EQT Financial Model

• Total assets: Approximately $35 billion to $40 billion post-Equitrans.
• Key asset categories: Property, Plant and Equipment (PP&E) dominates the balance sheet. This is split into proved and unproved oil and gas properties (successful efforts method) and midstream infrastructure.
• Goodwill & intangibles: Materially increased following the Equitrans and Tug Hill acquisitions.
• Working capital profile:
• DSO: 30 to 45 days.
• DPO: 45 to 60 days.
• Net working capital: Often negative or highly volatile due to the fair value of derivative instruments (hedging assets and liabilities). EQT does not structurally fund growth from working capital.
• PP&E: Depleted based on proved developed reserves. Midstream assets are depreciated straight-line over 15 to 40 years.
• Right-of-use assets: Present for drilling rig leases and office space but small relative to total PP&E.

• Capex as % of revenue: Less relevant for E&P than absolute capital intensity. EQT targets maintenance capex of $2.0 billion to $2.2 billion to hold production flat.
• Maintenance vs. growth split: Approximately 75% maintenance (reserve development) and 25% growth (midstream compression, water infrastructure, strategic leasing).
• Major capex programmes: Drilling and completion (D&C) in the Marcellus/Utica, and midstream compression projects to debottleneck the system.
• M&A pattern: Transformational acquirer. EQT has consolidated the Appalachian basin through massive acquisitions (Alta, Tug Hill, Equitrans).

• Total debt: Approximately $9.3 billion at year-end 2024, with net debt of $9.1 billion.
• Debt/EBITDA ratio: Currently elevated post-acquisition (approx. 2.0x to 2.5x depending on gas prices). The company targets absolute net debt of $7.5 billion or lower.
• Credit rating: Investment grade (BBB- / Baa3).
• Key debt instruments: Unsecured senior notes, a $3.5 billion revolving credit facility, and term loans used for acquisitions.
• Maturity profile: Laddered senior notes with maturities stretching beyond 2030.
• Interest rate profile: Predominantly fixed-rate senior notes.
• Share repurchase programme: Historically active but paused or reduced during the Equitrans integration to prioritise debt paydown.
• Dividend policy: Regular quarterly cash dividend, typically yielding 1.5% to 2.5%, with a focus on sustainable base dividends rather than variable payouts.

• Operating cash flow conversion: Very strong. OCF frequently exceeds net income due to massive non-cash DD&A charges and deferred taxes.
• Free cash flow margin: Highly dependent on gas prices. EQT generated nearly $600 million of FCF in Q4 2024 alone despite sub-$3.00 gas.
• Major non-cash items: DD&A, deferred income taxes, and unrealised gains/losses on derivatives.
• Working capital cash flow impact: Can cause $300 million to $500 million swings in a single quarter based on the timing of royalty payments and derivative settlements.
• Capex intensity: High absolute dollar spend (approx. $2.6 billion to $2.8 billion annually) but low on a per-unit basis ($0.60 to $0.70 per Mcfe).
• Cash tax rate: Often lower than the statutory rate due to intangible drilling costs (IDCs) and accelerated depreciation tax shields.

1. Assumptions: Macro drivers (NYMEX Henry Hub, WTI), basis differentials, production guidance, unit cost guidance, and capex budgets.
2. Scenarios: Base, High, and Low commodity price decks to stress-test cash flows and debt covenants.
3. Production & Reserves: Roll-forward of proved reserves (PUDs to PDPs), well turn-in-line (TIL) schedule, and production volume build by product (Gas, NGLs, Oil).
4. Pricing & Hedging: Calculation of realised prices including NYMEX, local basis, and a detailed schedule of fixed-price swaps and collar settlements.
5. Income Statement: Segmented revenue (Upstream, Midstream), LOE, GPT, production taxes, SG&A, DD&A, interest, and taxes.
6. Balance Sheet: PP&E roll-forward (successful efforts), derivative assets/liabilities, working capital, and debt tranches.
7. Cash Flow Statement: Net income to OCF bridge (adding back DD&A and unrealised hedging), investing cash flows (D&C capex, midstream capex), and financing cash flows (debt paydown, dividends).
8. Debt Schedule: Tranche-by-tranche roll-forward of senior notes and the revolving credit facility, calculating interest expense and tracking the path to the $7.5 billion net debt target.
9. DCF & NAV Valuation: Traditional DCF for corporate valuation, plus a Net Asset Value (NAV) model valuing PDP, PUD, and unproved reserves based on discounted cash flows at the wellhead, plus the standalone value of the Midstream segment.

