| News | UNIT CORPORATION |
| 8200 South Unit Drive, Tulsa, Oklahoma, 74132 | |
| Telephone 918 493-7700, Fax 918 493-7714 | |
| Contact: | Michael D. Earl |
| Vice President, Investor Relations | |
| (918) 493-7700 | |
| www.unitcorp.com | |
For Immediate Release…
February 23, 2017
UNIT CORPORATION REPORTS 2016 FOURTH QUARTER & YEAR END RESULTS
Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported its financial and operational results for the fourth quarter and year end 2016. Fourth quarter and recent highlights include:
| • | Net income of $1.7 million for the quarter. |
| • | To date, the contract drilling segment increased the number of drilling rigs in service from a low of 13 in the second quarter to 26, a 100% increase. |
| • | Contract drilling segment placed into service its ninth BOSS drilling rig. |
| • | Oil and natural gas segment resumed drilling activities in the fourth quarter with a drilling rig being placed into service in October in the Southern Oklahoma Hoxbar Oil Trend (SOHOT) play and a second drilling rig placed into service in December in the Granite Wash play. |
| • | Midstream segment started preliminary construction activities to connect the next well pad to its Pittsburgh Mills gathering system. |
| • | Reduced long-term debt by $53.7 million from the end of the third quarter, bringing the total 2016 reduction to $118.1 million. |
FOURTH QUARTER AND YEAR END 2016 FINANCIAL RESULTS
Unit recorded net income of $1.7 million for the quarter, or $0.03 per diluted share, compared to a net loss of $309.3 million, or $6.29 per share, for the fourth quarter of 2015. During the fourth quarter of 2015, Unit incurred a pre-tax non-cash ceiling test write-down of $458.3 million in the carrying value of its oil and natural gas properties and $27.0 million in the carrying value of three of its gas gathering systems. Those non-cash ceiling test write-downs resulted from lower commodity prices. Adjusted net income for the fourth quarter of 2016 (which excludes the effect of non-cash commodity derivatives) was $12.2 million, or $0.23 per diluted share (see Non-GAAP financial measures below). Total revenues for the quarter were $174.3 million (51% oil and natural gas, 19% contract drilling, and 30% midstream), compared to $172.3 million (44% oil and natural gas, 29% contract drilling, and 27% midstream) for the fourth quarter of 2015. Adjusted EBITDA for the quarter was $80.7 million, or $1.58 per diluted share (see Non-GAAP financial measures below).
For 2016, Unit recorded a net loss of $135.6 million, or $2.71 per share, compared to a net loss of $1.0 billion, or $21.12 per share, for 2015. For the full year, Unit incurred pre-tax non-cash ceiling test write-downs of $161.6 million in the carrying value of its oil and natural gas properties, compared to Unit’s 2015 pre-tax non-cash ceiling test write-downs of $1.6 billion in the carrying value of its oil and natural gas properties, $8.3 million in the carrying value of certain drilling rigs and other assets removed from service, and $27.0 million for the gas gathering systems discussed above. Unit recorded an adjusted net loss (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash write-downs) of $13.8 million, or $0.28 per share, for 2016 (see Non-GAAP financial measures below). Total revenues for the year were $602.2 million (49% oil and natural gas, 20% contract drilling, and 31% midstream), compared to $854.2 million (45% oil and natural
gas, 31% contract drilling, and 24% midstream) for 2015. Adjusted EBITDA for 2016 was $251.6 million, or $4.98 per diluted share (see Non-GAAP financial measures below).
OIL AND NATURAL GAS SEGMENT INFORMATION
Total production for 2016 was 17.3 million barrels of oil equivalent (MMBoe), a 14% decrease from 2015. For the quarter, total equivalent production was 4.2 MMBoe, a decrease of 12% from the fourth quarter of 2015 and essentially unchanged from the third quarter of 2016. Liquids (oil and NGLs) production represented 47% of total equivalent production for the quarter. Oil production for the quarter was 7,762 barrels per day, a decrease of 9% from the fourth quarter of 2015 and an increase of 2% over the third quarter of 2016. NGLs production for the quarter was 13,790 barrels per day, a decrease of 4% from the fourth quarter of 2015 and a 1% increase over the third quarter of 2016. Natural gas production for the quarter was 145,202 thousand cubic feet (Mcf) per day, a decrease of 16% from the fourth quarter of 2015 and essentially unchanged from the third quarter of 2016.
Unit’s average realized per barrel equivalent price for the quarter was $19.73, an increase of 6% over the fourth quarter of 2015 and an 8% increase over the third quarter of 2016. Unit’s average natural gas price for the quarter was $2.37 per Mcf, an increase of 6% over the fourth quarter of 2015 and an increase of 3% over the third quarter of 2016. Unit’s average oil price for the quarter was $46.14 per barrel, a decrease of 4% from the fourth quarter of 2015 and an increase of 8% over the third quarter of 2016. Unit’s average NGLs price for the quarter was $14.57 per barrel, a 32% increase over the fourth quarter of 2015 and an increase of 15% over the third quarter of 2016. All prices in this paragraph include the effects of derivative contracts.
