Devon Energy (DVN) — Stock Analysis 2026 [4.1]

Analysis as of 7 September 2026. This is a point-in-time snapshot of the combined Devon Energy — the all-stock merger of equals with Coterra Energy (agreed 1 Feb 2026, closed ~7 May 2026), which reported its first combined quarter on 4 August 2026. Operating fundamentals (production, reserves, standardized measure) remain on the pro-forma FY2025 / year-end-2025 basis from the Devon/Coterra joint proxy statement, refined by the combined company’s first results; per-basin detail is from Devon’s FY2025 10-K. Market data — share price, market cap, enterprise value, net debt and analyst targets — is as of the 4 September 2026 close. Rating: ★★★★, Solid — Modestly overvalued (wide band) → a top-tier operator priced ahead of its reserves: watch for a better entry. Price deck used in the valuation: base WTI US$70/bbl — the twelve-month trailing average of US$75.87 leaned to the lower price of the fixed US$60–100 grid, because the window carries the March–May 2026 Hormuz spike — with every grid price run as a scenario (bear US$60 / base US$70 / bull US$80 / deep bull US$90 / extreme bull US$100); Henry Hub US$3.00/MMBtu; 10% discount rate; no spot deck is carried. For information only, prepared with AI assistance — see the disclaimer at the end.

Devon Energy has become one of the largest independents in US shale. Its all-stock merger of equals with Coterra Energy — closed in May 2026 — pairs Devon’s oil-rich, four-basin base with Coterra’s premier Marcellus gas position, creating a ~1.6-million-barrel-of-oil-equivalent-per-day producer with a strong balance sheet, US$1 billion of targeted synergies and a bigger, more diversified reserve base. The thesis in one line: a top-tier, oil-and-gas-balanced US independent with low leverage and enhanced cash returns — one whose shares have recovered toward their spring high on a conflict-era oil tape, and now price crude near US$96 a barrel held flat forever. To screen the merged Devon against every US upstream name on production, cost, reserve life and free-cash-flow yield, go to Metal Pilot.

1. Snapshot & thesis

The combined Devon Energy Corporation (NYSE: DVN) is an independent oil & natural-gas exploration and production (E&P) company — now headquartered in Houston, Texas following the merger — operating entirely onshore in the United States. It is a producer/operator by archetype and an energy producer by sector, and after the Coterra combination it spans five core areas: the Delaware Basin (the oil-rich Permian core, from both companies), the Marcellus Shale in Pennsylvania (Coterra’s premier natural-gas position), the Rockies/Williston and Eagle Ford (Devon’s oil plays) and the Anadarko Basin (gas, from both). On a pro-forma FY2025 basis it produced ~1,624 thousand barrels of oil equivalent, annualized, i.e. ~591.3 mmboe/yr — 34% crude oil, 45% gas, 21% NGL — and held 4,993 million boe (mmboe) of proved reserves. (boe = barrel of oil equivalent, gas converted to oil at 6:1 by energy content; mmboe = million boe and mboe/d = thousand boe per day, an annual-average daily rate.)

Figure 1. Devon Energy (combined) in numbers

Figure data: Devon/Coterra joint proxy statement pro-forma combined figures; Devon FY2025 10-K ; market data per stockanalysis.com as of the 4 September 2026 close (combined share count ~1,150 m). FCF is a pro-forma run-rate estimate (trailing FCF is depressed by merger-year capex). Rating per Section 9.

Table 1. Devon Energy (combined, pro-forma FY2025) in numbers

Source: Devon/Coterra joint proxy statement , unaudited pro-forma combined financial statements and reserve disclosures (as if the merger completed 1 Jan 2025); Devon FY2025 10-K ; market data per stockanalysis.com , 4 Sep 2026. EV = market cap + net debt (outstanding debt ~US$11.4 bn − cash ~US$1.0 bn = ~US$10.4 bn, the US$0.5 bn of lease liabilities excluded and charged inside production costs); forward EBITDA on the Q3 2026 guidance run-rate is US$10.1 bn at the base deck (Section 7.3). Pro-forma operating figures are illustrative, not the combined company’s audited results.

Thesis in brief. Bull: the merger creates a top-tier US independent (~584 mmboe/yr, ~5.0 Bn boe proved) that is more diversified (Delaware oil + Marcellus gas), carries low leverage (~1.0× net debt/EBITDAX), targets US$1 billion of annual synergies, and pays a ~2.8%-yield dividend alongside a >US$5 billion buyback — and delivered 503,000 barrels of oil a day and US$1.7 billion of adjusted free cash flow in its first combined quarter. Bear: it is still a price-taker, now gassier (only 34% oil, and its Delaware gas realises a Waha-discounted US$1.05/Mcf), it must integrate the largest deal in either company’s history under a first-year Devon CEO, it reinvests 57% of EBITDA to hold an 8.2-year reserve book flat, and on the base deck the blended fair value sits 30% below the price. What tips it: whether the conflict-era oil price the shares capitalise persists, and whether US$1 billion of synergies lands — versus a reversion toward the deck the trailing average and the EIA’s 2027 forecast both point at. The full rating and its rationale are in Section 9.

How to read this analysis: here for the verdict? The statcards above and the rating in Section 9 are the whole story. Want the evidence? Read Section 2 (the assets) through Section 7 (the valuation).

2. Assets & operations

The combined company is a leveraged play on North American oil and gas, so the backdrop matters on both sides: after a soft 2025 (WTI averaged US$65.46/bbl), crude spiked through the Strait of Hormuz disruption to a monthly peak of US$102.13/bbl in May 2026 and averaged US$83.90 in August, while Henry Hub gas stayed weak at US$2.78/MMBtu — the reason Coterra’s low-cost Marcellus volumes are a swing factor for the merged group and a drag while gas is this soft. Devon’s own Delaware gas realises far less than the benchmark: US$1.05/Mcf in the second quarter of 2026, against US$88.09/bbl for oil. For the full picture of how crude is priced, see the Oil — A Complete Market Guide ; the gas and NGL side, now a much larger share of the portfolio, is covered in the Natural Gas guide . This section spends its words on the company.

2.1 Portfolio overview & map

The merged portfolio is best understood as an oil engine (Devon) bolted to a gas engine (Coterra), unified in the Delaware Basin where both held premium Permian acreage. Coterra contributes the Marcellus (a top Appalachian gas position), adds scale in the Anadarko, and deepens the Delaware; Devon brings the Rockies/Williston and Eagle Ford oil plays. All operations are 100%-operated onshore US.

Table 2. Combined asset base (pro-forma FY2025)

Source: Devon/Coterra joint proxy statement (Coterra assets: Delaware, Marcellus, Anadarko) and Devon FY2025 10-K (Devon basins). All interests are publicly listed operated positions (NYSE: DVN). Output shares are approximate pending combined-company segment reporting; Devon contributed ~306.6 mmboe/yr and Coterra ~286.2 mmboe/yr of the ~592.8 mmboe/yr pro-forma total.

The concentration read shifts with the merger: the Delaware Basin remains the single largest and highest-value area, but the portfolio is now materially more balanced between oil and gas, with the Marcellus turning Devon from a ~46%-oil producer into a ~34%-oil, gas-heavy major. A proportional-symbol asset map is not drawn — a component that prints a value on every mark cannot render a legible geographic map (Section 10.1) — so the table and this paragraph carry the read.

2.2 Revenue split — by product & by asset

Two cuts of the same revenue base tell the story. By product, the combined company is still oil-majority by revenue even though it is gas-majority by volume, because Coterra’s Marcellus gas realizes a low price: of ~US$18.4 billion of pro-forma oil, gas & NGL sales, oil was ~68%, natural gas ~19% and NGLs ~13%. By asset, the Delaware Basin leads, with the Marcellus the largest gas contributor.

