Letter to Stockholders Issued by Diamondback Energy, Inc.

Barnett expansion and lower unit operating costs accompanied higher total production, while deeper drilling targets raised blended drilling costs.

Rhea-AI Summary

Diamondback Energy (FANG) reported third-quarter oil production of 525 thousand barrels per day, flat sequentially and above its guidance midpoint. Total production rose 2% quarter over quarter to 1,034 thousand barrels of oil equivalent per day. Cash capital spending was $1.03 billion, within guidance.

Updated 2026 guidance calls for approximately 524 thousand barrels of oil daily, approximately 1,015 thousand barrels of oil equivalent daily and approximately $3.95 billion to $4.00 billion in capital spending. Barnett acreage reached 224,000 net acres, up 12% since February, while drilling costs per lateral foot fell over 10% year to date. A WhiteWater-led consortium including Diamondback reached a final investment decision on the Solitude pipeline, set to enter service in the second half of 2029. Diamondback is also pursuing oil-recovery pilots and partnerships linked to West Texas data centers and power.

19 points · 0 major

PositiveiHow this balance works

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Rhea-AI gives every point it takes from this document a weight. Minor counts 1, Moderate 3 and Major 9, so one Major point outweighs several Minor ones. The bar adds up the weights on each side, and when neither side holds more than 65% of the total the balance reads Mixed.

It reads the document as published, with the same rules for every company, and it does not look at what the market expected or at how the stock traded, so a point can be objectively good on a day the stock falls.

Rhea-AI Sentiment measures something else, the tone of the wording.

How the balance worksHow Sentiment works

0 major · 4 points

Hollow bars mark forward-looking points. How the balance works

Positive

• Moderate pointTotal production rose 2% quarter over quarter to 1,034 thousand barrels of oil equivalent daily.
• Moderate point. Forward-looking: it has not happened yet and may not happen.Solitude reached a final investment decision, with service set for the second half of 2029.
• Moderate pointTotal cash operating expense fell to $10.91 per oil-equivalent barrel from $10.96 sequentially, about 3% below first-quarter levels.
• Minor pointOil production of 525 thousand barrels daily was flat sequentially and above the third-quarter guidance midpoint.
• Minor point. Forward-looking: it has not happened yet and may not happen.Updated 2026 production guidance targets approximately 524 thousand oil barrels and 1,015 thousand oil-equivalent barrels daily.

14 minor points

• Minor point. Forward-looking: it has not happened yet and may not happen.Fourth-quarter production guidance targets 518–528 thousand oil barrels and 1,025–1,045 thousand oil-equivalent barrels daily.
• Minor pointBarnett acreage grew 12% since February to 224,000 net acres.
• Minor pointBarnett drilling costs per lateral foot fell over 10% year to date; a recent well was below $350.
• Minor pointBarnett completion costs fell below $400 per lateral foot following the shift to large-pad simultaneous fracturing.
• Minor pointBarnett full-field development is advancing to maximize capital efficiency while honoring lease obligations.
• Minor point. Forward-looking: it has not happened yet and may not happen.Solitude capacity of 4.5 billion cubic feet daily has potential to expand to 7.5 billion.
• Minor point. Forward-looking: it has not happened yet and may not happen.Downstream gas strategy targets more control of supply to end markets, primarily Gulf Coast liquefied natural gas.
• Minor point. Forward-looking: it has not happened yet and may not happen.Data-center partnerships are being pursued, with relationships already developed for Diamondback’s first project.
• Minor pointChemical oil-recovery pilots are testing additives intended to improve recovery and slow production declines.
• Minor pointCompleted lateral length rose roughly 13% sequentially to 13,584 feet per well.
• Minor pointCompletion crews finished 1.86 million lateral feet, up 10% sequentially, with per-foot costs essentially flat sequentially and annually.
• Minor pointFormation-specific drilling costs per foot remained flat to lower than a year earlier on a like-for-like basis.
• Minor point. Forward-looking: it has not happened yet and may not happen.Approximately 500 plunger-lift wells run autonomously; Diamondback expects to convert the remainder in short order.
• Minor point. Forward-looking: it has not happened yet and may not happen.2027 activity plans call for five electric simultaneous-fracturing fleets operating consistently.