1. Total Production (Bcfe) = Natural Gas (Bcf) + (NGLs (MMbbls) * 6) + (Oil (MMbbls) * 6).
2. Upstream Revenue = Total Production (Bcfe) * (NYMEX Henry Hub + Basis Differential + Hedging Impact).
3. Midstream Revenue = Third-Party Gathered Volumes * Average Gathering Fee + MVP Distributions.
4. Total Operating Costs = LOE + GPT + Production Taxes + SG&A.
5. Per Unit Metrics ($/Mcfe) = Total Expense Line Item / Total Production (Mcfe).
6. DD&A Expense = Total Production (Bcfe) * Depletion Rate ($/Mcfe).
7. Unlevered Free Cash Flow = Adjusted EBITDA - Capex - Cash Taxes.
8. Net Debt = Total Short-Term Debt + Total Long-Term Debt - Cash and Cash Equivalents.
9. Interest Expense = (Average Revolver Balance * Floating Rate) + Sum(Senior Notes * Fixed Rates).
10. Reserve Replacement Ratio = (Extensions + Discoveries + Revisions + Acquisitions) / Total Production.
11. Base Synergy Realisation = Equitrans Opex Reductions + Eliminated Third-Party Fees.

The critical chain begins on the Assumptions and Scenarios sheets, which feed commodity prices into the Pricing & Hedging sheet. The Production & Reserves sheet calculates volumes, which multiply with realised prices to generate revenue on the Income Statement. Production volumes also drive variable costs (LOE, GPT) on the Income Statement. EBITDA flows to the Cash Flow Statement, where Capex (from Assumptions) is deducted to find Free Cash Flow. This FCF dictates the revolver draw or paydown on the Debt Schedule. The Debt Schedule calculates interest expense, which loops back to the Income Statement (potential circularity here, requiring an iterative calculation or a switch to break the loop). Finally, all cash flows feed the DCF & NAV Valuation.

• Revenues and production volumes are entered and displayed as positive numbers.
• Operating expenses (LOE, GPT, SG&A) and Capex are entered as positive numbers in assumption blocks but subtracted in formulas (e.g., EBITDA = Revenue - Opex).
• On the Cash Flow Statement, cash inflows are positive, and cash outflows (capex, debt paydown, dividends) are negative.
• Debt balances are positive; a paydown is a negative adjustment to the balance.

1. Equitrans Stub Period: The Equitrans acquisition closed in July 2024. Historical 2023 and H1 2024 figures do not include Equitrans, making YoY comparisons meaningless without pro-forma adjustments.
2. Hedging Distortions: EQT uses complex derivatives. The model must separate unrealised mark-to-market gains (non-cash) from actual cash settlements to calculate true operating cash flow.
3. Volume Conversions: Natural gas is measured in Bcf, liquids in MMbbls. The builder must strictly adhere to the 6:1 energy equivalent ratio (1 barrel = 6 Mcf) to calculate total Bcfe.
4. Midstream Eliminations: Post-acquisition, EQT pays gathering fees to its own midstream segment. These intercompany revenues and expenses must be eliminated in consolidation to avoid double-counting.
5. Circularity in Interest: Debt paydown depends on cash flow, which depends on interest expense, which depends on debt balances. Implement a circuit breaker toggle.
6. Depletion Rate Volatility: DD&A per Mcfe changes annually based on reserve revisions. Holding it flat indefinitely will distort long-term EBIT.
7. Curtailments: EQT tactically chokes back production when prices are low (e.g., 27 Bcfe curtailed in Q4 2024). The model needs a toggle to reduce volumes if the price deck falls below $2.00/MMBtu.
8. Working Capital Swings: Do not project historical working capital changes as a percentage of revenue. In E&P, these are driven by derivative asset/liability settlements and should be modelled as zero in the terminal year.

1. "Unlevered FCF breakeven should be approximately $2.00/MMBtu; flag if the model requires >$2.50 to generate positive FCF".
2. "Total per unit operating costs (LOE + GPT + Taxes + SG&A) should fall between $1.05 and $1.25 per Mcfe".
3. "Net debt must trend toward the $7.5 billion target; flag if leverage increases in a base-case $3.00 gas environment".
4. "Production volumes for 2026 should align with guidance of 2,275 to 2,375 Bcfe".
5. "Maintenance capex should be between $2.07 billion and $2.21 billion in 2026".
6. "Balance sheet must balance: Total Assets = Total Liabilities + Equity in every period."
7. "DD&A should be the largest single expense line item, typically >$1.00 per Mcfe."
8. "Interest expense should reflect a blended cost of debt around 5-6% on the $9.3 billion principal."

• Filings: SEC EDGAR (EQT 10-K, 10-Q, 8-K) and the EQT Investor Relations page (ir.eqt.com) for earnings presentations.
• Key Peers: Antero Resources (AR), Coterra Energy (CTRA), Range Resources (RRC), and Chesapeake Energy / Expand Energy (EXE).
• Industry Data: Enverus for well-level data and rig counts; EIA (Energy Information Administration) for macro natural gas storage and demand data.
• Consensus Estimates: FactSet or Bloomberg for forward commodity curves and analyst EPS/EBITDA estimates.

• EQT Completes Acquisition of Equitrans Midstream (July 2024)
• EQT Q3 2024 Earnings Release (October 2024)
• EQT Q4 2024 Earnings Release and Presentation (February 2025)
• EQT Q4 2024 Earnings Call Transcript (February 2025)
• EQT Q4 2025 Earnings Release and 2026 Guidance (February 2026)
• EQT 2024 Annual Report on Form 10-K