Figure 2. Pro-forma FY2025 upstream revenue by product

Figure data: Devon/Coterra joint proxy statement ; combined oil, gas & NGL sales US$18,399 m (Devon US$11,223 m + Coterra US$7,176 m), split by the two companies’ disclosed oil/gas/NGL sales (oil ~US$12.6 bn, gas ~US$3.5 bn, NGL ~US$2.3 bn).

Figure 3. Approximate production by core area (pro-forma FY2025)

Figure data: this analysis, from Devon FY2025 10-K basin volumes and joint proxy Coterra totals; area shares are approximate and combine Devon’s Delaware/Anadarko with Coterra’s, pending combined-company segment reporting.

Read together: the merged company’s cash flow is led by Delaware oil but meaningfully balanced by Marcellus gas — a genuine two-commodity business now, where a gas recovery is real upside rather than a rounding error. For a multi-basin producer there is no royalty or by-product carve-out; the honest picture is a by-area one.

2.3 Delaware Basin — the unified oil core

The Delaware Basin, spanning West Texas and southeastern New Mexico, is the combined company’s engine and its point of overlap: both Devon and Coterra held premium, largely-contiguous acreage in the economic core of the play, and the merger stitches them into the single most valuable position in the portfolio (~35–40% of combined output, and the bulk of oil volumes and field cash margin). Devon’s standalone Delaware ran ~182.9 mmboe/yr in Q1 2026 (60% of legacy Devon) at a US$27.8/boe field cash margin; Coterra’s adjacent acreage adds scale and, management argues, the clearest source of the US$1 billion synergy target through shared infrastructure, longer laterals and lower drilling-and-completion costs. This is where the merger’s operational logic is strongest, and where the 2026 capital program is concentrated. The key asset-level risk is price and regional gas takeaway (Waha), not geology.

2.4 Marcellus Shale — the gas engine (new)

The Marcellus Shale in Pennsylvania is Coterra’s flagship contribution and the single biggest change to Devon’s risk profile. It is a premier, low-cost Appalachian dry-gas position — the reason Coterra held ~10.5 tcf of natural-gas reserves and produced ~401.5 bcf/yr of the combined ~584 bcf/yr gas total. Marcellus turns Devon from an oil-leveraged Permian name into a genuine oil-and-gas major with a large, long-life, low-decline gas base — attractive if Henry Hub firms (and as US LNG export demand grows), but a drag while Appalachian gas realizes below US$2/mcf. It also introduces Appalachian basis and takeaway as a new sensitivity and Pennsylvania as a new operating jurisdiction. Because the combined company has not yet reported segment detail, per-well Marcellus economics await its first stand-alone disclosures; the read here is at the reserve and volume level from the proxy.

2.5 Rockies (Williston) & the oil legs

Devon’s Rockies/Williston position (~68.3 mmboe/yr standalone, ~12% of the combined group; oil-weighted, from the 2024 Grayson Mill acquisition) and its high-margin Eagle Ford (~24.1 mmboe/yr, the portfolio’s best per-barrel field cash margin at ~US$40/boe, with premium Gulf Coast access after the April 2025 BPX Blackhawk acreage split) remain the oilier ballast against the gassier combined mix. Together with the Delaware, these are what keep the merged company ~68% oil by revenue despite being gas-majority by volume. The Anadarko Basin (Oklahoma, gas-weighted, developed partly through Devon’s Dow joint development agreement and now enlarged by Coterra’s Anadarko acreage) rounds out the base as long-dated gas optionality at the lowest per-barrel margin.

2.6 Production, reserves & costs (consolidated)

On a pro-forma FY2025 basis the combined company produced ~592.8 mmboe/yr (593 mmboe for the year) — 34% oil, 45% gas, 21% NGL — nearly double Devon’s standalone ~306.6 mmboe/yr. Proved reserves stood at 4,993 mmboe (oil 1,346 MMBbls, gas 14,993 bcf, NGL 1,148 MMBbls), 80% proved-developed — a higher developed share than Devon standalone (76%), reflecting Marcellus’s large developed gas base — implying a proved reserve life of ~8.4 years, modestly better than Devon’s standalone ~7.9 but still the shale reinvestment treadmill. Cost-wise, the two businesses are both low-cost operators (Devon’s field cash margin ~US$25/boe in FY2025; Coterra a low-cost Marcellus gas producer), and management frames the US$1 billion synergy target as further per-unit cost reduction. The nuance a reader should hold: the merger improves scale, diversification and reserve life, but dilutes oil leverage — the combined barrel is worth less than Devon’s standalone oilier barrel at any given oil price, offset by more gas upside.

Figure 4. Production by company and combined (pro-forma FY2025)

Chart source: Devon/Coterra joint proxy statement ; pro-forma FY2025 production of 593 mmboe (~592.8 mmboe/yr combined; Devon 307 mmboe / ~306.6 mmboe/yr, Coterra 286 mmboe / ~286.2 mmboe/yr). Commodity mix shifts gassier post-merger (§2.6) — carried in the prose, not overlaid.

2.7 Peer positioning

The combined company’s peer set is the large-cap US independent E&Ps, now including a gas name to reflect the Marcellus: EOG Resources (EOG), ConocoPhillips (COP), Diamondback Energy (FANG), EQT Corporation (EQT) and Occidental Petroleum (OXY). Every “vs. peers” claim in this analysis — each scorecard star, the cost read, the valuation multiples in Section 7 — uses that set.

Table 3. Quality-metric peer positioning (approximate, mid-2026)

Source: company filings and market data, mid-2026; figures are approximate and should be refreshed at publish — the live upstream peer set is screenable on the Metal Pilot upstream dataset. Net debt/EBITDA(X) on latest reported basis; for a like-for-like Permian pure-play read, the sibling Diamondback (FANG) analysis uses the same nine-dimension scorecard.

Where the combined Devon sits: among the largest US independents by volume, strong on the balance sheet (~1.0× net debt/EBITDAX — low and investment-grade, if no longer the sector’s very lowest after the merger added Coterra’s debt), and more oil-and-gas balanced than any pure-play — but with a gassier mix and shorter oil-reserve life than the oiliest names, and integration still to prove. That profile — top-tier scale and leverage, genuine diversification, a merely-adequate reserve life — is the crux of the scorecard.

3. Financials & balance sheet

Because the merger closed in 2026, there is no multi-year combined earnings history yet; the cleanest read is the pro-forma combination of FY2025 — how the two businesses add up — which the joint proxy provides. On that basis the combined company generated US$24,805 million of revenue and US$3,768 million of net earnings attributable to Devon (US$3.24 diluted EPS on ~1,164 million shares), with a pro-forma EBITDAX of roughly US$12 billion. Free cash flow is not disclosed on a combined basis, but on the components — Devon’s standalone US$3,119 million plus Coterra’s contribution — it is on the order of ~US$5 billion, before the US$1 billion of targeted synergies phase in.

Table 4. Pro-forma combination (FY2025)

Source: Devon/Coterra joint proxy statement , unaudited pro-forma combined statement of operations and reserve disclosures, and both companies’ historical columns. *Each Coterra share converts to 0.70 Devon shares, so Coterra’s ~760 m shares become ~531 m Devon shares; combined weighted-average diluted ~1,164 m. Pro-forma figures assume the merger completed 1 Jan 2025 and are illustrative, not a projection. A multi-year combined series awaits the merged company’s own reporting.