During the quarter, Unit continued its Wilcox recompletion and workover program. There were 10 new behind pipe re-completions during the quarter, which increased combined production on those wells by 9.8 MMcf per day and 300 barrels of oil per day at a total capital cost of $3.0 million. During 2016, total production from the Wilcox play increased 22% over 2015. Unit’s plan for 2017 is for 10 - 15 Wilcox re-completions and seven new wells (4 vertical and 3 horizontal).
In the SOHOT area, Unit resumed its drilling program in October drilling and completing two Marchand horizontal wells. Production is being monitored for a few months with plans to begin drilling additional wells in the second quarter. Unit is planning a seven well program for the balance of 2017.
Unit resumed drilling in the Granite Wash play in December drilling an extended length lateral in the A2 interval of Buffalo Wallow that is anticipated to be completed in late February. The Dixon 5554 XL #1H, which was completed in the C1 interval, continues to perform at a rate over 50% better than its type curve forecast. Unit’s plan is to continuously operate at least one drilling rig in the Granite Wash during 2017, which is planned to result in nine new extended length lateral wells.
In all three core areas, Unit continues to look for opportunities to add additional leasehold. Historically, Unit has generally succeeded in replacing acreage developed in any year with additional new locations.
Larry Pinkston, Unit’s Chief Executive Officer and President, said: “During 2016, we saw the continued strong performance of our Wilcox behind pipe recompletion and workover program. Wilcox production grew during 2016, helping to partially offset our corporate decline during the suspension of our drilling activities. All three of our core areas have provided rates of return that compete very favorably with other active basins."
2
The following table illustrates this segment’s comparative production, realized prices, and operating profit for the periods indicated:
| Three Months Ended | Three Months Ended | Twelve Months Ended | |||||||||||||||||||||
| Dec 31, 2016 | Dec 31, 2015 | Change | Dec 31, 2016 | Sept 30, 2016 | Change | Dec 31, 2016 | Dec 31, 2015 | Change | |||||||||||||||
| Oil and NGLs Production, MBbl | 1,983 | 2,108 | (6)% | 1,983 | 1,961 | 1% | 7,988 | 9,057 | (12)% | ||||||||||||||
| Natural Gas Production, Bcf | 13.4 | 15.9 | (16)% | 13.4 | 13.4 | —% | 55.7 | 65.5 | (15)% | ||||||||||||||
| Production, MBoe | 4,209 | 4,757 | (12)% | 4,209 | 4,194 | —% | 17,277 | 19,982 | (14)% | ||||||||||||||
| Production, MBoe/day | 45.8 | 51.7 | (12)% | 45.8 | 45.6 | —% | 47.2 | 54.7 | (14)% | ||||||||||||||
Avg. Realized Natural Gas Price, Mcf (1) | $ | 2.37 | $ | 2.24 | 6% | $ | 2.37 | $ | 2.29 | 3% | $ | 2.07 | $ | 2.63 | (21)% | ||||||||
Avg. Realized NGL Price, Bbl (1) | $ | 14.57 | $ | 11.05 | 32% | $ | 14.57 | $ | 12.68 | 15% | $ | 11.26 | $ | 10.12 | 11% | ||||||||
Avg. Realized Oil Price, Bbl (1) | $ | 46.14 | $ | 48.23 | (4)% | $ | 46.14 | $ | 42.79 | 8% | $ | 40.5 | $ | 50.79 | (20)% | ||||||||
Realized Price / Boe (1) | $ | 19.73 | $ | 18.54 | 6% | $ | 19.73 | $ | 18.29 | 8% | $ | 16.92 | $ | 20.92 | (19)% | ||||||||
Operating Profit Before Depreciation, Depletion, Amortization & Impairment (MM) (2) | $ | 60.4 | $ | 39.7 | 52% | $ | 60.4 | $ | 52.8 | 14% | $ | 174.0 | $ | 219.7 | (21)% | ||||||||
| (1) | Realized price includes oil, NGLs, natural gas, and associated derivatives. |
| (2) | Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment. (See non-GAAP financial measures below.) |
The following table summarizes this segment’s outstanding derivative contracts.
| Crude | ||||||
| Period | Structure | Volume Bbl/Day | Weighted Average Fixed Price | Weighted Average Floor Price | Weighted Average Subfloor Price | Weighted Average Ceiling Price |
| Jan'17 - Dec'17 | 3-Way Collar | 3,750 | $49.79 | $39.58 | $60.98 | |
| Natural Gas | ||||||
| Period | Structure | Volume MMBtu/Day | Weighted Average Fixed Price | Weighted Average Floor Price | Weighted Average Subfloor Price | Weighted Average Ceiling Price |
| Jan'17 - Mar'17 | Swap | 70,000 | $3.044 | |||
| Apr'17 - Oct'17 | Swap | 10,000 | $3.505 | |||
| Apr'17 - Dec'17 | Swap | 60,000 | $2.960 | |||
| Jan'18 - Dec'18 | Swap | 10,000 | $3.025 | |||
| Jan'17 - Dec'17 | Basis Swap (1) | 20,000 | $(0.215) | |||
| Jan'18 - Dec'18 | Basis Swap (1) | 10,000 | $(0.208) | |||
| Jan'17 - Oct'17 | Collar | 20,000 | $2.88 | $3.10 | ||
| Jan'17 - Dec'17 | 3-Way Collar | 15,000 | $2.50 | $2.00 | $3.32 | |
| Nov'17 - Dec'17 | 3-Way Collar | 10,000 | $3.50 | $2.75 | $4.00 | |
| Jan'18 - Mar'18 | 3-Way Collar | 50,000 | $3.35 | $2.65 | $4.22 | |
| Apr'18 - Dec'18 | 3-Way Collar | 10,000 | $3.00 | $2.50 | $3.66 | |
(1) After December 31, 2016, the basis swaps for February through October 2017 and April through October 2018 were liquidated for $0.6 million and $0.5 million, respectively.