Negative

• Minor pointBlended drilling cost per lateral foot rose as deeper Barnett and Wolfcamp D targets approached a fifth of wells.
• Minor pointDiesel, sand and water costs increased, adding operating cost pressure.
• Minor point. Forward-looking: it has not happened yet and may not happen.Barnett’s $800-per-lateral-foot well-cost target remains a goal for competitiveness with the core program.
• Minor pointChemical oil-recovery pilots remain early-stage, with a wide range of initial outcomes.

News Explained

The company has dropped its minimum quarterly cash-return commitment while reporting about one and a half billion dollars of debt reduction through September thirtieth.

Diamondback says its September agreement with SGF FANG Holdings lets SGF continue to designate two directors while it owns at least 10% of outstanding stock, after SGF’s latest sale reduced its stake below 25% and its designation right from four directors to two.

The company says its board now has 11 members, including two SGF designees.

Diamondback also says it removed its commitment to return a minimum amount of Free Cash Flow to stockholders quarterly.

Through September 30, it reports repurchasing $1.1 billion of notional bonds for about $970 million, including accrued interest, and reducing total debt, excluding Viper, by about $1.5 billion to $11.0 billion.

Key Figures

Q3 oil production: 525 MBO/d Q3 total production: 1,034 MBOE/d Q3 cash capital expenditures: $1.03 billion +5 more

Q3 oil production

525 MBO/d

Third quarter 2026; above the midpoint of guidance

Q3 total production

1,034 MBOE/d

Third quarter 2026; up 2% quarter over quarter

Q3 cash capital expenditures

$1.03 billion

Third quarter 2026; within the $950 million to $1.05 billion guidance range

Full-year oil production guidance

~524 MBO/d

Updated full-year 2026 guidance

Full-year total production guidance

~1,015 MBOE/d

Updated full-year 2026 guidance

Full-year capital expenditures guidance

$3.95 billion to $4.00 billion

Updated full-year 2026 guidance

Free cash flow

$2.1 billion

Third quarter 2026

Total debt

$11.0 billion

Diamondback excluding Viper, at September 30, 2026

Historical Context

2 past events · Latest: Aug 17

2 events

1. Aug 17

   Pipeline investment decision

   24h Move

   +1.9%

   Solitude reached FID; the earlier disclosure specified its phased capacity and Diamondback's 7.5% ownership.

2. Aug 03

   Q2 operating results

   24h Move

   -3.5%

   Q2 total production was 1,018 MBOE/d and full-year oil and total production guidance was raised.

24h Move is the share-price change in the day after each event; other market factors may also have contributed.

Key Terms

final investment decision, enhanced oil recovery, surfactant, free cash flow, +1 more

5 terms

final investment decision financial

"reached Final Investment Decision (“FID”) on another large diameter pipeline"

A final investment decision is the point at which a person or organization chooses to move forward with a particular project or purchase after reviewing all the necessary information and options. It is like deciding to buy a house after considering all the costs, benefits, and alternatives. This decision is important because it determines whether and when the investment will be made, impacting future financial plans and outcomes.

enhanced oil recovery technical

"c) Enhanced Oil Recovery (“EOR”):Chemical EOR has the potential"

Enhanced oil recovery is a set of techniques used to extract additional oil from a reservoir after the easy-to-reach portion has been produced, for example by injecting water, gas or chemicals to push or loosen remaining oil—like rinsing a sponge to get the last drops. It matters to investors because it can significantly increase a field’s output and cash flow, extend the life of assets, and change cost, environmental and regulatory risk profiles for an oil project.

surfactant technical

"ongoing pilots testing various surfactant designs"

A surfactant is a chemical that helps liquids spread, mix, or stick by lowering the tension at the boundary between them—think of soap helping oil and water mingle or wetting a surface like water on a glass. For investors, surfactants matter because they are essential ingredients in many products and medicines, affect manufacturing quality and costs, and can influence regulatory approval, product performance, and supply‑chain risks for companies that make or rely on them.

free cash flow financial

"which translated to $2.1 billion of Free Cash Flow"

Free cash flow is the amount of money a company has left over after paying all its expenses and investing in its business, like buying equipment or updating facilities. It shows how much cash is available to reward shareholders, pay down debt, or save for future growth. This helps investors understand if a company is financially healthy and able to grow.