The balance sheet is a genuine strength. At 30 June 2026 the combined company carries ~US$11.9 billion of total debt against ~US$1.0 billion of cash (~US$10.9 billion net), or ~1.0× net debt/EBITDAX — low and comfortably investment-grade among the large independents, though the merger lifted net debt above the pristine pro-forma level as Coterra’s notes consolidated. Devon has moved to refinance/roll Coterra’s notes and maintains ample revolver liquidity. On capital returns, the combined company pays a US$0.32 quarterly dividend (US$1.28 annualised, ~2.8% yield) alongside a share-repurchase authorization exceeding US$5 billion, restoring buybacks that Devon had paused during the merger’s pendency. The stated logic, echoed by both boards, is that the larger, more diversified company should drive higher free cash flow and a lower cost of capital, closing the free-cash-flow-yield discount both names carried to larger peers.

Hedge & treasury posture. Both legacy books carry hedges: Devon had ~30% of 2026 oil and ~35% of 2026 gas hedged (three-way oil collars around a US$59.59 floor / US$71.22 ceiling; Henry Hub gas swaps at US$3.80 plus WAHA basis protection), and Coterra brings its own Appalachian and Anadarko gas hedges. Neither company trades speculatively or applies hedge accounting; the combined book will be managed centrally to protect the dividend and deleveraging path. Post-merger the group’s larger gas weighting makes Henry Hub and regional basis hedging a bigger part of the treasury story than it was for standalone Devon.

Figure 5. Revenue by company and combined (pro-forma FY2025)

Chart source: Devon/Coterra joint proxy statement ; pro-forma combined revenue US$24,805 m (Devon US$17,188 m + Coterra US$7,645 m, less US$28 m reclassifications). Net earnings and EBITDAX are read from Table 4 and §3 rather than overlaid.

4. Management, strategy & corporate structure

4.1 Management & governance

The combined company is led by President & CEO Clay M. Gaspar (Devon’s CEO since 2025), with Thomas E. Jorden — Coterra’s chairman and CEO — as non-executive Chair of an 11-person board split six legacy-Devon (including a lead independent director) and five legacy-Coterra directors, Jorden’s chairmanship capped at two years. The executive committee blends both teams: Shannon E. Young III (Coterra’s CFO) becomes EVP & CFO, while Jeffrey L. Ritenour (Devon’s CFO) moves to EVP & Chief Corporate Development Officer; Michael D. DeShazer (Coterra) runs E&P for Anadarko, Eagle Ford, Marcellus & Rockies and John D. Raines (Devon) runs E&P — Permian; Blake A. Sirgo (Coterra) leads Operations, Robert (Trey) F. Lowe III (Devon) is CTO, with Andrea M. Alexander (Coterra) as Chief Administrative Officer and Adam M. Vela (Coterra) as General Counsel. The governance question a reader should weigh is squarely execution: a first-year CEO and a genuinely split leadership team must integrate two large organizations, relocate the headquarters to Houston, and deliver US$1 billion of synergies — all at once. Every seat named here is a documented executive, not a placeholder.

4.2 Strategy & capital allocation

The strategy is continuity plus scale: the same returns-first framework Devon ran standalone — moderate production growth, capital and operational efficiency, a low reinvestment rate to maximize free cash flow, low leverage, and cash returns — applied to a bigger, more diversified base. The near-term operational agenda has two threads: complete Devon’s US$1 billion business-optimization plan (~US$850 million already captured by end-2025) and capture the US$1 billion of merger synergies (shared Delaware infrastructure, lower drilling-and-completion costs, corporate-cost reduction). Capital allocation prioritizes a competitive fixed dividend, debt reduction, and the resumed >US$5 billion buyback, with the 2026 program weighted to the highest-return Delaware core. The explicit financial goal both boards articulated is to lift free cash flow per share and net asset value per share and to compete better for investor capital as a larger company.

4.3 Ownership & corporate structure

The defining structural event is the company as it now stands: the all-stock merger of equals with Coterra Energy, agreed 1 February 2026, approved by both shareholder bases on 4 May 2026 and closed ~7 May 2026, under which Merger Sub merged into Coterra (now a Devon subsidiary) and each Coterra share converted into 0.70 of a Devon share — leaving legacy Devon holders ~54% and Coterra holders ~46% of the combined company, headquartered in Houston and targeting US$1 billion of sustainable annual synergies. The prior building blocks, all now inside the combined entity, are named: Devon’s Grayson Mill (Williston) acquisition (Q3 2024), the 1 April 2025 BPX Energy Eagle Ford acreage exchange, and the 1 August 2025 buy-in of the remaining Cotton Draw Midstream interest (US$260 million); plus Devon’s strategic minority stakes in WaterBridge (14%), Catalyst Midstream (50%) and Fervo Energy (15%). Coterra contributes its Delaware, Marcellus and Anadarko positions and its own note stack, which Devon has moved to roll into the combined capital structure.

5. ESG & sustainability

The combined company inherits Devon’s target-driven environmental framework — GHG and methane-intensity reduction targets from a 2019 baseline, a net-zero Scope 1 & 2 aspiration, ~US$100 million/year of emissions-reduction capital, and a 90%-plus non-freshwater completions goal in the most active Delaware areas — now applied across a larger, gassier asset base. The gas weighting cuts two ways for ESG: Marcellus dry gas is a lower-carbon-intensity barrel than heavy-oil production and positions the company for LNG-linked demand, but it enlarges the methane-management task across Appalachia and the Permian, precisely as the EPA’s OOOOb/OOOOc methane rules and the IRA methane fee tighten. Governance runs through board committees on safety/operations/resources and environmental/public policy, with the merger adding a fresh integration overlay. The honest limitations carry over: the product is hydrocarbons (structural Scope 3 exposure), and Devon entered the merger with several open EPA air-permit notices of violation (legacy WPX operations in New Mexico and Texas, 2020–2024) still to resolve. Presented even-handedly, the ESG read is above the E&P median on ambition and disclosure, with real regulatory exposure now spread across more basins.

6. Risks

Table 5. Risk register

Source: Devon FY2025 10-K and joint proxy statement risk factors; this analysis. Likelihood/impact are the author’s assessment.

The through-line: the merger reduces some risks (scale, diversification, a still-strong balance sheet) while adding the single biggest new one — integration and synergy delivery — and raising gas-price sensitivity. The combined company’s biggest vulnerability is still a sustained fall in commodity prices, now on both oil and gas; its biggest company-specific unknown is whether US$1 billion of synergies actually lands under a new, blended leadership team; and its most structural constraint remains a ~8-year oil-reserve life. None is a solvency risk; they are the ordinary risks of a well-capitalized price-taker in an integration year.

Figure 6. Risk heat-map

Figure data: this analysis; risks per the register above.

7. Valuation

Valuation as of 7 September 2026, in US dollars. Horizon: spot fair value. Price deck: base WTI US$70/bbl — the representative trailing average snapped to the fixed US$60–100 grid (3-month US$83.06, 6-month US$90.50, 12-month US$75.87, all to end-August 2026 on the U.S. EIA Cushing monthly spot series; the twelve-month window is the representative one because the three- and six-month windows sit entirely inside the March–May 2026 Hormuz spike of US$91.38 / US$100.32 / US$102.13, and the nine months either side of it average US$68.51, so the average is leaned to the lower grid price) — with every grid price run as a scenario (bear US$60 / base US$70 / bull US$80 / deep bull US$90 / extreme bull US$100); the EIA’s August 2026 outlook, which puts Brent at US$87/bbl in 2026 and US$69/bbl in 2027 as the Hormuz disruption unwinds, is carried as a 0%-weight cross-check; no spot deck is carried, so the section does not age with the daily quote. Realisations are the company’s own guided percentages of the benchmark, so all three streams move with their deck: oil at 100% of WTI (third-quarter guidance 98–102%, full-year 98–100%), NGLs at 27.5% of WTI (guidance 25–30%) and gas at 55% of Henry Hub (guidance 50–60%) — at the base deck, oil US$70.00/Bbl, NGL US$19.25/Bbl and gas US$1.65/Mcf. The hedge book is charged once, in the bridge, so no realisation here carries a cash settlement. Discount rate 10%, the E&P convention for a high-decline shale base with a sub-ten-year proved life — the rate the standardized measure is struck at — sensitised 8–12%. Share price US$48.06 (4 September 2026 close), 1,150 m shares, balance sheet as of 30 June 2026, on the combined Devon/Coterra basis.

