Sign in

You're signed outSign in or to get full access.

EE

Epsilon Energy Ltd. (EPSN)·Q2 2025 Earnings Summary

Executive Summary

  • Q2 2025 revenue was $11.625M, down 28% QoQ and up 59% YoY; diluted EPS was $0.07. Sequential decline was driven by materially lower realized commodity pricing (gas −35%, oil −14%, NGL −25%), partially offset by stable midstream fees .
  • The company announced a transformational acquisition of Peak in the Powder River Basin, adding 40,500 net acres, 2.2 MBoepd of Q2 production, and a 150% increase in proved reserves (YE’24 basis), while maintaining dividend and a conservative leverage profile (~1x net debt/Adj. EBITDA pro forma) .
  • Versus S&P Global consensus, Q2 2025 was a slight miss on revenue ($11.625M actual vs $11.845M est.) and EPS ($0.0785 actual vs $0.08 est.) as weaker realized pricing weighed on results; Q1 2025 had been a notable beat on both metrics, highlighting volatility tied to pricing and timing of volumes *.
  • Operationally, Q2 capex was $4.0M, including Texas and Alberta activity; the quarter included a $2.7M impairment on the Alberta JV due to cost overruns and early underperformance, with management detailing learnings and a path to improvement .

What Went Well and What Went Wrong

What Went Well

  • Strategic expansion via Peak acquisition enhances operated, oil‑weighted inventory with attractive economics (Parkman, Niobrara, Mowry), adds experienced in‑basin team, and maintains dividend capacity; “We think this PRB platform provides the opportunity for both organic and inorganic growth” .
  • Strong Adjusted EBITDA of $7.396M despite price headwinds, up 89% YoY; cash + short‑term investments rose 41% QoQ to $10.378M, underscoring balance sheet resilience .
  • Midstream revenues remained resilient at $1.845M (−3% QoQ; +28% YoY), providing diversification amid commodity price volatility .

What Went Wrong

  • Sequential revenue decline (−28% QoQ) driven by lower realized prices across gas (−35%), oil (−14%), and NGL (−25%); total production was slightly down QoQ (−1%) .
  • Alberta JV impairment of $2.7M due to drilling/completion cost overruns and early well performance below expectations; management signaled process and planning improvements going forward .
  • Oil revenue decreased 17% QoQ and 22% YoY; NGL volumes halved QoQ and fell 59% YoY, pressuring liquids contribution .

Financial Results

Consolidated P&L vs Prior Periods and Estimates

MetricQ4 2024Q1 2025Q2 2025
Revenue ($USD)$8.940M*$16.163M $11.625M
Diluted EPS ($)$0.0196*$0.2156*$0.07
Net Income ($USD)N/AN/A$1,551,461
Net Income Margin (%)11.94%*24.85%*13.35%*
Adjusted EBITDA ($USD)$3.904M $10.609M $7.396M

Notes: Values marked with * retrieved from S&P Global.

Q2 2025 Actual vs S&P Global Consensus

MetricEstimateActual
Revenue ($USD)$11,845,000*$11,624,733
Primary EPS ($)$0.08*$0.0785*

Notes: Values marked with * retrieved from S&P Global.

Segment Revenue Breakdown (Oldest → Newest)

SegmentQ2 2024 ($M)Q1 2025 ($M)Q2 2025 ($M)
Gas1.961 10.614 6.910
Oil3.514 3.270 2.725
NGL0.389 0.387 0.145
Midstream1.444 1.892 1.845
Total7.308 16.163 11.625

Operating KPIs (Volumes, Prices, Cash, Capex)

KPIQ2 2024Q1 2025Q2 2025
Total Production (MMcfe)1,791 3,108 3,064
Daily Rate (MMcfe/d)19.7 34.5 33.7
Gas Price ($/Mcf)1.39 3.87 2.51
Oil Price ($/Bbl)78.44 71.75 61.72
NGL Price ($/Bbl)20.21 24.52 18.51
Adjusted EBITDA ($M)3.904 10.609 7.396
Cash + STI ($M)9.481 7.363 10.378
Capex ($M, incl. acquisitions)5.709 8.035 4.032
Dividend ($M)1.372 1.376 1.376

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Dividend per shareQuarterlyMaintain fixed dividend; $0.0625 declared for Jun 30, 2025 Maintain dividend per share post‑Peak; “comfortably maintain” Maintained
Marcellus development2025–2026No incremental activity in 2025; operator plan to drill 7 gross (1.2 net) starting 2026 Reaffirmed start in 2026; 7 gross (1.2 net) wells across two pads in Q4 2026 Maintained
Permian Barnett2025Minimal activity; 2 gross wells to meet obligations in 2H25 8th well (Irma Unit 1H) completed; planning ≥2 gross wells in 2026 Clarified next‑year plan
Alberta JV2025Two wells on flowback; plan 2 more in 2025 Q2 impairment recognized; process improvements; continued prudent planning Maintained with caution
Leverage/LiquidityQ4 2025 close (pro forma)No net debt; strong liquidity RBL upsized to $95M indicative; ~50% drawn at close; net debt/Adj. EBITDA ≈ 1x Increased leverage (conservative)
Hedging2025–2026~30% gas hedged through Oct ’25; tactical adds considered FY25 hedge book outlined; collars/swaps; building 2026 collars and swaps Maintained; extended visibility