View in glossary

non-gaap financial information financial

"forward-looking statements and non-GAAP financial information"

Non-gaap financial information are company-reported numbers that adjust standard accounting results to remove items management considers one-time, unusual, or not representative of ongoing business — for example, adjusted earnings or cash flow measures. Investors use them like a cleaned-up snapshot (wiping dirt off a window) to see underlying performance trends, but because companies choose what to exclude these figures can vary and should be compared with the official GAAP statements and disclosures.

AI-generated analysis. How Rhea-AI works. Not financial advice.

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MIDLAND, Texas, Nov. 02, 2026 (GLOBE NEWSWIRE) --

Diamondback Stockholders,

This letter is meant to be a supplement to our earnings release and is being furnished to the Securities and Exchange Commission (SEC) and released to our stockholders simultaneously with our earnings release. Please see the information regarding forward-looking statements and non-GAAP financial information included at the end of this letter.

Mega Themes

Before we talk about the quarter, we would like to give you some insight into what we see as the mega-themes of the Permian Basin over the next decade, Diamondback’s potential role in those mega-themes and why our strategy will benefit Diamondback stockholders. In our mind, these three mega-themes are: increased recoveries of oil in place, gas production growth and monetization through LNG and power demand and the growing AI / power / infrastructure buildout in West Texas and the Permian Basin.

The past decade in the Permian Basin was dominated by capital efficiency improvements, resource expansion and consolidation. This resulted in more assets in the hands of larger, well-run operators turning the dream of the shale revolution into a reality, producing more consistent returns on and of capital to the stockholders that helped fund it.

While we expect to maintain consistent returns, we anticipate the next decade will look different. Upstream consolidation in the Permian will continue, albeit at a more measured pace given how much has already occurred to date. Capital efficiency will continue to improve, but the pace of above ground mechanical improvements will naturally slow relative to what has been accomplished over the last ten years. Resource expansion will continue and new zones like the Barnett and Woodford (more on that later) are exciting, but it will be tough to match the resource growth we saw from developing the Wolfcamp B as a standalone horizontal bench in 2012 in the Midland Basin to the 8+ zones we are developing today.

Therefore, we will need to do more with what we have, directly and indirectly. We will continue to improve our position by increasing working interest (and mineral interest at Viper Energy, Inc. (“Viper”), our consolidated mineral and royalty subsidiary), extending laterals through trades, grinding down costs and being prepared for M&A opportunities if or when they present themselves.

As we mentioned earlier, we are also working on being at the forefront of three Permian mega-themes:

1. Improving Recoveries

We currently estimate that we extract approximately 10% of the oil in place in the Permian Basin today. Every percentage point of incremental recovery carries significant value to our stockholders, and we are therefore very focused on improving recoveries. There are several factors that contribute to the ultimate recovery of hydrocarbons from a well, but the list below represents the main factors we are focused on.

a) Development design:
Each project Diamondback executes is designed to maximize the return the Company receives on capital while ensuring resource recovery is maximized at an appropriate incremental rate of return hurdle. Our philosophy has resulted in Diamondback's projects generating the highest average returns relative to our peer group. These outcomes are clearly seen on slide #10 of this quarter’s investor presentation.

