 to 2016 has created significant challenges for UDC and its peers. With the drop in drilling demand, dayrates for the rigs also fell. At the same time, the shift to longer laterals and higher-powered fracking methods hastened the obsolescence of older, lower-powered rigs.
As drilling demand has recovered, utilization rates have improved, but they are still well below historical averages. The same is true for dayrates. In this environment, many contract drillers have faced financial difficulties and some have gone bankrupt, but the industry still remains oversupplied. If rig demand does not continue to improve, there will be increasing pressure for further rationalization of rig capacity.
From 2014 to 2016, UDC’s revenues declined from $477 million to $122 million. Along with the drop in rig utilization, its average dayrate declined from $20,043 to $17,784. Its EBITDA, meanwhile, fell from $202 million to $34 million. In 2014 and 2015, UDC booked impairment charges on contract drilling equipment of $83 million.
Since the May 2016 bottom, UDC has been able to more than double its operating rigs to 29, including the nine BOSS units and 20 SCR units. Of the 20 SCR rigs now operating, 6 required some type of upgrade and 20 were returned to service without any modifications.
In 2017, I am projecting that the average number of drilling rigs in use will increase to 30 from 17.4, but the average dayrate with decline from $17,784 to $16,500. That translates into revenue of $181 million, up 48% from $122 million in 2016 and EBITDA of $56 million, up 65% from $34 million.
Despite the improvement, my projections indicate an average utilization rate of only 32% for 2017. Unless UDC’s utilization rate continues to improve, Unit will eventually have to take an impairment charge against its contract drilling assets, which were carried on the books at $942 million at the end of 2016. Under accounting rules, I believe that Unit has the flexibility to carry those assets for a considerable period of time without taking an impairment charge. However, the longer that rigs remain idle, the more costly it may become to bring them back into service. Although UDC enjoyed a big pickup in operating rigs in the second half of 2016 and first quarter of 2017, the recent decline in the price of oil unless reversed will lead to a slowdown in rigs being placed back into service. Oil and natural gas prices will probably have to continue climbing, even if at a slow pace, in order for rig utilization rates to continue to improve. Without such improvement, it would not surprise me to see Unit incur another impairment charge on its rig fleet eventually, perhaps in late 2017 or 2018, and possibly as high as $200-$300 million.
Mid-Stream. Unit Corp. conducts its mid-stream operations through Superior Pipeline Company, LLC (SPC). Superior offers a full range of gathering, processing and treatment services, mostly under long-term contracts. It operates 25 active systems with 340 million cubic feet per day of processing capacity, 1,465 million of pipeline and three natural gas treatment plants. It serves five separate regions, including Northern Oklahoma and Kansas, the Texas Panhandle, Central & Eastern Oklahoma, East Texas and Appalachia. In 2016, four customers accounted for 71% of revenues. As the downturn has unfolded, Superior had shifted its business mix away from commodity-based contracts and more in favor of fee-based contracts.
Gas gathering volumes increased steadily from 2014 to 2016, but natural gas liquids (NGLs) volume fell sharply over that period and gas processing volumes fell 15% in 2016. The drop in NGL volumes was due primarily to Superior operating for most of 2016 and so far in 2017 in full ethane rejection mode at most of its processing plants due to low prices for natural gas liquids.
Overall, SPC’s revenue fell 48% from $356 million in 2014 to $186 million in 2016, but its EBITDA has remained relatively stable over the period – $49.5 million in 2014 and $48.3 million in 2016 – after a dip in 2015. The company said that both purchase volumes and prices paid for natural gas declined in 2016. The combination of the two is included in operating costs. By implication, therefore, either the company lost less (or it made more) on the natural gas volumes that it purchased and subsequently sold.
As with the Oil and Natural Gas and the Contract Drilling businesses, Unit’s Mid-Stream business has scaled capital spending back sharply over the past couple of years. Capital expenditures declined from $79.3 million in 2014 to $16.8 million in 2016 and are projected by the company to be $13 million in 2017. This is a business, however, that requires continual investment as natural gas production from mature fields declines and new infrastructure is required to gain gathering and processing volumes from new fields. Thus, I would be surprised if SPC can keep its capital spending at very low levels for very long.
Based upon my admittedly brief analysis of the business, I wonder whether the company and its shareholders would be better served if Unit were to scale back its Mid-Stream operations by selling those parts of it that do not serve its core operating areas in Oklahoma and Texas (or perhaps even by selling SPC outright). Its Appalachian region being so far detached from its core operating areas seems to me like a good candidate for sale, the proceeds from which could be used to pay down debt. Yet, I also recognize that the management says that the Appalachian region, and specifically its Pittsburgh Mills gathering system, is among the division’s best performers. Nevertheless, good growth prospects should allow Unit to obtain a better price for the sale of the Appalachian region.
