NASDAQ: PROP

Business Strategy

We intend to increase stakeholder value by using the following strategies to grow our reserves, production, and cash flow in a capital efficient and environmentally conscious manner:

Deliver growth through the development of extensive drilling inventory and acreage. We plan to target rich, immediately accessible permitted locations and organically
grow development through infill leasing. We believe this will allow us to increase production, reserves and cash flow which generate favourable returns.

Fund drilling program with free cash flow and retain low leverage. We aim to maintain a conservative financial position and develop primarily through available cash flow
from operations. We plan to allocate capital in a disciplined manner and proactively manage our cost structure.

Maximize returns and capital efficiency. We plan to utilize the latest technology in 3–D seismic mapping and geo–steering to decrease drill times and improve well results.
Additionally, our management’s extensive experience allows us to deploy the latest drilling and completion methodologies and apply the industry best practices to increase overall estimated ultimate recovery versus prior generation wells.

Acquisition strategy focused on core area in the DJ Basin. We plan to pursue accretive acquisitions through an opportunistic roll–up strategy by continually evaluating
acquisition opportunities to expand our position. Our management team has a long track record of successfully sourcing and integrating acquisitions.

Proactively manage regulatory, environmental, safety, and community matters. Our development approach prioritizes the well–being of environment, communities, and wildlife,
and we actively engage with regulatory agencies to minimize surface impact while maximizing efficiency of our development program. Additionally, our operations emphasize utilizing technology and innovation to minimize impacts.

3

Table of Contents

Our Properties and Operations

Central Weld Assets

On January 11, 2024, we and one of our subsidiaries entered into an asset purchase agreement (the “NRO Agreement”) with NRO to acquire the assets of NRO (the “NRO Acquisition”). On October 1, 2024, we closed
the NRO Acquisition and paid $49.6 million to NRO in cash.

On February 6, 2025, we and certain of our subsidiaries entered into a purchase and sale agreement with Bayswater, pursuant to which we agreed to acquire certain oil and natural gas assets (the “Bayswater
Assets”) for a purchase price of $602.8 million, subject to certain closing price adjustments (the “Bayswater Acquisition”). At the closing of the Bayswater Acquisition on March 26, 2025, we (i) paid approximately $482.5 million in cash to
Bayswater, $15.0 million of which was deposited in escrow pending the acquisition of additional working interest (the “Additional Working Interest Acquisition”), which Bayswater acquired and assigned to us on April 11, 2025, and (ii) issued
3,656,099 shares of our common stock, par value $0.01 per share (“Common Stock”) to Bayswater (the “Equity Consideration”). We completed the final settlement with Bayswater on October 15, 2025, resulting in a final consideration of $475.6
million.

In July 2025, we entered into an agreement to acquire certain assets from Edge Energy for a total purchase price of $12.5 million payable in cash, subject to certain closing adjustments (the “Edge Acquisition”).
We closed the Edge Acquisition on July 3, 2025, which included the acquisition of 13 operated wells on approximately 11,300 net acres. We funded the transaction by borrowing under our amended and restated reserve–based credit agreement (the
“Credit Facility”) with Citibank, N.A. (“Citi”). In October 2025, we entered into agreements to acquire certain assets from Summit Oil & Gas, LLC. (“Summit”) and Crown Exploration II, Ltd (“Crown”) for a total purchase price of $2.3
million payable in cash, subject to certain closing adjustments (the “Summit and Crown Acquisitions”). The Summit and Crown Acquisitions included the acquisition of five operated wells on approximately 3,400 net acres. We refer to the
assets we acquired in the Bayswater Acquisition, the Edge Acquisition, and the Summit and Crown Acquisitions as the “Central Weld Assets.”

As of December 31, 2025, the Central Weld Assets cover approximately 45,000 net leasehold acres, on and under approximately 56,200 gross acres and 177 gross proved undeveloped locations. Approximately 87% of the
net leasehold of our Central Weld Assets are held by production and 95% of the acreage is leased from private landowners, with the remaining 5% under State of Colorado or Federal leases. The remaining 13% of the Central Weld Assets acreage
not held by production have varying expiration dates, some with options to extend ranging from one to two years. The Central Weld Assets fee leases are burdened with average royalties of 20%. The leases can be held indefinitely by
production and unless production is established within the spacing units covering the undeveloped acreage, the leases for such acreage will eventually expire.