Broadly, our relatively higher wells per section × better per well performance ÷ the lowest cost structure in the basin = the maximum return for every dollar of capital invested. Diamondback was an early adopter of co-development in the Midland Basin, moving to this methodology in 2019 for the core zones from the Middle Spraberry to the Wolfcamp B. Co-development of 8+ benches in the Midland Basin, optimized spacing and targeting, longer laterals and creative wellbore trajectories allow us to optimize our developments while preserving the value of our remaining inventory – an advantage we believe is unmatched in the basin.

b) Completion design:
Proper completion sizing is imperative to maximizing value from each development project. The advancement of completion technology into simulfrac and continuous pumping are positive cost stories from an operational standpoint, but they have also allowed us to pursue more aggressive stage designs with tighter cluster and stage spacing to increase reservoir contact and near-wellbore fracture complexity. We believe this, combined with our efforts around advanced chemical additives, is contributing to recent well outperformance relative to previous vintages seen on slide #10 of this quarter’s investor presentation.

c) Enhanced Oil Recovery (“EOR”):
Chemical EOR has the potential to meaningfully improve recovery factors and shallow base decline rates in unconventional reservoirs. Shallowing our corporate base decline by just 1% at current capital efficiency implies drilling 10 to 15 fewer wells to maintain flat oil production, extending inventory quality and duration.

Chemical EOR makes it easier for oil to flow through the reservoir to the wellbore. We have several ongoing pilots testing various surfactant designs both in the remedial and completion phases of our operations. These pilots are in the early stages, and we have seen a wide range of outcomes from our initial tests. We will continue to learn from these tests and refine our methodologies to continuously improve, just as we did on the completion side of the business over the last fifteen years.

Our goal is and has always been to be the best at converting rock into cash flow. We have demonstrated this ability consistently over the past decade and will continue to do so moving forward. We are confident the technologies and workflows we are developing today will propel us to higher recoveries in the future and we look forward to keeping our stockholders updated on our progress.

2. Gas Production and Monetization

In the third quarter, future gas growth out of the Permian Basin received significant attention as a WhiteWater-led consortium (that includes Diamondback) reached Final Investment Decision (“FID”) on another large diameter pipeline out of the basin. This pipe is called Solitude and is set to enter service in the second half of 2029. This project consists of two twin 48" lines able to move 4.5 bcf/d out of the Permian to Katy and Gulf Coast markets, with potential to expand to 7.5 bcf/d. While the market was surprised that another pipe reached FID this quickly after multiple announcements over the last 18 months, we were not.

As we have said many times, the Permian Basin has not tried to produce gas yet. We expect the Permian to be the largest natural gas play as well as the largest oil play in the United States in the 2030s. Gas to oil ratios will naturally continue to expand, secondary zones in both the Midland and the Delaware Basins are gassier than what operators have targeted to date and there are gas-weighted exploratory zones that have not even been tested yet given the perpetual egress issues out of this basin.

As for Diamondback’s strategy, our goal is to continue to control more of our gas further downstream to a mix of end markets, primarily feeding the Gulf Coast LNG complex. We are working to build relationships with LNG players who are long offtake and short physical molecules. There should be beneficial deals to get done with those companies in the coming years. We also believe in-basin and in-state power demand will continue to grow, driven by both behind-the-meter power development and the expansion of the Texas grid.

At the highest level, the gas theme in the Permian Basin has moved from supply-push to demand-pull, which should be beneficial to the owners of the molecule long-term and therefore Diamondback stockholders.

3. West Texas AI / Power / Infrastructure Buildout

We believe that the incremental large-scale data center development in the United States should go through West Texas and that Diamondback can be an integral part of that value chain without overstepping our core competencies. In our mind, our Company owns or has access to all the key components of data center development:

• Fuel: We have significant natural gas reserves that we control. These can grow if needed.
• Land: We own surface in areas conducive to development and know how to strategically grow our position.
• Water: We are invested in and understand the water business, which is vital to our upstream business and becoming increasingly important as industrial use cases including data center and power cooling needs grow.
• Deal Execution: We have a long track record of sourcing, structuring, financing and integrating transactions across our value chain. Since our 2012 IPO, Diamondback, along with Viper, have successfully completed approximately $60 billion in trades across dozens of transactions, and in parallel, have formed, scaled and successfully exited joint ventures in midstream and water infrastructure, creating value beyond the drillbit. In short, we know how to get deals done, upstream and non-upstream alike, that benefit our stockholders.