Devon is valued on the E&P producer archetype, run as a sum-of-the-parts over three claims — the proved developed reserve base, the proved undeveloped tranche the reserve report funds, and the Delaware acreage bought at the June 2026 federal lease sale. The method behind the numbers is set out in the How to Value Commodity Stocks guide; this section applies it to the merged company. The headline is a deck-to-value map, not a single number: the blended fair value is US$33.73/share at the US$70 base price, US$23.62 at US$60 and US$43.92 at US$80, and each US$10/bbl of WTI is worth about US$5.5 of NAV/share — the deck sensitivity in Table 11 lets a reader run the model at any oil price they hold. The tiers frame the structure: the producing base plus the whole bridge is worth US$12.54/share, the booked undeveloped tranche another US$5.33, and the new acreage US$2.26 at what Devon paid for it three months ago. The section sets the current US$48.06 price against that map only in §7.6, where the rating and the flip prices are published.

7.1 Method selection

Devon is a producer, so the blend is the E&P-producer default set out in the valuation guide linked above — NAV/DCF 45% / EV/EBITDA 30% / a reserve read 25% — carried without deviation. The third slice takes the guide’s reserve anchor on proved (1P) reserves, the only category an SEC filer publishes; the anchor is written for 2P, so the denominator is narrower than the convention and the method reads low. All three run on the combined basis: the reserves and the standardized measure are the pro-forma figures the merger proxy publishes for 31 December 2025, and the forward metrics are struck on the third-quarter 2026 guidance run-rate, the first fully combined quarter the company has guided.

Table 6. Valuation method selection

Source: method-to-archetype mapping, anchors and the default weight set per The Commodity Investor, Part 11: How to Value Commodity Stocks , “The archetype is the unit of analysis” and “The valuation toolkit”; the E&P-producer default carried without deviation. Archetype in Section 1; target multiples derived in §7.3 from the archetype anchors, not from the Section 2.7 peer set, which stays a quality comparator. Input families: intrinsic 45% (single method), cash-flow 30%, asset & capacity 25%, transaction 0% — all inside the family caps.

7.2 Net asset value

Vehicle map. After the 7 May 2026 close, Devon holds the combined portfolio directly: there is no listed subsidiary, no consolidated joint venture with a third-party interest ahead of the common equity, and — at 30 June 2026 — no minority-interest caption on the balance sheet at all. The map is therefore short, and nothing inside one line can reappear as another.

Table 7. Vehicle map

Source: this analysis; combined reserves, the standardized measure and the pro-forma balance sheet per the Devon/Coterra joint proxy statement , pp.158–165; the New Mexico acquisition, the balance sheet and the debt position per the Devon Q2 2026 results , 4 August 2026; investments and balance-sheet detail per stockanalysis.com , 30 June 2026.

Tax basis and asset-retirement obligations. The reserve base is carried at the SEC after-tax standardized measure, so tax is inside the figure by construction (the disclosure’s own schedule) and the combined US$8.9 bn of deferred tax liabilities sit behind it — neither charged nor credited again. That schedule runs at 17.1% of pre-tax future net revenue (US$11,645 m against US$68,279 m); an incremental dollar of oil price is taxed at the 23% blended statutory rate the merger proxy states, and that is the rate the deck adjustment uses. Future dismantlement and abandonment are already inside the reserve report’s development costs (ASC 932), so the bridge’s reclamation line prints in rows and names the US$1,169 m obligation it corresponds to; the relative legs in §7.3 and §7.4 still deduct it, because neither EBITDA nor a reserve multiple carries it.

Stage risk (n/a) and synergies (not modelled). No asset in the model is pre-production. The proved undeveloped tranche is a booked SEC category that must be developed within five years and whose share of the US$9,400 m of future development costs is already charged inside the standardized measure, so it takes a 1.00 risk weight; the New Mexico acreage is carried at an arm’s-length cash price paid three months before the valuation date, so it takes 1.00 too. Neither the target P/NAV nor the discount rate carries a second charge. The US$1.0 bn of annual pre-tax run-rate synergies the company targets by year-end 2027 are deliberately not in the model — they are a management target, not a disclosed line — and the omission is a stated understatement: capitalised on the same after-tax annuity as corporate overhead they would be worth US$5,208 m, or US$4.53/share, more than the whole capitalised-G&A charge the bridge takes.

The per-asset NPV build. Every NPV the model carries is built here first, one block per tranche, so the arithmetic arrives before the answer. The two reserve blocks are the combined company’s own disclosed figure apportioned on the proxy’s own filed volumes and prices and moved to the deck; the acreage block is a mark, not a model.

Table 8. Per-asset NPV build — base case (US$70/bbl WTI, 100% realized, 10%)

Notes to Table 8

1. The proxy publishes the pro-forma standardized measure only in total, so each of its cost lines is apportioned on a filed quantity: revenue on the reserve volumes valued at the price set below, production costs on the boe share, income tax on pre-tax net revenue. The apportionment is exact by construction: 27,020 + 5,342 = US$32,362 m. The price set is itself checked: the guided realisation percentages applied to the 2025 benchmark averages — oil US$65.46/Bbl (100% of WTI), gas US$1.94/Mcf (55% of Henry Hub US$3.53) and NGL US$18.00/Bbl (27.5% of WTI) — reproduce the filed US$138,027 m of future cash inflows to 0.10% on the filed reserve volumes, which is what one expects since the SEC deck is that same twelve-month average.
2. The severance rate is the company’s own guidance — production and property taxes at 6.5–7.5% of upstream sales, taken at the 7.0% midpoint — and it reconciles to the second quarter’s actual US$376 m of production and property taxes against US$5,106 m of oil, gas and NGL sales (7.4%).
3. The proxy does not footnote the abandonment component of its US$9,400 m of future development costs, so the balance sheet’s US$1,169 m asset-retirement obligation at 30 June 2026 stands in for it, split on boe volumes; the remaining US$8,231 m of drilling capital is charged wholly to the undeveloped tranche, which is what it funds.
4. One discount ratio, both tranches. The disclosure gives a single US$24,272 m discount against US$56,634 m of undiscounted after-tax cash flow, and no split by category, so both tranches carry it. The developed base produces earlier and the undeveloped later, so the split understates the developed tranche and overstates the undeveloped one; the total is exact, and the same ratio implies a flat-equivalent life of 11.8 years — the annuity that reproduces 0.5714 at 10% — which is the profile the rate rows of Figure 8 move both blocks on.
5. The deck term: the barrels whose realisation moves one-for-one with WTI — developed oil 997 mmbbl plus 27.5% of 886 mmbbl of developed NGL = 1,241 mmbbl (undeveloped 349 + 27.5% × 262 = 421) × (1 − 7.0% severance) × (1 − 23% statutory tax) × the 0.5714 discount ratio. Gas is held at 55% of the US$3.00 Henry Hub base across the WTI grid, because it tracks its own benchmark; NGLs move with crude at the guided percentage. Half the reserve base is gas by volume, which is what keeps the oil slope below a Permian pure-play’s.
6. The acreage is priced at what a competitive federal lease sale charged Devon for it in June 2026, which is the strongest kind of mark: a dated, arm’s-length, cash transaction in the same rock. US$2.6 bn over ~400 locations is US$6.5 m per location, against an 87.5% net revenue interest.
7. Devon publishes no total undrilled-location count, so the row that would price the rest of the inventory cannot be built from disclosure and is printed n/d rather than proxied. It is bounded, and the bound is large: the merger purchase-price allocation records US$14,099 m of Coterra unproved and under-development property at merger-date fair value — US$12.26/share for the acquired half alone, before any of Devon’s own legacy acreage. Direction: net asset value understated. The company’s own investor presentation, with a location count and a type curve, is the document that would let the row be built.

