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UNIT CORP (UNTC)·Q3 2019 Earnings Summary

Executive Summary

  • Q3 2019 headline loss driven by non-cash impairments: net loss $206.9M ($3.91 diluted EPS); adjusted net loss was $15.7M ($0.30) as NGL and gas price deterioration offset higher oil volumes .
  • Total revenues fell to $155.4M, down 29% YoY and 6% QoQ; Adjusted EBITDA was $58.8M, steady QoQ but below prior year .
  • Operations executed well: oil production +26–28% QoQ with Red Fork/Marchand wells meeting/exceeding expectations; BOSS rigs remained 100% contracted; midstream Cashion/Reeding throughput increased .
  • Balance sheet developments: borrowing base reduced to $275M; management initiated exchange offer to extend 2021 subordinated notes and targeted Q4 free cash flow to reduce debt .

What Went Well and What Went Wrong

  • What Went Well

    • “Continued focus on increasing oil production, with this quarter's oil production increasing 28% over the second quarter and representing 21% of total equivalent production” .
    • Red Fork and SOHOT well results “continue to meet or exceed expectations”; eight new horizontals brought online with strong IP30s (e.g., Saratoga 1HX ~3,000 BOE/d, Wingard Farms 1HX ~2,800 BOE/d) .
    • BOSS rigs at 100% utilization; construction of 14th BOSS rig substantially complete and expected to start in Q4, with contract extensions from a key operator .
    • Midstream: third-party activity around Cashion/Reeding boosted throughput; Q3 Cashion throughput ~63.5 MMcf/d and NGLs ~276,000 gallons/d, with 11 new wells connected in Q3 .

  • What Went Wrong

    • Large non-cash impairments: $169.8M ceiling test (E&P), $62.8M goodwill (drilling), $2.3M line-fill (midstream), driving reported loss despite underlying operations .
    • NGL price collapse: average NGL price fell to $8.50/bbl (−32% QoQ; −67% YoY), pressuring margins despite higher oil volumes; realized price per BOE was $18.70 (flat QoQ, −19% YoY) .
    • Contract drilling utilization down sharply (20.4 rigs vs. 28.6 in Q2); average per-day operating margin fell to $4,635 (−16% QoQ) due to fixed costs and stacking expenses .
    • Borrowing base reduced to $275M, reflecting commodity price backdrop; long-term debt ended Q3 at $784.4M .

Financial Results

MetricQ3 2018Q1 2019Q2 2019Q3 2019
Revenue ($USD Millions)$220.1 $189.7 $165.1 $155.4
Diluted EPS ($)$0.36 $(0.07) $(0.16) $(3.91)
Net Income (Loss) ($USD Millions)$18.9 $(3.5) $(8.5) $(206.9)
Adjusted Diluted EPS ($)$0.30 $0.09 $(0.24) $(0.30)
Adjusted EBITDA ($USD Millions)$90.8 $77.1 $59.3 $58.8
Adjusted EBITDA Margin (%)41.3% 40.6% 35.9% 37.8%

Segment revenue and operating profit

SegmentQ3 2018 Revenue ($MM)Q2 2019 Revenue ($MM)Q3 2019 Revenue ($MM)Q3 2018 Op Profit pre DDA ($MM)Q2 2019 Op Profit pre DDA ($MM)Q3 2019 Op Profit pre DDA ($MM)
Oil & Natural Gas$111.6 $77.8 $78.0 $79.5 $41.6 $42.7
Contract Drilling$50.6 $43.0 $37.6 $18.6 $13.7 $8.8
Midstream (Gas Gathering & Processing)$57.8 $44.3 $39.8 $14.7 $11.8 $11.3

Key operating KPIs

KPIQ3 2018Q2 2019Q3 2019
Oil Production (MBbl)692 726 927
NGLs Production (MBbl)1,278 1,210 1,240
Natural Gas Production (Bcf)14.3 13.3 13.4
Total Production (MBoe)4,359 4,151 4,394
Avg Realized Oil Price ($/Bbl)$57.72 $59.94 $56.62
Avg Realized NGL Price ($/Bbl)$25.66 $12.52 $8.50
Avg Realized Gas Price ($/Mcf)$2.27 $1.86 $1.83
Realized Price per BOE ($)$22.96 $18.75 $18.70
Rigs Utilized (Drilling)34.2 28.6 20.4
Avg Per-Day Operating Margin ($)$6,291 $5,526 $4,635
Midstream Gas Gathering (Mcf/d)415,862 465,714 428,573
Midstream Gas Processing (Mcf/d)160,294 165,682 167,687
Midstream Liquids Sold (gal/d)700,523 711,192 572,852

Non-GAAP adjustments and impacts

  • Impairments in Q3: $169.8M ceiling test (E&P/midstream assets), $62.8M goodwill (drilling), $2.3M line-fill (midstream), materially impacting GAAP EPS but excluded from adjusted metrics .
  • Adjusted net loss reconciles by adding back impairments and cash-settled derivatives; adjusted diluted EPS was $(0.30) vs $0.30 in Q3 2018 .