Therefore, we believe companies like Diamondback with credible projects will continue to rise to the top. Our hope is to build relationships and partnerships across this space that put us in the middle of the AI revolution, and we think a company like ours can add significant value to advancing this mega-theme.

We have already developed significant relationships with strong, reliable partners in working our first project. We expect these partnerships to grow, but also see room for more. West Texas has a significant amount of private land, an abundance of fuel for power and our industry (Diamondback in particular) knows how to build things with unmatched efficiency. Diamondback’s own production has grown more than 330x since 2012 – a growth rate competitive with the tech industry that is naturally intersecting with ours.

Barnett / Woodford Update

We received significant market curiosity after revealing our Barnett position in the Midland Basin earlier this year. Since that announcement, we have grown our position to 224,000 net acres, up 12% since February. We are also entering a period of increased activity in the play as we move to full-field development so we can maximize capital efficiency while honoring lease obligations.

When we revealed our position, we told our investors we needed to work the well costs down to $800 per lateral foot for the play to be competitive with our core program. We are on our way to this number, with drilling costs down over 10% per lateral foot year-to-date including a recent well below $350 per lateral foot. Completion costs have also been reduced to below $400 per lateral foot as we have moved to large pad simulfrac operations on most current and future Barnett projects.

Recent well results also continue to increase our excitement about the Barnett. Today we revealed data around our best wells in the play on slide #11 of this quarter’s investor presentation, which had previously remained private as we worked through our leasing program. This performance, combined with our improving cost structure, further strengthens our conviction in this emerging opportunity.

Governance

In September, we disclosed an agreement with our largest stockholder, SGF FANG Holdings, LP (“SGF”), to revise the stepdown thresholds for SGF’s board designation rights. In connection with SGF’s most recent stock sale that reduced its ownership below 25% and reduced its corresponding right to designate board members from four board members to two board members, we essentially agreed that SGF could continue to designate two board members for so long as it owns at least 10% of our outstanding stock.

The Diamondback Board now has 11 members, in line with S&P 500 and large-cap energy peer averages. We believe this size balances breadth of expertise with cohesion. While we have two Board members who are SGF designees and nine who are not, we feel we are one Diamondback Board with a unified strategy to drive stockholder value while ensuring our largest stockholder feels appropriately represented on the Board with two well-qualified members who collectively bring over 75 years of experience in the oil and gas industry. We believe this is best-in-class governance.

Macro Update

The macro backdrop is almost exactly as we described last quarter: highly volatile and impossible to predict. The timing of the eventual global oil supply normalization is anyone’s guess, and we therefore expect the current volatility to continue. Through this volatility, our priorities remain unchanged: execute with the best capital efficiency in the industry and allocate Free Cash Flow appropriately to maximize long-term stockholder value.

Third Quarter 2026 Operational Performance

Third quarter oil production averaged 525 MBO/d, flat with the second quarter and above the midpoint of our guidance range. Total production for the quarter averaged 1,034 MBOE/d, up 2% quarter over quarter. Third quarter cash capital expenditures were $1.03 billion, within our $950 million to $1.05 billion guidance range. With one quarter remaining, we have updated our full-year 2026 oil production guidance to ~524 MBO/d, total production guidance to ~1,015 MBOE/d; and our full-year capex guidance to approximately $3.95 billion to $4.00 billion.

Fourth quarter guidance is 518 to 528 MBO/d (1,025 to 1,045 MBOE/d) on $1.00 to $1.05 billion of capex. Our current expectation for activity in 2027 is to run five electric simulfrac fleets consistently for maximum efficiency while running enough rigs ahead of those crews to maintain the execution buffers one would expect from Diamondback.