YEAR END 2016 ESTIMATED PROVED RESERVES
The discount rate (PV-10) value of Unit’s estimated year-end 2016 proved reserves decreased 17% from 2015 to $575.2 million. Estimated year-end 2016 proved oil and natural gas reserves were 117.8 MMBoe, or 706.6 billion cubic feet of natural gas equivalents (Bcfe), as compared with 135.2 MMBoe, or 811.4 Bcfe, at year-end 2015, a 13% decrease. Estimated reserves were 13% oil, 29% NGLs, and 58% natural gas.
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The following details the changes to Unit’s proved oil, NGLs, and natural gas reserves during 2016:
Oil (MMbls) | NGLs (MMbls) | Natural Gas (Bcf) | Proved Reserves (MMBoe) | ||||||
| Proved Reserves, at December 31, 2015 | 16.7 | 37.7 | 484.9 | 135.2 | |||||
| Revisions of previous estimates | (0.5 | ) | (2.5 | ) | (31.7 | ) | (8.3 | ) | |
Extensions, discoveries, and other additions | 2.5 | 4.3 | 38.4 | 13.2 | |||||
| Purchases of minerals in place | 0.1 | — | 0.6 | 0.3 | |||||
| Production | (3.0 | ) | (5.0 | ) | (55.7 | ) | (17.3 | ) | |
| Sales | (0.1 | ) | — | (30.9 | ) | (5.3 | ) | ||
| Proved Reserves, at December 31, 2016 | 15.7 | 34.5 | 405.6 | 117.8 | |||||
Estimated 2016 year-end proved reserves included proved developed reserves of 99.1 MMBoe, or 594.4 Bcfe, (13% oil, 29% NGLs, and 58% natural gas) and proved undeveloped reserves of 18.7 MMBoe, or 112.2 Bcfe, (16% oil, 32% NGLs, and 52% natural gas). Overall, 84% of the estimated proved reserves are proved developed.
The present value of the estimated future net cash flows from the 2016 estimated proved reserves (before income taxes and using a PV-10), is approximately $575.2 million. The present value was determined using the required SEC's pricing methodology. The aggregate price used for all future reserves was $42.75 per barrel of oil, $19.74 per barrel of NGLs, and $2.48 per Mcf of natural gas (then adjusted for price differentials). Unit’s 2016 year-end proved reserves were independently audited by Ryder Scott Company, L.P. Their audit covered properties which accounted for 83% of the discounted future net cash flow (PV-10). See below for the reconciliation of PV-10 to the standardized measure of discounted future net cash flows as defined by GAAP.
Pinkston said: "The suspension of drilling activities at the end of the first quarter 2016, lower commodity prices, and divestitures during the year resulted in the reduction of 2016's total proved reserves as compared to 2015. Lower pricing requirements caused the revisions to our reserves. Our non-core asset divestitures also reduced our reserves by approximately 5.3 MMBoe. Our proved undeveloped reserves were 16% of total proved reserves at the end of 2016."
CONTRACT DRILLING SEGMENT INFORMATION
The average number of Unit's drilling rigs working during the quarter was 19.5, a decrease of 28% from the fourth quarter of 2015 and an increase of 22% over the third quarter of 2016. Per day drilling rig rates for the quarter averaged $16,866, a decrease of 9% from the fourth quarter of 2015 and a 4% decrease from the third quarter of 2016. For 2016, per day drilling rig rates averaged $17,784, a 9% decrease from 2015. Average per day operating margin for the quarter was $6,478 (with no elimination of intercompany drilling rig profit and bad debt expense). This compares to fourth quarter 2015 average operating margin of $7,258 (before elimination of intercompany drilling rig profit and bad debt expense of $0.3 million), a decrease of 11%, or $780. Fourth quarter 2016 average per day operating margin increased 42%, or $1,932, as compared to $4,546 for the third quarter of 2016 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP financial measures below). Average operating margins for the fourth quarter of 2016 did not include early termination fees from the cancellation of long-term contracts, compared to early termination fees of $3.3 million, or $1,327 per day, during the fourth quarter of 2015. There were no early termination fees for the third quarter of 2016.
