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UNIT CORP (UNTC)·Q4 2019 Earnings Summary

Executive Summary

  • Q4 2019 delivered a GAAP net loss of $334.98M and diluted EPS of $(6.33), driven by a $390.8M pre-tax impairment (ceiling test and small system write-offs); Adjusted net loss was $35.5M and adjusted diluted EPS $(0.67) .
  • Revenue was $164.36M, up 5.7% sequentially vs Q3 ($155.44M) but down 23.5% YoY vs Q4 2018 ($214.79M); Adjusted EBITDA was $65.39M, up q/q and ~26% below Q4 2018 .
  • Management suspended operated drilling, guided to ~10% LOE cuts in 2020, and set mid-stream 2020 capex at ~$28M (-57% YoY); contract drilling has no approved 2020 capital plan .
  • Liquidity tightened: Unit’s borrowing base was reduced to $200M (from $275M in Sept-2019), and the company did not host a Q4 call due to negotiations with banks and bondholders—both likely near-term stock catalysts .

What Went Well and What Went Wrong

What Went Well

  • Oil mix and pricing improved: Oil represented a higher share of volumes, with average realized oil price at $57.33/bbl (+1% q/q, +6% YoY) and realized price per Boe rose to $20.41 (+9% q/q) .
  • Segment operating improvements: Oil & gas operating profit rose to $53.0M (+24% q/q), and drilling margins/day increased to $6,001 (+30% q/q) as BOSS rigs stayed 100% utilized .
  • Strategic mid-stream expansion: Acquired ~600 miles of gathering pipeline and compression assets in central Oklahoma to enhance system flexibility and growth prospects .
  • Management quote: “We were able to increase our oil production by 12% year-over-year... We suspended our operated drilling rig program... We sold our Panola Field in eastern Oklahoma for $18 million.” .

What Went Wrong

  • Large impairments overshadowed operations: Q4 included a $390.8M pre-tax ceiling test impairment (plus minor write-offs), producing GAAP EPS of $(6.33) despite positive adjusted EBITDA .
  • Volume softness: Total production fell 5% q/q to 4.157 MBoE; gas volumes dipped 2% and NGLs 10% q/q, while rigs utilized fell to 18.3 (from 20.4) .
  • Liquids volumes weakness and mid-stream profit: Liquids sold were flat q/q but down 18% YoY; mid-stream operating profit declined 6% q/q and 14% YoY .
  • Analyst concern: Borrowing base cut to $200M and no Q4 webcast due to creditor negotiations highlight financing risk and potential constraints on capital deployment .

Financial Results

Consolidated P&L Snapshot

MetricQ4 2018Q2 2019Q3 2019Q4 2019
Revenue ($USD Millions)$214.79 $165.15 $155.44 $164.36
Net Income (Loss) Attributable ($USD Millions)$(77.84) $(8.51) $(206.89) $(334.98)
Diluted EPS (GAAP) ($USD)$(1.49) $(0.16) $(3.91) $(6.33)
Adjusted Diluted EPS ($USD, non-GAAP)$0.27 $(0.24) $(0.30) $(0.67)
Adjusted EBITDA ($USD Millions)$88.18 $59.25 $58.78 $65.39

EBITDA Margin (Computed)

MetricQ4 2018Q2 2019Q3 2019Q4 2019
Adjusted EBITDA Margin (%)41.1% 35.9% 37.8% 39.8%

Segment Revenue and Operating Profit

SegmentQ2 2019 Revenue ($MM)Q3 2019 Revenue ($MM)Q4 2019 Revenue ($MM)Q2 2019 Operating Profit ($MM)Q3 2019 Operating Profit ($MM)Q4 2019 Operating Profit ($MM)
Oil & Natural Gas$77.82 $78.05 $83.84 $41.57 $42.68 $53.04
Contract Drilling$43.04 $37.60 $36.60 $13.73 $8.80 $10.10
Mid-stream$44.29 $39.80 $43.92 $11.80 $11.31 $10.65

KPIs

KPIQ2 2019Q3 2019Q4 2019
Production (MBoE)4,151 4,394 4,157
Production (MBoE/day)45.6 47.8 45.2
Oil Production (MBbl)726 927 867
Natural Gas Production (Bcf)13.3 13.4 13.0
Avg Realized Oil Price ($/bbl)$59.94 $56.62 $57.33
Avg Realized NGL Price ($/bbl)$12.52 $8.50 $13.11
Realized Price per Boe ($)$18.75 $18.70 $20.41
Rigs Utilized (avg)28.6 20.4 18.3
Dayrate ($/day)$18,491 $19,276 $19,311
Drilling Avg Daily Operating Margin ($/day)$5,526 $4,635 $6,001
Gas Gathering (Mcf/day)465,714 428,573 399,019
Gas Processing (Mcf/day)165,682 167,687 162,766
Liquids Sold (Gallons/day)711,192 572,852 570,299

Actual vs Consensus (Q4 2019)