Source: the Devon/Coterra joint proxy statement (pp.158–165, the pro-forma combined reserves, standardized measure and balance sheet) and the Devon Q2 2026 results of 4 August 2026. Filed marks a figure printed in the filing, Derived the arithmetic of rows above it, Input a parameter of this section. The value column is headed Value rather than US$m because a build that multiplies heterogeneous terms cannot hold one unit; the unit sits in the line item, and only the = rows are US$m. The one relationship the table cannot express is the parametric form the sensitivity grid runs across the deck and the rate: proved(WTI, r) = [32,362 + 680.0 × (WTI − 65.46)] × AF(r, 11.8) ÷ AF(10%, 11.8).

Table 9. Per-asset model — base case (US$70/bbl WTI, 10%)

Source: this analysis, from the Devon/Coterra joint proxy statement and the Q2 2026 results . Every NPV in the last column reproduces from its block in Table 8; this table adds the reserve, cost, capital, tax and discounting inputs behind those figures. One discount-rate treatment: the two reserve blocks and the capitalised overhead re-discount on the proxy’s own timing, the acreage mark is held, and the grid’s notes say so.

Table 10. NAV build-up and equity bridge (base case — US$70/bbl WTI, 10%)

Source: this analysis; the reserve and pro-forma balance-sheet lines per the Devon/Coterra joint proxy statement ; debt, cash and the acreage per the Devon Q2 2026 results ; the 30 June 2026 working-capital, lease and investment lines and the share count per stockanalysis.com , read 7 September 2026. Bridge lines in the standard order, each printed even where empty on one of the five value-column states. The tiers sum to the published NAV/share: producing US$12.54 + development US$5.33 + resource US$2.26 = US$20.13 — and the producing tier alone sits 74% below the US$48.06 price, before either undeveloped tier is counted. Values computed on unrounded inputs, printed to whole US$m and two decimals per share.

Figure 7. Sum-of-the-parts NAV build-up

Figure data: Table 10. Equity net asset value of US$23,146 m equates to US$20.13 per share; the producing tier alone is US$12.54. “Hedge, wkg cap. & inv.” nets the hedge mark (+135) and investments at carrying value (+992) against working capital (−1,497).

Figure 8. NAV/share sensitivity — WTI price × discount rate

Notes to Figure 8

1. Checksum — the bear column (US$60) at the 10% base rate: proved developed = 27,020 + 507.7 × (60 − 65.46) = US$24,248 m; proved undeveloped = 5,342 + 172.3 × (−5.46) = US$4,402 m; plus the US$2,600 m acreage mark = US$31,250 m of enterprise NAV, less net debt 10,379, capitalised G&A 4,154 and working capital 1,497, plus the US$153 m hedge mark at that deck and investments 992 = US$16,365 m ÷ 1,150.0 m = US$14.23.
2. Rate rows — they move the two reserve blocks and the capitalised G&A, on the 11.8-year flat-equivalent profile the standardized measure’s own discount ratio implies (×1.1049 at 8%, ×0.9099 at 12%); the New Mexico acreage mark, net debt, working capital, the investments and the hedge mark are held down each column, the last because an option’s intrinsic value does not discount.
3. Cost — a +10% shock to the guided lease-operating and gathering costs (US$8.20/boe, US$503 m/yr) takes NAV/share to US$17.85 (−11.3%); a +10% WTI move to US$77 lifts it to US$24.05 (+19.5%), and with a 5% cost lag applied to that price move, US$22.91 (+13.8%). The cost line bites harder here than at a Permian pure-play, because half the reserve base is gas earning a Waha-discounted price.
4. FX — n/a, Devon reports and trades in US dollars.
5. Stage risk — n/a, no asset in the model is pre-production; the proved undeveloped tranche is a booked SEC category and the acreage is a cash mark, both at 1.00, so there is no risked tranche to step down a band.
6. Schedule slip — n/a for the reserve rows, whose capital sits inside the standardized measure’s own five-year schedule. The New Mexico acreage is 6.8% of enterprise NAV, below the 10% trigger; carried at cost, it does not discount with time in this model.

Figure data: this analysis’ model (Tables 8–10), every cell recomputed at that column’s WTI price and that row’s rate, never scaled from the base cell. Price columns are the fixed crude-oil grid, grid version 2026-09 (US$60–100); base case US$70 at 10%. A one-step (US$10/bbl) WTI move shifts NAV/share by US$5.54, or ~28%; the deck sensitivity is tabulated in Table 11.

Deck sensitivity — what one US$10/bbl step of WTI is worth. The grid above holds the recomputed values at each grid price; this table names the slope between them, so a reader who holds a different oil view can move the valuation themselves. Both reserve rows enter on the disclosure’s own linear price term, but the hedge mark does not: the collars are inside their strikes at US$60–70 and short of the cap above, so every line below carries a kink where the ceiling binds.

Table 11. Deck sensitivity — value per US$10/bbl step of WTI (US$/share unless stated; base rate, target multiples held)

Source: this analysis, Tables 8–10 and 18. % of base is each line’s per-step move divided by its own base-price value — a leverage read, and the reason free cash flow is the most oil-sensitive line on the page: at US$5.8 bn of annual capital against US$12.3 bn of EBITDA, the residual is what moves. Linear over is the WTI range on which the slope holds: ¹ the slope is measured between the US$70 and US$80 columns and flattens above US$73, where the oil collars’ US$72–73 ceilings bind and the hedge mark turns sharply negative; ² the reserve leg prices a fixed booked volume at a fixed dollar per barrel, so its only movement is the hedge mark inside the bridge — which is why its slope is negative; ³ FCF/share crosses zero at ~US$43.43/bbl, well below the grid; ⁴ the scenario blend steps 10.10 → 10.20 → 11.14 → 12.21 because the rate and the three target multiples move with the column. Every step is the difference between two recomputed grid prices of Figure 8, never a scaled figure. Forward EBITDA moves US$2,239 m per step. How to use it: start from the base-price values (NAV/share US$20.13, blended fair value US$33.73) and add or subtract the per-step figure for every US$10/bbl of WTI away from US$70 — a US$85 flat deck gives a NAV/share of ~US$28.4 and a held-multiple blend of ~US$42.1; for a reading that also lets the multiples move with the cycle, use the scenario columns of Table 18.

P/NAV ladder (unweighted). The NAV restated as a price map, straight off Figure 8’s base-rate row: for each of the five fixed P/NAV levels this series uses for producers and E&Ps, the share price it implies at every grid price — NAV/share at the deck × level, the base rate held. Read down a column for the deck you hold, across a row for the multiple you would pay; where today’s quote sits on the map is said once, by the market-implied deck in §7.5.

Table 12. P/NAV ladder — share price implied by each P/NAV level at each grid price (US$/share)

Source: this analysis, solved on Tables 8–10: each cell is the Figure 8 base-rate NAV/share at that column’s WTI price (14.23 / 20.13 / 25.67 / 31.01 / 36.29) × the row’s P/NAV level. The levels are fixed for the series (0.50× to 1.50× in quarter steps), so two producers can be read column-for-column; Devon’s 0.94× target, derived in §7.3, reads US$18.92 at the base price, US$13.38 at US$60 and US$24.13 at US$80, between the 0.75× and 1.00× levels. Unweighted: it translates a multiple and a deck into a share price without reference to today’s quote, so the map stays readable as both move — parity at the base price is US$20.13, and the top of the map, 1.50× at US$100 oil, is US$54.43.