Pinkston said: “Construction for our ninth BOSS drilling rig was completed, and currently all nine of our BOSS drilling rigs are operating under contract. Commodity prices continued to increase during the quarter, and the uptick in operator inquiries has led to more contracts for our drilling rigs. Our fleet totals 94 drilling rigs, of which 26 are working under contract after rebounding from a low of 13 drilling rigs during the second quarter of 2016. We also have contracts for four additional drilling rigs to return to service during the first quarter of 2017. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 10 of our drilling rigs. Of the 10, eight are up for renewal during 2017 and two in 2018.”
4
The following table illustrates certain comparative results from this segment’s operations for the periods indicated:
| Three Months Ended | Three Months Ended | Twelve Months Ended | |||||||||||||||||||||
| Dec 31, 2016 | Dec 31, 2015 | Change | Dec 31, 2016 | Sept 30, 2016 | Change | Dec 31, 2016 | Dec 31, 2015 | Change | |||||||||||||||
| Rigs Utilized | 19.5 | 27.2 | (28)% | 19.5 | 16.0 | 22% | 17.4 | 34.7 | (50)% | ||||||||||||||
Operating Profit Before Depreciation & Impairment (MM) (1) | $ | 11.6 | $ | 17.9 | (35)% | $ | 11.6 | $ | 6.7 | 74% | $ | 33.9 | $ | 109.3 | (69)% | ||||||||
| (1) | Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and impairment. (See non-GAAP financial measures below.) |
MIDSTREAM SEGMENT INFORMATION
For the quarter, per day gas gathered volumes increased 18%, while gas processed and liquids sold volumes decreased 17% and 5%, respectively, as compared to the fourth quarter of 2015. Compared to the third quarter of 2016, gas gathered, gas processed, and liquids sold volumes per day decreased 1%, 8% and 4%, respectively. Operating profit (as defined in the footnote below) for the quarter was $14.7 million, an increase of 55% over the fourth quarter of 2015 and an increase of 13% over the third quarter of 2016.
For 2016, per day gas gathered volumes increased 18%, while gas processed and liquids sold volumes per day decreased 15% and 7%, respectively, as compared to 2015. Operating profit (as defined in the footnote below) for 2016 was $48.3 million, an increase of 17% over 2015.
The following table illustrates certain comparative results from this segment’s operations for the periods indicated:
| Three Months Ended | Three Months Ended | Twelve Months Ended | |||||||||||||||||||||
| Dec 31, 2016 | Dec 31, 2015 | Change | Dec 31, 2016 | Sept 30, 2016 | Change | Dec 31, 2016 | Dec 31, 2015 | Change | |||||||||||||||
| Gas Gathering, Mcf/day | 423,669 | 360,159 | 18% | 423,669 | 429,693 | (1)% | 419,217 | 353,771 | 18% | ||||||||||||||
| Gas Processing, Mcf/day | 140,719 | 170,087 | (17)% | 140,719 | 152,651 | (8)% | 155,461 | 182,684 | (15)% | ||||||||||||||
| Liquids Sold, Gallons/day | 535,253 | 561,941 | (5)% | 535,253 | 558,843 | (4)% | 536,494 | 577,513 | (7)% | ||||||||||||||
Operating Profit Before Depreciation, Amortization & Impairment (MM) (1) | $ | 14.7 | $ | 9.4 | 55% | $ | 14.7 | $ | 13.0 | 13% | $ | 48.3 | $ | 41.2 | 17% | ||||||||
| (1) | Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment. (See non-GAAP financial measures below.) |
Pinkston said: “Our midstream segment saw throughput volumes continue to grow at both our Pittsburgh Mills and Segno (Wilcox) gathering systems which partially offset declines on other gathering systems resulting from reduced well drilling activity levels. Due to low liquids prices, our midstream segment processing facilities in the Mid-Continent area largely operated in ethane rejection mode during the quarter. Midstream operating profit remained strong in 2016.”
2017 CAPITAL BUDGET & PRODUCTION GUIDANCE
Pinkston said: "The commodity price outlook appears to show signs of improvement. While our balance sheet has improved over last year, we continue to be cautious in developing our capital expenditures plan for 2017. It is our intention to match expected anticipated cash flow with our capital expenditures for the year."
During 2017, Unit's capital expenditures budget is anticipated to be $227 million, which represents a 32% increase over 2016. The capital expenditures plan by segment is: $188 million for the oil and natural gas segment, $24 million for the contract drilling segment, and $13 million for the midstream segment, representing an increase of 57%, 25%, and a decrease of 23%, respectively, from 2016. The budget includes no costs for potential acquisitions and is based on realized prices for the year averaging $53.37 per barrel for oil, $21.35 per barrel for natural gas liquids, and $3.00 per Mcf of natural gas (all prices are before differentials and hedges are applied). As always, Unit's capital budget is subject to periodic review based on prevailing conditions.
5
With the curtailment of drilling activity during 2016, production declined and ended the year down 13.5% year over year, at the low end of guidance. 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 begin growing sequentially in subsequent quarters. Unit's 2017 production is expected to decline 5% to 8% year over year from 2016.