Financial Condition. With its focus on operating within the limits of its operating cash flow and maintaining a solid balance sheet, Unit was able to pare back its debt by $124 million in 2016 and reduce its debt-to-capitalization ratio by a point from 41.2% to 40.1%. Based upon its expectations for improved performance in 2017, the company raised its capital spending budget to $227 million from $186 million in 2016.
Without a cut in its 2017 capital budget, the $57 million Hoxbar acquisition would have required additional borrowing; so Unit has entered into an arrangement with Raymond James to raise up to $100 million in equity capital over time through periodic share issuances. Through April 21, 2017, Unit had sold 770,660 shares for net proceeds of $18.3 million.
At March 31, 2017, Unit had $800 million of debt outstanding, including $150 million under its bank credit agreement and $650 million of 6.625% Senior Subordinated Notes due May 15, 2021. The committed amount of the bank credit agreement is $475 million and the borrowing base is currently $475 million. My quick covenant analysis suggests that the company should have had nearly the full net amount of $325 million available for borrowing as of March 31.
The bank credit agreement matures on April 10, 2020, a little more than one year before the Senior Subordinated Notes. The banks will undoubtedly want the Notes refinanced (i.e. the maturity extended by at least five years to 2026) before they agree to extend the maturity date in a new credit agreement. That suggests that Unit will have to issue new unsecured notes to refinance the 6 5/8s in 2019 at the latest.
The Senior Subordinated Notes are rated B3/B+/BB-. They most recently traded at 98.25 to yield 7.15%, which represents a spread of 552 basis points over the comparable maturity Treasury. The average high yield energy bond is currently trading at a 459 bp spread over Treasurys (with a one year greater effective duration), according to Bank of America. The Unit Notes are callable currently at 102.2, dropping to 101.1 on May 15, 2018 and then to 100 on May 15, 2019. Based upon the current pricing, the market is assuming that the bonds will not be called before maturity, which is unlikely assuming no further deterioration in the company’s financial condition.
Projections. Using some of my own assumptions along with management’s guidance on certain metrics, I project that Unit Corp. will generate $755 million of revenues and earnings of $0.75 per share in 2017. My projections assume no impairment charges. Consensus estimates anticipate earnings of $0.93 per share. Without getting into all the details, I believe that my revenue assumptions are quite reasonable (up 27% over 2016). I also project that total company EBITDA will increase 39% from $222 million to $308 million.
My projections further assume that the company will be able to generate sufficient cash (together with nearly $40 million net raised from the issuance of common stock) to reduce debt by another $8 million (bringing total debt reduction to $20 million for the year).
Consensus estimates anticipate that earnings will jump again to $1.76 in 2018. Such projections must implicitly assume higher production levels and higher price realizations for oil, NGL and natural gas, as well as another big increase in utilization for Unit’s contract drilling rigs.
Valuation. Valuing Unit and its peer group (which includes both E&P and oilfield services companies) is difficult at this time. About half of Units peers are projected to post losses in 2017 and a third are projected to post losses again in 2018. Compared with those that are expected to post profits, Unit’s forward P/E multiple (using consensus estimates) of roughly 20 times projected 2017 earnings is in in line with peers for 2017; but its forward multiple of 10 times projected 2018 earnings is substantially below the peer group average of 16 for 2018. The lower 2018 forward multiple suggests that investors are somewhat skeptical about Unit’s ability to achieve the 2018 consensus estimate. Thus, its stock has greater upside potential, if it can hit that 2018 earnings target and thus can deliver a superior investment return, assuming that the industry rebound continues.
On a price-to-book value basis, Unit’s common stock is valued at 0.8 times book, while the peer average is 1.6 times. The discount may reflect concerns about the potential for further impairment charges, especially in contract drilling, and also doubts about whether the company can meet 2018 consensus earnings projections.
From a technical perspective, Unit’s stock, like virtually all energy stocks, has been in a clear downtrend since the beginning of the year and there are only tentative signs that a bottom may be at hand.
On balance, while there are risks across all of its businesses (and especially in contract drilling), Unit Corp. has been able to focus on its core competencies and adjust its operations and cost structure appropriately to match tough current market conditions. It has also maintained a fairly solid balance sheet and preserved its access to bank and equity financing. Accordingly, I believe that Unit’s common stock offers good upside potential with moderate downside risk (compared with peers). My price target of $28 per share reflects a forward P/E multiple for 2018 that is consistent with peers. Similarly, the 6 5/8% Senior Subordinated Notes offer an attractive yield and superior potential risk-adjusted returns over the next two years, assuming that the Notes are called in 2019 or earlier.
June 1, 2017
Stephen P. Percoco
Lark Research, Inc.
839 Dewitt Street
Linden, New Jersey 07036
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