7.3 Relative valuation

At US$48.06 and 1,150 million shares, Devon’s market capitalisation is ~US$55.3 billion and enterprise value ~US$65.6 billion. This section values Devon standalone: each target multiple is the fixed anchor for the E&P-producer archetype moved by the signed drivers this post’s own scorecard has already scored. No peer multiples are tabulated here — reading Devon against the Section 2.7 peer set on observed multiples is the job of the sector comparison , on one shared basis. Forward metrics are struck on the next twelve months at the Q3 2026 guidance run-rate — the first fully combined quarter Devon has guided, and the only guided period that reflects the merged company; the FY2026 guidance year blends four pre-merger months and understates the run-rate by about a fifth. The US$70 base sits 11.5% below WTI’s five-year average of US$79.08 (September 2021–August 2026, on the EIA monthly series) — inside the ±25% band that marks a cycle extreme — so the subject is treated as near mid-cycle, and the scenarios in §7.6 flex the deck and the multiples together.

Table 13. Target-multiple driver line (one line, applied to every multiple)

Source: this analysis; each term is tied to one scored dimension, capped at ±10%, and no fact is charged under two labels. The driver set is the standard one — asset quality, cost position, reserves and replacement, balance sheet and capital allocation, jurisdiction; growth, management and ESG (Dims 4, 7 and 9) sit outside it and are scored in Section 9, which is why the integration question appears once, under capital allocation, and not again. The one line is applied, unchanged, to every anchor:

Target P/NAV = 0.80× anchor × 1.18 = 0.944 → 0.94× · Target EV/EBITDA = 5.0× anchor × 1.18 = 5.900 → 5.9× · Target EV per proved boe = US$10.00 anchor × 1.18 = US$11.800 → US$11.80. Rounded figures are the ones used in every table below.

Table 14. Forward EBITDA build — the next twelve months at the Q3 2026 guidance run-rate and the base deck

Source: this analysis; volumes and capital per the Devon Q2 2026 results of 4 August 2026; realisations and unit costs per the same release; the product mix, the G&A line, the financing-cost line and the depreciation rate per the Devon/Coterra joint proxy statement pro-forma statement of operations. “Forward” is the next twelve months, struck on the Q3 2026 guidance run-rate rather than on the FY2026 guidance year, because FY2026 carries four pre-merger months and is not the combined company’s twelve months; every trailing line in the free-cash-flow memo sits on FY2025 pro-forma, the latest full reported basis for the combined company. Reconciliation: run at the second quarter’s own filed volumes and unhedged realisations — 45.8 mmbbl of oil at US$95.10, 28.6 mmbbl of NGL at US$22.70 and 295.9 Bcf of gas at US$0.35 — this build gives US$5,105 m against the US$5,106 m of oil, gas and NGL sales the company reported, a 0.02% difference. The realised prices including cash settlements (oil US$88.09) are deliberately not used: the hedge is charged once, in the bridge. Cost-basis note: the NAV rows use the reserve report’s own production costs with gathering netted inside its price line, while this build states each guided cost line separately — a definition, not a gap.

Table 15. Relative valuation — implied value per share (base case)

Source: this analysis; archetype anchors (E&P: P/NAV 0.80×, EV/EBITDA 5.0×) per the valuation guide linked in §7, “The valuation toolkit”. The implied EV crosses the same claims as the NAV bridge — plus the US$1,169 m asset-retirement obligation, which the reserve report carries inside its development costs but EBITDA does not — and omits only the capitalised corporate G&A, which is already deducted inside the EBITDA build. The hedge mark is the same per-column intrinsic figure the NAV bridge carries. Values computed on unrounded inputs. To run the same reserve and cash-flow multiples across every North American upstream name, screen the sector on Metal Pilot.

The two reads do not agree, and the gap is the valuation: US$52.99 against US$18.92, a factor of 2.8. It is the difference between capitalising one year of cash flow and discounting a finite, audited reserve book. The multiple sees US$12.3 billion of EBITDA and applies a mid-cycle anchor; the NAV sees 4,993 mmboe of proved reserves that run 8.2 years at the guided rate, charges the US$9.4 billion of future development capital the reserve report schedules, and stops. Devon spends US$5.8 billion a year — 47% of that EBITDA — to hold production flat, and the multiple charges none of it. That is the standard trap in valuing a high-decline shale producer on EBITDA, and it is why the NAV anchors the blend at 45%.

7.4 Further weighted methods — EV per proved boe

The third weighted read prices the booked reserve base at the archetype’s reserve anchor moved by the same driver line, and bridges it on the same claims.

Table 16. EV per proved boe build — base case

Source: this analysis; reserves per the Devon/Coterra joint proxy statement p.164; the bridge lines as Table 10. Basis note: the archetype’s reserve anchor is written for 2P reserves and this denominator is SEC proved (1P), the only category the filer publishes — so the method reads low by whatever the probable tranche is worth, and the unbooked inventory it cannot see is n/d in Table 8.

The method lands at US$37.26, between the NAV and the cash-flow read and 10% above the blend. It is the leg that most nearly agrees with the market: at US$48.06 the shares carry US$13.15 per proved boe against that US$11.80 target — an 11% premium, the narrowest of the three gaps, and a reminder that on reserves alone Devon is not obviously expensive. The disagreement lives in the NAV, where the same barrels are charged their development capital and stopped at the end of the book.

7.5 Cross-checks (unweighted)

Nine diagnostics locate the blend; none carries weight.

Table 17. Cross-checks — reported, reconciled, never weighted

Source: this analysis; the market-implied and flip prices solved on the Tables 8–16 model; reserve, capital and roll-forward figures per the Devon/Coterra joint proxy statement and the Q2 2026 results ; WTI history per the U.S. EIA Cushing monthly series, five-year window September 2021–August 2026; the 2027 Brent forecast per the EIA Short-Term Energy Outlook , 11 August 2026; the trailing multiple and dividend-yield series, quarterly capital, consensus and analyst count per stockanalysis.com , read 7 September 2026 on the 4 September close.

7.6 Scenarios & fair value

Every weighted method is re-run in every column of the WTI grid — the same five grid prices as Figure 8 and Table 11, so the whole section reads on one price axis. Each column is its own world, and Table 18 lists what changes in it above the values it produces: the deck moves one step at a time; because the base sits inside 25% of crude’s five-year average (§7.3) the subject is near mid-cycle, so the three target multiples step ×0.90 / — / ×1.10 / ×1.20 / ×1.30 with the deck; the discount rate steps out to 12% on the downside and holds at the 10% convention on the upside — a rate below the industry’s own floor would price an 8.2-year shale book as safer than the industry treats it at any price. The last memo row is the same blend with the multiples held at their targets, which is the linear version a reader can reproduce from Table 11.

Table 18. Scenarios & fair value — inputs, value per method and the blend by grid price (US$/share)

Source: this analysis; weights per §7.1, scenario names by offset from the base price — the base sits on the grid’s second column, so the scenario names read Bear through Extreme Bull. Base blend on a calculator: 0.45 × 18.9193 + 0.30 × 52.9910 + 0.25 × 37.2568 = 8.5137 + 15.8973 + 9.3142 = US$33.73. The unrounded method values are printed here because the blend is computed on them; the two-decimal figures in the rows above give the same US$33.73. Inputs behind the rows, by column: the flexed targets 0.85× · 5.31× · US$10.62 / 0.94× · 5.9× · US$11.80 / 1.03× · 6.49× · US$12.98 / 1.13× · 7.08× · US$14.16 / 1.22× · 7.67× · US$15.34; forward EBITDA US$10,110 m / 12,349 m / 14,588 m / 16,826 m / 19,065 m; cash tax US$442 m / 800 m / 1,158 m / 1,516 m / 1,875 m. Risk weights are 1.00 in every column — nothing in the model is pre-production. The hedge mark is re-struck in every column from the disclosed strikes: +US$153 m / +US$135 m / −US$294 m / −US$949 m / −US$1,681 m. That series is the reason the reserve leg’s value falls as crude rises: the multiple and the booked volume are both fixed, so the only thing moving inside its bridge is the hedge, and Devon’s oil collars are capped at US$72–73. Illustrative scenarios, not forecasts.