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Full-year production (MMBoe)FY 201917.0–17.2 MMBoe ~17.0 MMBoe Lowered to low end
Oil mix (% of production)FY 2019 (target)~19–20% by year-end Q3 actual 21% (quarter) Tracking above target in Q3
Capital expendituresFY 2019Budget range $336–$422M; expected low end QoQ capex −56%; focus on Q4 free cash flow to reduce debt Tilted to low end; spending reduced
Borrowing base (Unit Corp credit)As of Sep 26, 2019$425M elected commitment/borrowing base (April) $275M borrowing base re-determined Lowered
14th BOSS rig statusQ4 2019 startLong-term contract obtained; under construction Construction substantially complete; expected to begin work in Q4 Timeline confirmed
Refinancing plan (6.625% notes due 2021)Near termNot discussedPreliminary registration filed to exchange for new notes; objective to extend maturities New initiative

Earnings Call Themes & Trends

TopicPrevious Mentions (Q1 & Q2)Current Period (Q3)Trend
Oil-weighted development focusQ1: Refocused capital to Red Fork/Marchand; 4 operated rigs in Western OK . Q2: Expect oil to be 19–20% by YE; strong Red Fork IPs .Oil production +26–28% QoQ; oil 21% of production; Red Fork/Marchand wells exceeded expectations .Strengthening oil mix; execution delivering volumes.
Commodity price headwinds (NGL/gas)Q1: Plant shutdown impacted Wilcox; NGL prices −18% vs Q4 . Q2: NGL and gas price deterioration drove loss .NGL price $8.50/bbl (−32% QoQ; −67% YoY); realized BOE price flat QoQ, down YoY .Persistent price pressure; margins constrained.
Contract drilling utilization and marginsQ1: BOSS rigs fully contracted; margin $7,376/day incl. term fees . Q2: Utilization down to 28.6 rigs; margin $5,526/day .Utilization 20.4 rigs; margin $4,635/day; fixed/stacking costs weighed .Utilization/margins compressing with rig count declines.
Midstream capacity/throughputQ1: Reeding plant placed in service post-Q1; throughput +14% . Q2: Reeding plant installation completed; Cashion throughput +27% YoY .Cashion throughput ~63.5 MMcf/d; 11 new wells connected in Q3; processing capacity ~105 MMcf/d .Expanding capacity; third-party activity supportive.
Balance sheet and refinancingQ2: Long-term debt $756.6M; borrowing base $425M .Borrowing base reduced to $275M; initiated exchange of 2021 notes; targeting Q4 free cash flow for debt reduction .Active de-leveraging steps; tighter liquidity.

Management Commentary

  • CEO: “We continued to navigate a very challenged commodity price backdrop… we remain focused on balance sheet… actions… anticipated to generate free cash flow during the fourth quarter that will be used to reduce debt” .
  • CFO: “Filed a preliminary registration statement offering to exchange our 6.625% senior subordinated notes maturing in 2021 for new notes… to extend the maturity profile and eliminate short- to medium-term refinancing risks” .
  • E&P lead: “Average IP30 of the 4 Red Fork wells was 2,150 BOE per day with an average oil cut of 72%… our AFE cost for a Red Fork horizontal well with a 7,500-foot lateral is approximately $7 million” .
  • Drilling lead: “All 13 of our BOSS rigs are operating with 10 of them on term contracts… average per day operating margin… $4,635… expect rig activity to remain flat in Q4 and increase in Q1 2020” .
  • Midstream lead: “New 60 MMcf/d Reeding processing plant is fully operational… processing capacity at Cashion ~105 MMcf/d… actively searching for acquisition and expansion opportunities with the $200M stand-alone credit facility” .

Q&A Highlights

  • The available transcript content encompasses prepared remarks; a Q&A section was not accessible in the dataset due to a document retrieval inconsistency. Management addressed capital allocation, refinancing, and segment operating dynamics within the prepared remarks .

Estimates Context

  • Wall Street consensus (S&P Global) for Q3 2019 EPS and revenue was unavailable due to access limitations (daily request cap exceeded). As a result, comparison vs estimates cannot be provided for this quarter using S&P Global data.

Key Takeaways for Investors

  • Underlying operations performed: oil volumes and E&P execution improved, but pricing headwinds (especially NGLs) dominated reported results and compressed realized BOE pricing .
  • Balance sheet actions are important catalysts: note exchange filing to extend maturities and targeted Q4 free cash flow to reduce debt; monitor liquidity post borrowing base reset to $275M .
  • Drilling segment is levered to industry rig activity; despite BOSS fleet strength, declining utilization cut margins; watch for potential Q1 activity uptick with new budgets .
  • Midstream assets benefitting from third-party growth and expanded capacity at Cashion/Reeding; fee-based contracts help stability amid low commodity prices .
  • Non-cash impairments overshadowed GAAP results; adjusted metrics better reflect operating trends, but pricing remains the key swing factor for earnings power .
  • 2019 production guidance narrowed to ~17.0 MMBoe (low end); oil mix tracking ahead of prior YE target supports margin resilience if prices stabilize .
  • Near-term trading: stock likely sensitive to updates on the debt exchange, Q4 free cash flow delivery, and commodity price moves; medium-term thesis hinges on oil-weighted development, BOSS rig contract stability, and midstream throughput growth .