FINANCIAL INFORMATION
Unit ended the quarter with long-term debt of $800.9 million (a reduction of $53.7 million from the end of the third quarter and $118.1 million from the end of 2015). Long-term debt is comprised of $640.1 million of senior subordinated notes (net of unamortized discount and debt issuance costs) and $160.8 million of bank credit facility borrowings. During October, Unit's borrowing base was redetermined with no change to availability. Under the credit agreement, the amount Unit can borrow is the lesser of the amount it elects as the commitment amount ($475 million) or the value of its borrowing base as determined by the lenders ($475 million), but in either event not to exceed $875 million.
RETIREMENT OF EXECUTIVE OFFICER
On February 21, 2017, Mr. Brad Guidry, Executive Vice President - Exploration & Production, of the company’s wholly owned subsidiary Unit Petroleum Company, announced his intention to retire effective March 31, 2017. Mr. Frank Young, Unit Petroleum’s current Senior Vice President - Exploration & Production, is expected to replace Mr. Guidry on the effective date of his retirement. Mr. Young joined Unit Petroleum in June 2007 as Vice President over the Central Division. Since 2012, Mr. Young has served as the Senior Vice President, Operations for Unit Petroleum. Before joining Unit Petroleum, Mr. Young worked for Anadarko Petroleum for 16 years where he served in various operating and leadership capacities. Mr. Young holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University and a Master of Business Administration degree from Texas A&M University.
Pinkston said: "Brad has been a tremendous asset for the almost 30 years he has been with us. His knowledge and leadership skills allowed him to move quickly from a staff geologist to manager and finally to executive vice president. He has had an incredible career here, and we will greatly miss him. We believe that Mr. Young is a highly qualified replacement for Mr. Guidry, and we look forward to his leadership for our oil and natural gas segment."
MANAGEMENT COMMENTS
Pinkston said: "We are pleased with our fourth quarter improved results. We entered 2016 with an uncertain outlook for the direction of commodity prices. As a result, we implemented a strategy of closely managing costs and being careful with our balance sheet. We believe recent modest commodity price improvements and the resulting positive impact on industry sentiment has positioned our company for an improved 2017. Our oil and natural gas segment is excited about having restarted its drilling program after a period of inactivity. Our intention is to increase our capital allocation to this segment and return to sequential production growth, although it will take time to overcome the results of that inactivity. Our Granite Wash drilling activities will not only benefit our production profile but will also benefit our midstream throughput volumes at our Buffalo Wallow facility. Our contract drilling segment had seen a dramatic improvement in utilization from a low of 13 drilling rigs operating in the second quarter to current levels. We are pleased with the pace of getting drilling rigs redeployed. Surprisingly, we have seen spotty opportunities to increase dayrates very modestly. Finally, the increased activity levels around our Buffalo Wallow, Segno and Pittsburgh Mills midstream facilities bode well for that segment's ability to increase its gathering volumes in 2017. Additionally, continued NGL price improvement should position the midstream segment to increase its cash flow with minimal incremental capital cost."
WEBCAST
Unit will webcast its fourth quarter earnings conference call live over the Internet on February 23, 2017 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm at least fifteen minutes prior to the start of the call to download and install any necessary audio software. For those who are not available to listen to the live webcast, a replay will be available shortly after the call and will remain on the site for 90 days.
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_____________________________________________________
Unit Corporation is a Tulsa-based, publicly held energy company engaged through its subsidiaries in oil and gas exploration, production, contract drilling, and gas gathering and processing. Unit’s Common Stock is on the New York Stock Exchange under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.
FORWARD-LOOKING STATEMENT
This news release contains forward-looking statements within the meaning of the private Securities Litigation Reform Act. All statements, other than statements of historical facts, included in this release that address activities, events, or developments that the company expects, believes, or anticipates will or may occur in the future are forward-looking statements. Several risks and uncertainties could cause actual results to differ materially from these statements, including changes in commodity prices, the productive capabilities of the company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected rate of the company’s oil and natural gas production, the amount available to the company for borrowings, its anticipated borrowing needs under its credit agreement, the number of wells to be drilled by the company’s oil and natural gas segment, and other factors described from time to time in the company’s publicly available SEC reports. The company assumes no obligation to update publicly such forward-looking statements, whether because of new information, future events, or otherwise.