Figure 9. Value per share by method and scenario

Source: Table 18; each cell recomputed at its column’s deck, rate and multiple flex, never scaled; data-level ranked 0–9 across the whole grid. The three methods fan rather than cluster, and the fan is the finding: the cash-flow read carries the steepest deck leverage because nothing stands between EBITDA and the equity except fixed claims; the reserve read is nearly flat, because a fixed dollar per booked barrel does not care what the barrel sells for; and the NAV sits lowest throughout, because it alone charges the development capital and terminates at the end of the book. Current share price US$48.06 (4 Sep 2026); market-implied deck ~US$96.30/bbl WTI. The bracketed figure under each value is its change against the same row’s base-case value.

Conclusion. The blended base-case fair value is US$33.73, inside a US$23.62 (Bear, US$60) – US$67.28 (Extreme Bull, US$100) range, against a US$48.06 price — an implied −29.8%, Modestly overvalued, published as Modestly overvalued “(wide band)” because the bear-column blend sits 51% below the price. That read sits on the boundary of its band, and the flip price says so precisely: the base blend crosses down into Overvalued at a flat ~US$69.86/bbl WTI, 0.2% below the base deck, and up into Fairly valued only at ~US$87.28 (+24.7%). A reader who prefers a US$65 flat deck is looking at an Overvalued name; one who prefers US$80 is looking at a fairly valued one. At the base price the forward-year free cash flow of US$5,149 m after all capital is a 9.3% yield on the US$55.3 bn market capitalisation — a genuinely strong number, and the reason the cash-flow leg is the highest of the three.

The three methods do not cluster, and the spread is explained rather than averaged away: the EV/EBITDA read (US$52.99) is 2.8× the net asset value (US$18.92) because a whole-company multiple capitalises one guided run-rate and charges neither the US$9.4 billion of scheduled development capital nor the fact that the booked base runs 8.2 years. The net asset value anchors the blend for that reason, and the reserve read sits between them, closest to the market. The framing that matters is not that Devon is a poor business — the merger genuinely improved it: more scale, a longer-life gas leg, ~1.0× leverage, no maturities until 2027, a 2.8× recycle ratio, 117% organic reserve replacement and a first combined quarter that beat its own guidance on volumes, cost and capital. It is what the price requires: the producing base plus the whole bridge is worth US$12.54/share, the booked undeveloped tranche another US$5.33, the new Delaware acreage US$2.26 at cost — and a buyer at US$48.06 is paying a US$28 premium to all three for WTI at ~US$96 held flat in perpetuity, at a moment when the EIA expects Brent back at US$69 in 2027.

Two things could close much of that gap honestly, and both are named rather than modelled because neither is a disclosed line this section can price: the US$1.0 billion synergy programme, worth about US$4.53/share capitalised, and the drilling inventory beyond proved reserves — which the merger’s own purchase-price allocation values at US$14.1 billion for the acquired Coterra half alone, US$12.26/share, before any of Devon’s legacy acreage. Add either in full and the read moves a band. Neither is in the reserve report, which is audited and dated, and a valuation that put both in at face value would be underwriting management’s plan rather than testing it. The Street’s US$59.54 target does underwrite them. This is an analytical read of price against value, not a recommendation.

Assumptions box: valuation date 7 September 2026; balance sheet as of 30 June 2026 for net debt, the hedge book, working capital, investments, the asset-retirement obligation and shares, 31 December 2025 pro-forma for the reserves and the standardized measure; horizon spot fair value. USD throughout — trading currency = model currency, no FX. Price decks: base WTI US$70/bbl (the 12-month trailing average of US$75.87 to end-August 2026, leaned to the lower price of the fixed grid because the window carries the March–May 2026 Hormuz spike; 3-month US$83.06, 6-month US$90.50), run across the US$60–100 grid, version 2026-09, with the base on the grid’s second column; the EIA’s US$69/bbl Brent forecast for 2027 as a 0% cross-check — no spot deck is carried. Realisations are the company’s guided percentages — oil 100% of WTI, NGLs 27.5% of WTI, gas 55% of Henry Hub at a US$3.00/MMBtu base — so oil and NGLs move with the grid and gas is held; constant-price, unescalated deck and costs, matching the SEC reserve convention, so the 10% rate is real. Discount rate 10% — the E&P convention for a high-decline shale base with an 8.2-year proved life, and the rate the standardized measure is struck at — sensitised 8–12% on the reserve rows and the capitalised overhead; no jurisdiction premium (Dim 8 ★★★★★, 100% United States, so the band is +0%). Share basis 1,150.0 m (basic and diluted within 1%); values per share to two decimals, multiples to two significant figures, on unrounded inputs. Cycle: base 11.5% below the five-year average of US$79.08 (Sep 2021–Aug 2026), inside ±25%, so deck and multiples flex together across the scenario columns; anchors E&P P/NAV 0.80×, EV/EBITDA 5.0×, EV per reserve boe US$10.00 per the valuation guide linked in §7, one driver line (×1.18); metric basis forward on the Q3 2026 guidance run-rate — the next twelve months of the combined company, not the FY2026 guidance year, which blends four pre-merger months; every forward cost, realisation and tax line is a guidance midpoint rather than an estimate; EBITDA before all capital and after G&A; net debt on the company’s own definition, leases excluded; P/NAV form equity (market cap ÷ equity NAV); no peer multiples enter this section. Method weights NAV 45% / EV/EBITDA 30% / EV per proved boe 25% — the E&P default, no deviation. NAV provenance: the pro-forma combined after-tax standardized measure from the merger proxy, apportioned on its own volumes and a price set built from the guided realisation percentages that reproduces the filed future cash inflows to 0.10%, and moved to the deck on a term built from the combined oil and NGL volumes, the guided severance rate and the disclosed discount ratio; the New Mexico acreage at the June 2026 consideration; the hedge book marked at intrinsic value from the disclosed strikes in every column; tax basis the SEC schedule (basis 3), pools inside it; abandonment inside the reserve report. Primary value yardstick P/NAV (equity form). Stage-risk placement n/a — no pre-production asset; every row at 1.00. Known data gaps: (1) drilling inventory beyond proved reserves n/d apart from the 400 acquired New Mexico locations — Devon publishes no total location count, type curve or inventory life, so the row cannot be built; net asset value understated, bounded at US$14,099 m (US$12.26/share) by the Coterra unproved property recorded in the merger purchase-price allocation, and closed by the company’s investor presentation; (2) the short-term derivative liability is not separately captioned on the balance sheet, so it remains inside other current liabilities while the hedge line carries the computed intrinsic mark — the overlap understates net asset value by under US$0.15/share, closed by the Q2 2026 Form 10-Q’s fair-value note; (3) the maintenance/growth capital split n/d — the whole US$5.8 bn annualised programme is treated as maintenance, which understates free cash flow before growth capital; (4) the reserve report’s own price deck is not published by category in the proxy, so the price set is reconstructed from the guided realisation percentages and reconciled to the filed future cash inflows (0.10%); (5) the US$1.0 bn synergy programme is deliberately excluded from every weighted method and reported at 0% in §7.5. Gaps (1) and (5) both point the same way — the model is conservative — and are the reason the read sits on its band boundary rather than inside it. To run the same net asset value and multiples across every North American upstream name, screen the sector on Metal Pilot.