On the drilling side, our blended cost per lateral foot rose in the quarter as the program shifted toward deeper Barnett and Wolfcamp D targets, which now make up roughly a fifth of the wells we drill. On a like-for-like basis, drilling costs per foot in each formation remain flat to lower than a year ago. In total, we drilled 105 gross wells and completed 135, with average completed lateral length up roughly 13% quarter over quarter to 13,584 feet per well. Our completion crews finished 1.86 million lateral feet, 10% more than last quarter, at a cost per lateral foot essentially flat with both the prior quarter and a year ago. These results absorbed higher diesel, sand and water costs, consistent with the inflation pressure we flagged last quarter in casing, fuel and fuel-adjacent items. Service pricing outside those categories has remained largely stable, but it is logical that inflation could build if oil prices stay in the triple digits and the Permian rig count keeps rising. We expect any increase to be more modest than the 2022 upcycle, when rig activity surged while supply chains were still recovering from the pandemic. We continue to challenge our teams to offset cost pressure with efficiency gains in the field; we expect those gains to materialize, but the net effect will depend on the macro environment.

Technology is increasingly part of how we deliver these results. Artificial intelligence continues to grow in importance to our daily operations. We now have ~500 plunger-lift wells, about a third of our current count, that run autonomously, and we expect to convert the remainder in short order. We are also in the early stages of integrating drones into our field operations where the drones can identify issues ahead of human interaction, improving human efficiency and reducing corporate downtime.

These gains are visible in our unit costs. Lease operating expense was $5.97 per BOE, flat with the second quarter and roughly 4% below the first quarter, and total cash operating expense was $10.91 per BOE, down slightly from $10.96 in the second quarter and about 3% below the first quarter. Behind those numbers is a production organization doing more work at lower unit cost: our well-maintenance teams completed 1,448 jobs, 19% more than in the second quarter, at an average cost per job roughly 10% lower. Additionally, electric submersible pump repair costs are 14% less on average. Keeping downtime and the workover backlog in check as our well count grows is what is holding lifting cost down.

Third Quarter 2026 Financial Performance

We generated $2.6 billion in net cash provided by operating activities in the third quarter, which translated to $2.1 billion of Free Cash Flow. Cash capital expenditures of $1.0 billion represented 39% of net cash provided by operating activities for the quarter and 37% year to date. Our corporate reinvestment ratio (defined as cash CAPEX divided by Operating Cash Flow Before Working Capital Changes) was 32% for both the quarter and year to date, meaning two of every three dollars of cash flow we generated this year have been converted to Free Cash Flow.

Since the Endeavor merger closed eight quarters ago, oil production per share has increased every quarter and is up 15% over that span. Year over year, oil production per share has grown 7.5% on absolute oil growth of 4%. Year over year, net cash provided by operating activities per share has grown 12.5%, and Free Cash Flow per share has grown 26%, with our diluted share count down 3%.

Capital Allocation

Earlier this year, we removed our commitment to return a minimum amount of Free Cash Flow on a quarterly basis to stockholders. Since then, we have focused on taking advantage of what the market gives us. We have repurchased $1.1 billion of notional bonds outstanding for ~$970 million (including accrued interest) this year. It is rare for an E&P to be able to do this pro-cyclically. On top of that, in 2026 through September 30, we have reduced total debt at Diamondback (excluding Viper) by approximately $1.5 billion, to $11.0 billion, and net debt at Diamondback by approximately $2.0 billion. On a consolidated basis, total debt has decreased approximately $1.3 billion and net debt approximately $1.7 billion this year through September 30.

"Ground game" has been a hot topic in the Permian Basin this year, and Diamondback has always prided itself on executing deals of all sizes. Year to date, we have executed 34 acquisitions for $406 million, adding over 28,000 net acres and 95 net locations, and closed 10 trades covering more than 20,000 net acres. While each deal is small relative to our enterprise, in aggregate they matter: this year's ground game activity has added 1.9 million lateral feet to inventory, replacing roughly a full quarter's worth of completed footage. Every one of these deals creates value for our stockholders through higher working interest, longer laterals and extended inventory duration – little wins that add up year in and year out.