Earnings Call Themes & Trends

TopicPrevious Mentions (Q4 2024, Q1 2025)Current Period (Q2 2025)Trend
Portfolio diversificationPermian ramp, Alberta JV established; Marcellus volumes rebounding Peak acquisition adds PRB core; operated inventory; balanced oil/gas optionality Positive inflection
Marcellus operator planDeferred TILs lifted; strong pricing; no 2025 drilling; start in 2026 Reaffirmed drilling in 2026; 7 gross/1.2 net wells; Auburn system supports throughput Stable
Permian Barnett execution2024 build; 2H25 wells to meet obligations 8th well completed; planning ≥2 wells in 2026 Stable to positive
Alberta JV performanceEarly stage; initial wells on flowback; plan two more in 2025 Q2 impairment; process improvements; cautious continuation Mixed/learning curve
Hedging strategy30% gas hedged through Oct ’25; tactical adds Detailed hedge book 2025–2027; collars/swaps mix More structured
Capital allocationDividend maintained; opportunistic buybacks Dividend maintained; leverage conservative; development across Marcellus/Permian/PRB from 2026 Stable

Management Commentary

  • “The deal adds a new core area to the company at an attractive price… approximately 75% held by production, allowing for returns driven capital allocation over time as commodity prices dictate” — CEO, Jason Stabell .
  • “We will be approximately 50% drawn with a forecasted net debt to adjusted EBITDA ratio of approximately one times… [and] comfortably maintain our existing per share dividend” — CFO, Andrew Williamson .
  • “We learned valuable lessons that will improve our drilling and completion approach… we still feel the asset has great potential” — CEO, Jason Stabell, on Alberta JV .
  • “Initial plans for next year call for the development of three high working interest Parkman wells… This acquisition adds approximately 2,200 net BOE/d, 56% oil” — COO, Henry Clanton .

Q&A Highlights

  • The Q2 2025 call transcript reflects minimal public Q&A; the session concluded quickly with management remarks emphasizing the Peak acquisition, leverage/dividend framework, and multi‑basin development plans .
  • Key clarifications came in prepared remarks: pro forma leverage (~1x), RBL expansion ($95M indicative) and dividend maintenance ; near‑term operational focus in PRB Parkman, with Niobrara/Mowry delineation over time .

Estimates Context

  • Q2 2025: Revenue $11.625M vs $11.845M consensus (slight miss) and EPS $0.0785 vs $0.08 consensus (slight miss). Pricing downdraft drove the miss as gas/oil/NGL realizations fell sequentially *.
  • Q1 2025: Revenue $16.163M vs $11.713M consensus (beat) and EPS $0.2156 vs $0.14 consensus (beat), driven by Marcellus volume recovery and stronger realized pricing, including midstream throughput uplift *.
  • Q4 2024: Revenue $8.940M vs $9.027M consensus (miss) and EPS $0.0196 vs $0.05 consensus (miss), consistent with prior pricing headwinds and production curtailments *.

Notes: Values marked with * retrieved from S&P Global.

Key Takeaways for Investors

  • Sequential softness was largely price‑driven; production held roughly flat QoQ (−1%), reinforcing that realized pricing is the dominant earnings lever near term .
  • The Peak transaction is a portfolio‑defining shift: adds operated oil‑weighted growth with strong inventory economics while preserving dividend and conservative pro forma leverage (~1x), a likely medium‑term re‑rating catalyst .
  • Alberta JV impairment is a watch item; management is implementing drilling/completion refinements—expect disciplined follow‑through before scaling capital there .
  • Marcellus visibility improved: operator plans backed into reserves with drilling resuming 2026; Auburn system throughput and lower suction pressure underpin midstream stability .
  • Hedge book provides downside protection through FY25 and building into FY26–27; however, Q2 demonstrated earnings sensitivity to spot realizations, particularly gas .
  • Near‑term trading: headline acquisition/operated control and dividend maintenance are positives; Q2 slight miss and impairment may temper sentiment until PRB execution milestones emerge .
  • Medium‑term thesis: diversified, multi‑basin optionality (Marcellus/Permian/PRB) with improving development cadence and balanced commodity mix supports per‑share value growth once PRB program and 2026 Marcellus wells ramp .