8. Near-term catalysts (1–3 years)

The combined company’s forward upside over the next two to three years is dominated by turning the merger into per-share value — realized synergies, deleveraging and restored returns — on top of a firmer commodity tape. The most material positives are structural, not speculative.

Table 19. Near-term catalysts (1–3 years)

Source: Devon/Coterra joint proxy statement , Devon FY2025 10-K and Q1 2026 10-Q ; timing reflects company guidance and is not guaranteed.

The common thread is scale, synergies and self-funded returns: the combined company does not need higher prices to integrate, capture savings or fund the dividend — a firmer oil-and-gas tape simply accelerates all three. The swing factor is execution: landing US$1 billion of synergies without losing the cost and capital discipline that both companies were valued for.

9. Rating & verdict

The combined Devon is scored on the Metal Pilot Company Scorecard — the same nine dimensions, on the same ★1–5 scale, that every US upstream name in the series is scored on, so the peers are directly comparable. Each star is relative to the large-cap US independent E&P peer set (Section 2.7) and substantiated below.

Table 20. The combined Devon Energy scorecard

Source: the Metal Pilot Company Scorecard; evidence in Sections 2–7. Peer basis: large-cap US independent E&Ps (Section 2.7). Composite is the archetype-weighted average per the producer/operator weighting (dimensions 1/2/3/5/6 at 15% each, dimensions 4/7/8/9 at 6.25% each).

Weighted average = (0.60 + 0.60 + 0.60 + 0.60 + 0.60) + (0.25 + 0.25 + 0.3125 + 0.25) = 4.06/5 → rounds to the published ★★★★, Solid.

The two-axis verdict. Quality Solid (★★★★) × Value Modestly overvalued (wide band) → a top-tier operator priced ahead of its reserves: watch for a better entry. The merger lifts the quality axis a notch above standalone Devon — bigger, more diversified, a longer-life reserve base and still a strong, investment-grade balance sheet (the lone ★★★★★ is jurisdiction) — held back from High quality by a gassier, less oil-levered mix, a still-adequate reserve life and genuine integration risk. The value axis is the dated layer, and it has moved with the oil tape rather than with the business: on the base deck of US$70/bbl the blended fair value is US$33.73 against a US$48.06 price, an implied −29.8%, and the market-implied read says the shares discount a flat WTI of about US$96.30 — 22% above crude’s own five-year average and far above the EIA’s US$69/bbl Brent forecast for 2027. The target multiples the module argued are a premium to their archetype anchors, not a discount (P/NAV 0.94× against a 0.80× anchor, EV/EBITDA 5.9× against 5.0×, EV per proved boe US$11.80 against US$10.00) — the quality is credited, and the price still runs ahead of it. Two omissions cut the other way and are named rather than modelled: the US$1 billion synergy programme (≈US$4.53/share capitalised) and the drilling inventory beyond proved reserves, which the merger’s own purchase-price allocation values at US$14.1 billion — US$12.26/share — for the acquired Coterra half alone. The read carries the wide-band qualifier because the bear column blends 51% below the price, and it sits on its band boundary: a flat US$69.86/bbl deck, 0.2% below the base, tips it into Overvalued, and US$87.28 tips it into Fairly valued. This is an analytical read, not a recommendation; operating figures are pro-forma, refined by the combined company’s first results (reported 4 August 2026), on current market data.

For how Devon compares head-to-head with the four other largest US upstream oil producers — EOG, Occidental, Diamondback and Ovintiv — on one shared construction, see US Large-Cap Upstream Oil Producers Compared (2026) .

To go from this single-name view to the whole peer group — screening every US upstream E&P on production, cost, reserve life, net debt and free-cash-flow yield — explore Metal Pilot.

10. Sources, methodology & disclaimer

10.1 Sources, methodology & data vintage

This is an analysis of the combined Devon Energy following its merger of equals with Coterra Energy (closed ~7 May 2026), on a pro-forma basis. The combined financials, reserves, production, share count and standardized measure are from the Devon/Coterra joint proxy statement/prospectus (2026) — its unaudited pro-forma combined statements, prepared as if the merger completed 1 January 2025, together with both companies’ historical columns. Devon’s per-basin operating detail (production, netbacks, costs, hedges, management, ESG) is from Devon’s FY2025 10-K and Q1 2026 10-Q; the combined company’s first quarter of realisations, unit costs, volumes, hedge positions and guidance is from the Q2 2026 results of 4 August 2026 and their supplemental tables. Three documents that would strengthen the next run are not in the verification set and are named here so they can be requested: Devon’s and Coterra’s FY2025 Forms 10-K (the audited statements and the two reserve reports the pro-forma combines, where the proxy carries only the combined result) and the Q2 2026 Form 10-Q (the derivative fair-value note, whose short-term liability is the one line Section 7 still cannot separate). Market data — share price, market cap, enterprise value, net debt, share count and analyst targets — is as of the 4 September 2026 close (US$48.06, ~1,150 million shares, 27-analyst consensus target US$59.54) per stockanalysis.com , read 7 September 2026. Enterprise value, EV/EBITDA and free-cash-flow yield are derived from those inputs. The Section 7 valuation is built on the pro-forma combined after-tax standardized measure at 31 December 2025 from the joint proxy, apportioned into its developed and undeveloped tranches on the proxy’s own volumes and prices and moved to the stated deck, plus the June 2026 New Mexico federal acreage at the consideration paid; forward metrics are struck on the Q3 2026 guidance run-rate, the first fully combined quarter the company has guided. The price deck is the fixed US$60–100 WTI grid on the U.S. EIA Cushing monthly series, with the EIA Short-Term Energy Outlook of 11 August 2026 as the unweighted forecast cross-check. Section 7’s data-gap register names five inputs the source set does not carry; the two that would most improve the valuation are the Q2 2026 Form 10-Q (the derivative fair values, absent from the release) and the company’s investor presentation (the drilling-inventory location count). The US$1.0 billion synergy programme is deliberately excluded from every weighted method and reported unweighted. Peer figures in Section 2.7 are approximate and flagged for refresh. The asset map is omitted deliberately — a five-area onshore US footprint does not render as a legible proportional-symbol map. Operating figures remain on the pro-forma year-end-2025 reserve basis, refined by the combined company’s first results; market data as of the 4 September 2026 close. Data as of 7 September 2026; refreshed on the combined company’s next quarterly report. Re-run log — 7 September 2026: Section 7 rebuilt on the reserve-based method and the market layer rolled to the 4 September close (net asset value US$19.59, blend US$30.18, Overvalued); re-run the same day against the Q2 2026 supplemental tables, which replaced every estimated realisation, unit cost, volume and hedge input with the company’s own guided figures — net asset value US$20.13, blended fair value US$33.73, value read Modestly overvalued (wide band). Provenance: Devon Energy Corporation / Coterra Energy Inc. — Joint Proxy Statement/Prospectus & 10-K Filing — 2026.

10.2 Disclaimer & disclosure

This analysis is for informational purposes only and is not investment advice; do your own research or consult a licensed advisor. It is a point-in-time snapshot as of 7 September 2026, built on the combined company’s first post-close results and pro-forma operating figures, at the 4 September 2026 market price — the share price, multiples and the valuation read all move, and combined operating figures are estimates pending full audited combined reporting. The two-axis verdict is an analytical read of quality and price, not a personal buy or sell instruction. This report was prepared with AI assistance; figures were sourced from the Devon/Coterra joint proxy and Devon’s filings and reviewed, but readers should verify against the combined company’s own reporting before acting. The author holds no position in Devon Energy as of the date of writing.