We also saw periods of stock price weakness in the third and early fourth quarters, and we took advantage of this weakness and bought back 1.7 million shares at an average price of $186.11. As we continue to generate cash flow at what we believe are above mid-cycle commodity prices, the “top” that we use to ensure we buy back stock at an accretive value relative to mid-cycle commodity pricing and our cost of capital will continue to go up – accreting value to the stockholders long-term. On the other hand, we are also preparing our balance sheet to be able to be aggressive on stock repurchases at the appropriate time of the natural commodity cycle.

Lastly, today we announced we increased our base dividend by over 7% to $4.72 per share annually from $4.40 previously. As a reminder, base dividend growth remains a core tenet of the value proposition at Diamondback and our base dividend is now up over 9x since initiating at $0.50 per share in 2018.

In closing, we continue to execute exceptionally well on the base business. This execution and the trust we have in our team frees us up to think more strategically about the future of the Permian Basin and Diamondback’s role in that future. We gave you a glimpse into that thinking today, see exciting things on the horizon and will update our stockholders as we progress on these initiatives with the transparency you should continue to expect from us.

Thank you for your continued interest in Diamondback Energy.

Sincerely,

Kaes Van't Hof
Chief Executive Officer and Director

Investor Contact:
Adam Lawlis
+1 432.221.7467
alawlis@diamondbackenergy.com 

Forward-Looking Statements:

This letter contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions. All statements, other than statements of historical fact, including statements regarding Diamondback’s: future performance; business strategy; future operations (including drilling plans and capital plans); estimates and projections of revenues, losses, costs, expenses, returns, cash flow, and financial position; reserve estimates and its ability to replace or increase reserves; anticipated benefits or other effects of strategic transactions (including the 2026 drop down to Diamondback’s subsidiary, Viper Energy, Inc. (“Viper”), Viper’s Riverbend acquisition, Viper’s McElroy Ranch acquisition and Viper’s Sitio acquisition, and other acquisitions, divestitures or reorganizations); and plans and objectives of management (including plans for future cash flow from operations and for executing environmental strategies) are forward-looking statements. When used in this letter, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to Diamondback are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Although Diamondback believes that the expectations and assumptions reflected in its forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond Diamondback’s control. Accordingly, forward-looking statements are not guarantees of future performance and Diamondback’s actual outcomes could differ materially from what Diamondback has expressed in its forward-looking statements.

Factors that could cause the outcomes to differ materially include (but are not limited to) the following: geopolitics and market conditions, including changes in supply and demand levels for oil, natural gas and natural gas liquids and the resulting impact on the price for those commodities; changes in U.S. energy, environmental, monetary and trade policies, including with respect to tariffs or other trade barriers and any resulting trade tensions; actions taken by the members of OPEC and its non-OPEC allies (OPEC+) affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments; changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates, inflation rates, and instability in the financial sector; regional supply and demand factors, including delays, curtailments or interruptions of production, or governmental orders, rules or regulations that impose production limits; federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations; physical and transition risks relating to climate change, changing political and social perspectives on climate change and other environmental, social and governance factors, and risks from our publicly disclosed targets related to sustainability and emissions reduction initiatives; challenges in developing our existing leasehold acreage and finding, developing or acquiring additional reserves; restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water disposal well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin; significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges; conditions in the capital, financial and credit markets, including the availability and pricing of capital for acquisitions, exploration and development operations; challenges with employee retention and an increasingly competitive labor market; changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services; changes in safety, health, environmental, tax and other regulations or requirements (including those addressing air emissions, water management, or the impact of global climate change); security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business; lack of, or disruption in, access to adequate and reliable electrical power, internet and telecommunication infrastructure, information and computer systems, transportation, processing, storage and other facilities for our oil, natural gas and natural gas liquids; failures or delays in achieving expected reserve or production levels from existing and future oil and natural gas developments, including due to operating hazards, drilling risks, or the inherent uncertainties in predicting reserve and reservoir performance; inability to keep pace with technological developments in our industry; failure to meet our obligations under our oil purchase contracts; loss of one or more customers or their inability to meet their obligations; geographical concentration of our primary operations; risks from our return of capital activity, and uncertainties over our future dividends and share repurchases; difficulty in obtaining necessary approvals and permits; severe weather conditions and natural disasters; changes in the financial strength of counterparties to our credit facilities and hedging contracts; our substantial indebtedness and restrictions to our operating and financial flexibility; changes in our credit rating; failure to identify, complete and successfully integrate acquisitions, including Viper’s Riverbend acquisition, McElroy Ranch acquisition and Sitio acquisition; the Endeavor stockholders’ ability to significantly influence our business and potential conflicts of interest; and other risks described in Part I, Item 1A of Diamondback’s Annual Report on Form 10-K, filed with the SEC on February 25, 2026, and those risks disclosed in its subsequent filings on Forms 10-Q and 8-K, which can be obtained free of charge on the SEC’s website at http://www.sec.gov and Diamondback’s website at www.diamondbackenergy.com/investors.