7
Unit Corporation
Selected Financial Highlights
(In thousands except per share amounts)
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Statement of Operations: | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Oil and natural gas | $ | 87,903 | $ | 75,830 | $ | 294,221 | $ | 385,774 | ||||||||
| Contract drilling | 33,300 | 50,554 | 122,086 | 265,668 | ||||||||||||
| Gas gathering and processing | 53,077 | 45,908 | 185,870 | 202,789 | ||||||||||||
| Total revenues | 174,280 | 172,292 | 602,177 | 854,231 | ||||||||||||
| Expenses: | ||||||||||||||||
| Operating costs: | ||||||||||||||||
| Oil and natural gas | 27,493 | 36,175 | 120,184 | 166,046 | ||||||||||||
| Contract drilling | 21,665 | 32,691 | 88,154 | 156,408 | ||||||||||||
| Gas gathering and processing | 38,424 | 36,475 | 137,609 | 161,556 | ||||||||||||
| Total operating costs | 87,582 | 105,341 | 345,947 | 484,010 | ||||||||||||
| Depreciation, depletion, and amortization | 48,925 | 74,567 | 208,353 | 352,742 | ||||||||||||
| Impairments | — | 485,261 | 161,563 | 1,634,628 | ||||||||||||
| General and administrative | 8,517 | 8,467 | 33,337 | 34,358 | ||||||||||||
| (Gain) loss on disposition of assets | (1,717 | ) | 959 | (2,540 | ) | 7,229 | ||||||||||
| Total expenses | 143,307 | 674,595 | 746,660 | 2,512,967 | ||||||||||||
| Income (loss) from operations | 30,973 | (502,303 | ) | (144,483 | ) | (1,658,736 | ) | |||||||||
| Other income (expense): | ||||||||||||||||
| Interest, net | (9,604 | ) | (8,481 | ) | (39,829 | ) | (31,963 | ) | ||||||||
| Gain (loss) on derivatives not designated as hedges | (18,039 | ) | 13,428 | (22,813 | ) | 26,345 | ||||||||||
| Other | 318 | 7 | 307 | 45 | ||||||||||||
| Total other income (expense) | (27,325 | ) | 4,954 | (62,335 | ) | (5,573 | ) | |||||||||
| Income (loss) before income taxes | 3,648 | (497,349 | ) | (206,818 | ) | (1,664,309 | ) | |||||||||
| Income tax expense (benefit): | ||||||||||||||||
| Current | 15 | (18,900 | ) | 15 | (20,616 | ) | ||||||||||
| Deferred | 1,950 | (169,112 | ) | (71,209 | ) | (606,332 | ) | |||||||||
| Total income taxes | 1,965 | (188,012 | ) | (71,194 | ) | (626,948 | ) | |||||||||
| Net income (loss) | $ | 1,683 | $ | (309,337 | ) | $ | (135,624 | ) | $ | (1,037,361 | ) | |||||
| Net income (loss) per common share: | ||||||||||||||||
| Basic | $ | 0.03 | $ | (6.29 | ) | $ | (2.71 | ) | $ | (21.12 | ) | |||||
| Diluted | $ | 0.03 | $ | (6.29 | ) | $ | (2.71 | ) | $ | (21.12 | ) | |||||
| Weighted average shares outstanding: | ||||||||||||||||
| Basic | 50,081 | 49,157 | 50,029 | 49,110 | ||||||||||||
| Diluted | 50,949 | 49,157 | 50,029 | 49,110 | ||||||||||||
8
| December 31, | December 31, | ||||||
| 2016 | 2015 | ||||||
Balance Sheet Data: | |||||||
| Current assets | $ | 121,196 | $ | 140,258 | |||
| Total assets | $ | 2,479,303 | $ | 2,799,842 | |||
| Current liabilities | $ | 164,915 | $ | 150,891 | |||
| Long-term debt | $ | 800,917 | $ | 918,995 | |||
| Other long-term liabilities | $ | 103,479 | $ | 140,626 | |||
| Deferred income taxes | $ | 215,922 | $ | 275,750 | |||
| Shareholders’ equity | $ | 1,194,070 | $ | 1,313,580 | |||
| Twelve Months Ended December 31, | |||||||
| 2016 | 2015 | ||||||
| Statement of Cash Flows Data: | |||||||
| Cash flow from operations before changes in operating assets and liabilities | $ | 205,888 | $ | 397,859 | |||
| Net change in operating assets and liabilities | 34,242 | 49,085 | |||||
| Net cash provided by operating activities | $ | 240,130 | $ | 446,944 | |||
| Net cash used in investing activities | $ | (110,971 | ) | $ | (549,778 | ) | |
| Net cash provided by (used in) financing activities | $ | (129,101 | ) | $ | 102,620 | ||
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Non-GAAP Financial Measures
Unit Corporation reports its financial results in accordance with generally accepted accounting principles (“GAAP”). The Company believes certain non-GAAP performance measures provide users of its financial information and its management additional meaningful information to evaluate the performance of the company.
This press release includes net income (loss) and earnings (loss) per share excluding impairment adjustments and the effect of the cash settled commodity derivatives, its exploration and production segment’s reconciliation of PV-10 to standard measure, its reconciliation of segment operating profit, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, its cash flow from operations before changes in operating assets and liabilities, and its reconciliation of net income (loss) to adjusted EBITDA.
Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2016 and 2015. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP. This non-GAAP information should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. The non-GAAP financial information presented may be determined or calculated differently by other companies and may not be comparable to similarly titled measures.