MetricActualConsensus (S&P Global)
Revenue ($USD Millions)$164.36 N/A (consensus unavailable via S&P Global at time of analysis)
Diluted EPS (GAAP) ($USD)$(6.33) N/A (consensus unavailable via S&P Global at time of analysis)
Adjusted Diluted EPS ($USD)$(0.67) N/A (consensus unavailable via S&P Global at time of analysis)

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Lease Operating ExpenseFY 2020N/A~10% reduction expectedLowered (cost improvement)
Mid-stream CapexFY 2020N/A (2019 baseline not disclosed)~$28MLowered (~57% YoY)
Oil & Gas Drilling ActivityFY 2020Operated rigs suspended since early Q3 2019 No plans to drill wellsLowered/maintained pause
Contract Drilling CapexFY 2020N/ANo approved capital planMaintained discipline
Unit Corp Borrowing Base (Credit Agreement)Current$275M (Sep 26, 2019)$200M (Jan 17, 2020)Lowered

Earnings Call Themes & Trends

TopicPrevious Mentions (Q2 2019)Previous Mentions (Q3 2019)Current Period (Q4 2019)Trend
Commodity Price HeadwindsNGL and gas price deterioration drove losses Loss driven by NGL/gas price deterioration Realized prices improved q/q, but YoY still mixed (NGLs down) Mixed
Oil Mix ShiftPlan to reach ~19–20% oil by YE; focus on Red Fork/SOHOT Oil rose to 21% of stream; new Redfork/Marchand wells O&G represented 48% of stream (combined); oil +12% YoY Improving
Contract Drilling Utilization28.6 rigs; dayrate $18.5K; margins boosted by terminations 20.4 rigs; dayrate $19.3K; margins/day $4,635 18.3 rigs; dayrate $19.3K; margins/day $6,001 Declining utilization, stronger margins
Mid-stream ExpansionNew 60 MMcf/d Reeding plant; throughput up YoY Modest volume changes; OP down 4% q/q Central OK asset acquisition adds ~600 miles pipeline Expanding via M&A
Capital DisciplineCapital aligned to cash flow; borrowings to be reduced No operated rigs running for E&P No drilling planned in 2020; drilling capex unapproved Tightening
Liquidity/LeverageUnit credit elected commitment $425M Borrowing base cut to $275M Borrowing base cut to $200M; no Q4 webcast (negotiations) Tightening liquidity

Management Commentary

  • “Our focus for 2019 was to increase the proportion of oil in our production mix... We were able to increase our oil production by 12% year-over-year... We suspended our operated drilling rig program... We sold our Panola Field in eastern Oklahoma for $18 million.” — Larry Pinkston, CEO .
  • “The increase in oil production during the quarter resulted from the new Redfork and Marchand wells which met or exceeded our expectations... we anticipate annual production to be in line with our projection of approximately 17.0 MMBoe... we continue to have no rigs currently running for this segment.” — Larry Pinkston .
  • “We projected a budget range of $336 million to $422 million... we anticipate that both our cash flow and our capital expenditures will end up at the low end... the oil and natural gas segment currently has no rigs operating... our acreage positions... are over 80% held by production.” — Larry Pinkston .

Q&A Highlights

  • No Q4 earnings call or webcast due to ongoing negotiations with banks and bondholders; therefore, no Q&A was held for Q4 .
  • Prior quarters had scheduled calls, but we did not identify transcripts in the current dataset; key clarifications came via press releases .

Estimates Context

  • S&P Global consensus estimates for Q4 2019 were unavailable at the time of analysis; therefore, estimate comparisons are omitted and tables mark consensus as N/A. We would normally anchor comparisons to S&P Global’s consensus for EPS, revenue, and EBITDA .

Key Takeaways for Investors

  • Core operations showed resilience: Adjusted EBITDA improved sequentially to $65.39M amid better realized prices and higher oil & gas operating profit, despite volume softness .
  • Impairment-driven GAAP loss is the headline, but adjusted results provide a clearer view for near-term operating trajectory; watch subsequent quarters for impairment risk tied to commodity prices .
  • Capital discipline and LOE reduction are supportive for 2020 cash flows; however, tightened borrowing base ($200M) and absence of a webcast underscore financing risk and potential constraints on growth .
  • Contract drilling utilization is cyclically weak (18.3 rigs), yet margins/day improved—near-term cash generation depends on sustaining dayrates and term contracts across the 14 BOSS rigs .
  • Mid-stream strategy pivoting to consolidation: the central Oklahoma acquisition should enhance system optionality; monitor volume trends and margin stability given YoY declines in liquids sold .
  • Asset portfolio optimization continues (eastern Oklahoma gas sale for $18M); further non-core divestitures could be a source of liquidity and deleveraging .
  • near-term stock drivers: creditor negotiations and liquidity updates, commodity price volatility (especially NGLs), and evidence of LOE reductions flowing through margins; absence of guidance on drilling may limit growth narratives short term .