In light of these factors, the events anticipated by Diamondback’s forward-looking statements may not occur at the time anticipated or at all. Moreover, Diamondback operates in a very competitive and rapidly changing environment and new risks emerge from time to time. Diamondback cannot predict all risks, nor can it assess the impact of all factors on its business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those anticipated by any forward-looking statements it may make. Accordingly, you should not place undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this letter or, if earlier, as of the date they were made. Diamondback does not intend to, and disclaims any obligation to, update or revise any forward-looking statements unless required by applicable law.

Non-GAAP Financial Measures

This letter includes financial information not prepared in conformity with generally accepted accounting principles (GAAP), such as Free Cash Flow, Free Cash Flow per share, Operating Cash Flow Before Working Capital Changes, and net debt. The non-GAAP information should be considered by the reader in addition to, but not instead of, financial information prepared in accordance with GAAP. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in Diamondback's quarterly results, which are posted on Diamondback's website at www.diamondbackenergy.com/investors and included as Exhibit 99.1 to the Current Report on Form 8-K filed by Diamondback with the SEC that also includes this letter as Exhibit 99.2. Furthermore, this letter includes or references certain forward-looking, non-GAAP financial measures. Because Diamondback provides these measures on a forward-looking basis, it cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP financial measures, such as future impairments and future changes in working capital. Accordingly, Diamondback is unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Diamondback believes that these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing Diamondback's forecasted financial performance to the forecasted financial performance of other companies in the industry.

FAQ

AI-generated questions and answers. How Rhea-AI works. Not financial advice.

What capital spending does Diamondback Energy expect for 2026 and the fourth quarter?

Diamondback expects approximately $3.95 billion to $4.00 billion in full-year 2026 capital spending and $1.00 billion to $1.05 billion in the fourth quarter. Third-quarter cash capital spending was $1.03 billion, within its $950 million to $1.05 billion guidance range.

When will Diamondback’s Solitude pipeline project enter service, and how much gas can it move?

Solitude is set to enter service in the second half of 2029, with capacity to move 4.5 billion cubic feet per day. The project comprises twin 48-inch pipelines from the Permian Basin to Katy and Gulf Coast markets, with potential expansion to 7.5 billion cubic feet per day.

How did Diamondback Energy change SGF’s board designation rights?

SGF can continue to designate two directors while it owns at least 10% of Diamondback’s outstanding stock. Its latest stock sale reduced ownership below 25% and its designation rights from four directors to two. Diamondback’s board now has 11 members, including two SGF designees.

What oil-recovery improvement is Diamondback Energy targeting with chemical recovery technology?

Diamondback is testing chemical treatments to improve oil recovery and slow the decline in existing production. The company estimates that reducing its corporate base decline by 1% at current capital efficiency would imply drilling 10 to 15 fewer wells to maintain flat oil production. Initial pilot outcomes have varied widely.