Unit Corporation
Reconciliation of Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) per Share
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| (In thousands except earnings per share) | ||||||||||||||||
| Adjusted net income: | ||||||||||||||||
| Net income (loss) | $ | 1,683 | $ | (309,337 | ) | $ | (135,624 | ) | $ | (1,037,361 | ) | |||||
| Impairment adjustment (net of income tax) | — | 302,075 | 100,573 | 1,017,556 | ||||||||||||
| (Gain) loss on derivatives (net of income tax) | 11,845 | (8,363 | ) | 14,960 | (16,421 | ) | ||||||||||
| Settlements during the period of matured derivative contracts (net of income tax) | (1,322 | ) | 8,995 | 6,333 | 29,055 | |||||||||||
| Adjusted net income (loss) | $ | 12,206 | $ | (6,630 | ) | $ | (13,758 | ) | $ | (7,171 | ) | |||||
| Adjusted diluted earnings per share: | ||||||||||||||||
| Diluted earnings (loss) per share | $ | 0.03 | $ | (6.29 | ) | $ | (2.71 | ) | $ | (21.12 | ) | |||||
| Diluted earnings per share from the impairments | — | 6.15 | 2.01 | 20.72 | ||||||||||||
| Diluted earnings per share from the (gain) loss on derivatives | 0.23 | (0.18 | ) | 0.30 | (0.34 | ) | ||||||||||
| Diluted earnings (loss) per share from the settlements of matured derivative contracts | (0.03 | ) | 0.18 | 0.12 | 0.59 | |||||||||||
| Adjusted diluted earnings (loss) per share | $ | 0.23 | $ | (0.14 | ) | $ | (0.28 | ) | $ | (0.15 | ) | |||||
________________
The Company has included the net income and diluted earnings per share including only the cash settled commodity derivatives because:
| • | It uses the adjusted net income to evaluate the operational performance of the company. |
| • | The adjusted net income is more comparable to earnings estimates provided by securities analysts. |
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Unaudited Reconciliation of PV-10 to Standard Measure
December 31, 2016
PV-10 is the estimated future net cash flows from proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes. Standardized Measure is the after-tax estimated future cash flows from proved reserves discounted at an annual rate of 10 percent, determined in accordance with GAAP. The company uses PV-10 as one measure of the value of its proved reserves and to compare relative values of proved reserves among exploration and production companies without regard to income taxes. The company believes that securities analysts and rating agencies use PV-10 in similar ways. The company’s management believes PV-10 is a useful measure for comparison of proved reserve values among companies because, unlike Standardized Measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves. Below is a reconciliation of PV-10 to Standardized Measure:
| 2016 | |||||
| (In millions) | |||||
| PV-10 at December 31, 2016 | $ | 575.2 | |||
| Discounted effect of income taxes | (57.0 | ) | |||
| Standardized Measure at December 31, 2016 | $ | 518.2 | |||
Unit Corporation
Reconciliation of Segment Operating Profit
| Three Months Ended | Twelve Months Ended | |||||||||||||||||||
| September 30, | December 31, | December 31, | ||||||||||||||||||
| 2016 | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Oil and natural gas | $ | 52,840 | $ | 60,410 | $ | 39,655 | $ | 174,037 | $ | 219,728 | ||||||||||
| Contract drilling | 6,682 | 11,635 | 17,863 | 33,932 | 109,260 | |||||||||||||||
| Gas gathering and processing | 12,997 | 14,653 | 9,433 | 48,261 | 41,233 | |||||||||||||||
| Total operating profit | 72,519 | 86,698 | 66,951 | 256,230 | 370,221 | |||||||||||||||
| Depreciation, depletion and amortization | (50,441 | ) | (48,925 | ) | (74,567 | ) | (208,353 | ) | (352,742 | ) | ||||||||||
| Impairments | (49,443 | ) | — | (485,261 | ) | (161,563 | ) | (1,634,628 | ) | |||||||||||
| Total operating income (loss) | (27,365 | ) | 37,773 | (492,877 | ) | (113,686 | ) | (1,617,149 | ) | |||||||||||
| General and administrative | (8,380 | ) | (8,517 | ) | (8,467 | ) | (33,337 | ) | (34,358 | ) | ||||||||||
| Gain (loss) on disposition of assets | 154 | 1,717 | (959 | ) | 2,540 | (7,229 | ) | |||||||||||||
| Interest, net | (10,002 | ) | (9,604 | ) | (8,481 | ) | (39,829 | ) | (31,963 | ) | ||||||||||
| Gain (loss) on derivatives | 6,969 | (18,039 | ) | 13,428 | (22,813 | ) | 26,345 | |||||||||||||
| Other | 3 | 318 | 7 | 307 | 45 | |||||||||||||||
| Income (loss) before income taxes | $ | (38,621 | ) | $ | 3,648 | $ | (497,349 | ) | $ | (206,818 | ) | $ | (1,664,309 | ) | ||||||
________________
The Company has included segment operating profit because:
| • | It considers segment operating profit to be an important supplemental measure of operating performance for presenting trends in its core businesses. |
| • | Segment operating profit is useful to investors because it provides a means to evaluate the operating performance of the segments and Company on an ongoing basis using criteria that is used by management. |
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Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit
and Bad Debt Expense
| Three Months Ended | Twelve Months Ended | |||||||||||||||||||
| September 30, | December 31, | December 31, | ||||||||||||||||||
| 2016 | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
| (In thousands except for operating days and operating margins) | ||||||||||||||||||||
| Contract drilling revenue | $ | 25,819 | $ | 33,300 | $ | 50,554 | $ | 122,086 | $ | 265,668 | ||||||||||
| Contract drilling operating cost | 19,137 | 21,665 | 32,691 | 88,154 | 156,408 | |||||||||||||||
| Operating profit from contract drilling | 6,682 | 11,635 | 17,863 | 33,932 | 109,260 | |||||||||||||||
| Add: | ||||||||||||||||||||
| Elimination of intercompany rig profit and bad debt expense | — | — | 325 | 235 | 3,991 | |||||||||||||||
| Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense | 6,682 | 11,635 | 18,188 | 34,167 | 113,251 | |||||||||||||||
| Contract drilling operating days | 1,470 | 1,796 | 2,506 | 6,374 | 12,681 | |||||||||||||||
| Average daily operating margin before elimination of intercompany rig profit and bad debt expense | $ | 4,546 | $ | 6,478 | $ | 7,258 | $ | 5,360 | $ | 8,931 | ||||||||||
________________
The Company has included the average daily operating margin before elimination of intercompany rig profit and bad debt expense because:
| • | Its management uses the measurement to evaluate the cash flow performance of its contract drilling segment and to evaluate the performance of contract drilling management. |
| • | It is used by investors and financial analysts to evaluate the performance of the company. |
Unit Corporation
Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities
Twelve Months Ended December 31, | |||||||
| 2016 | 2015 | ||||||
| (In thousands) | |||||||
| Net cash provided by operating activities | $ | 240,130 | $ | 446,944 | |||
| Net change in operating assets and liabilities | (34,242 | ) | (49,085 | ) | |||
| Cash flow from operations before changes in operating assets and liabilities | $ | 205,888 | $ | 397,859 | |||
________________
The Company has included the cash flow from operations before changes in operating assets and liabilities because:
| • | It is an accepted financial indicator used by its management and companies in the industry to measure the company’s ability to generate cash which is used to internally fund its business activities. |
| • | It is used by investors and financial analysts to evaluate the performance of the company. |
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Unit Corporation
Reconciliation of Adjusted EBITDA
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| (In thousands except earnings per share) | ||||||||||||||||
| Net income (loss) | $ | 1,683 | $ | (309,337 | ) | $ | (135,624 | ) | $ | (1,037,361 | ) | |||||
| Income taxes | 1,965 | (188,012 | ) | (71,194 | ) | (626,948 | ) | |||||||||
| Depreciation, depletion and amortization | 48,925 | 74,567 | 208,353 | 352,742 | ||||||||||||
| Amortization of debt issuance costs and debt discounts | 536 | 524 | 2,122 | 2,088 | ||||||||||||
| Impairments | — | 485,261 | 161,563 | 1,634,628 | ||||||||||||
| Interest expense | 9,604 | 8,481 | 39,829 | 31,963 | ||||||||||||
| (Gain) loss on derivatives | 18,039 | (13,428 | ) | 22,813 | (26,345 | ) | ||||||||||
| Settlements during the period of matured derivative contracts | (2,077 | ) | 14,459 | 9,658 | 46,615 | |||||||||||
| Stock compensation plans | 3,148 | 8,954 | 13,812 | 21,468 | ||||||||||||
| Other non-cash items | 632 | 824 | 2,779 | 3,453 | ||||||||||||
| (Gain) loss on disposition of assets | (1,717 | ) | 959 | (2,540 | ) | 7,229 | ||||||||||
| Adjusted EBITDA | $ | 80,738 | $ | 83,252 | $ | 251,571 | $ | 409,532 | ||||||||
| Diluted earnings (loss) per share | $ | 0.03 | $ | (6.29 | ) | $ | (2.71 | ) | $ | (21.12 | ) | |||||
| Diluted earnings per share from income taxes | 0.04 | (3.82 | ) | (1.42 | ) | (12.77 | ) | |||||||||
| Diluted earnings per share from depreciation , depletion and amortization | 0.96 | 1.52 | 4.12 | 7.16 | ||||||||||||
| Diluted earnings per share from amortization of debt issuance costs and debt discounts | 0.01 | 0.01 | 0.04 | 0.04 | ||||||||||||
| Diluted earnings per share from impairments | — | 9.86 | 3.24 | 33.28 | ||||||||||||
| Diluted earnings per share from interest expense | 0.19 | 0.17 | 0.79 | 0.65 | ||||||||||||
| Diluted earnings per share from the (gain) loss on derivatives | 0.35 | (0.27 | ) | 0.45 | (0.53 | ) | ||||||||||
| Diluted earnings per share from the settlements during the period of matured derivative contracts | (0.04 | ) | 0.29 | 0.20 | 0.94 | |||||||||||
| Diluted earnings per share from stock compensation plans | 0.06 | 0.18 | 0.27 | 0.44 | ||||||||||||
| Diluted earnings per share from other non-cash items | 0.01 | 0.02 | 0.05 | 0.07 | ||||||||||||
| Diluted earnings per share (gain) loss on disposition of assets | (0.03 | ) | 0.02 | (0.05 | ) | 0.15 | ||||||||||
| Adjusted EBITDA per diluted share | $ | 1.58 | $ | 1.69 | $ | 4.98 | $ | 8.31 | ||||||||
________________
The Company has included the adjusted EBITDA, which excludes gain or loss on disposition of assets and includes only the cash settled commodity derivatives because:
| • | It uses the adjusted EBITDA to evaluate the operational performance of the company. |
| • | The adjusted EBITDA is more comparable to estimates provided by securities analysts. |
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