Development Plan and Permitting. We began executing the development plan of our Central Weld Assets in the second quarter of 2025 by completing nine wells on the
Opal/Coalbank pad and drilling 11 gross wells on the Rusch pad, which came online in September 2025. After completing drilling at our Rusch pad, we drilled our Noble pad development, consisting of seven gross wells, and our Simpson pad,
consisting of six gross wells, both of which came online in the fourth quarter of 2025. We finished the year by drilling a 10 gross well development consisting of five wells in our Blehm North drilling spacing unit (“DSU”) and five wells in
our Schneider DSU. These ten wells are expected to be completed in the first quarter of 2026. Additionally, we began drilling a nine well development in our Elder East and West DSUs, which is expected to be completed in the early in the
second quarter of 2026.

Additionally, we plan to drill and complete approximately 40 gross wells in 2026 with further development planned in 2027. Our drilling plan is based on current commodity prices, and an increase or decrease in
commodity prices could impact the number of wells we actually drill. There is no guarantee that our development plan will result in the successful production of economic quantities of oil and natural gas. Our development plan is based on
assumptions from management’s prior experience and such experience may not be indicative of the success of our development plans.

4

Table of Contents

The following table summarizes the permitting status of our Central Weld Assets gross undeveloped locations as of December 31, 2025:

Gross

Undeveloped

Locations

Weld Oil & Gas Location Assessment Approved

128

Colorado Energy & Carbon Management Commission Approved

128

Colorado Energy & Carbon Management Commission Fully Permitted

103

For more information regarding regulations affecting our permitting, refer to Regulation of the Oil and Natural Gas Industry—Related Permits and Authorizations.

Genesis Assets

In May 2023, we consummated the purchase of oil and natural gas leases from Exok, Inc. (“Exok”), including all of Exok’s right, title, and interest in, to and under approximately 3,200 net leasehold acres
located in Weld County, Colorado, together with certain other associated assets, data, and records, for $3.0 million (the “Exok Transaction”). On August 15, 2023, we exercised the option we acquired in the Exok Transaction to purchase
additional oil and natural gas leases from Exok, consisting of approximately 20,300 net leasehold acres in, on and under approximately 32,580 gross acres (the “Exok Option Purchase”) for total consideration of $25.3 million (collectively,
the “Initial Genesis Assets”). On February 5, 2024, we acquired 1,280 gross leasehold acres on drillable spacing unit and eight proved undeveloped drilling located in the DJ Basin, made up of 835 net leasehold acres, from a private seller
for $0.9 million. In August 2025, we completed our third acquisition from Exok, acquiring approximately 5,000 net acres for $1.6 million (the “Third Exok Acquisition”). We refer to these assets collectively as the “Genesis Assets.” As of
December 31, 2025, the total Genesis Assets include approximately 23,000 net leasehold acres in, on and under approximately 42,000 gross acres. As of December 31, 2025, approximately 7,900 net acres of the Genesis Assets have expired. The
expired leases were deemed non–core; therefore, we elected to not re–new the leases at their expiration date.

Approximately 92% of the net leasehold of our Genesis Assets are leased from private landowners, with the remaining 8% under State of Colorado or Federal leases. 91% of the net Genesis Assets acreage is held by
crude oil and natural gas leases with varying expiration dates, some with options to extend ranging from one to four years. The leases can be held indefinitely by production. Unless production is established within the spacing units covering
the undeveloped acreage, the leases for such acreage will eventually expire.

Development Plan and Permitting. We began executing the development plan of our Genesis Assets in the third quarter of 2024 by drilling eight wells in the Shelduck
South development, all of which began producing in February 2025.

Our 2026 drilling plan includes drilling an additional four gross wells on our Gensis Assets. Our drilling plan is based on current commodity prices, and an increase or decrease in commodity prices could impact
the number of wells we actually drill. There is no guarantee that our development plan will result in the successful production of economic quantities of oil and natural gas. Our development plan is based on assumptions from management’s
prior experience and such experience may not be indicative of the success of our development plans.

The following table summarizes the permitting status of our identified well locations with respect to our Genesis Assets as of December 31, 2025:

Expected Three

Mile Lateral

Count

Expected Two

Mile Lateral

Count

Weld Oil & Gas Location Assessment Approved

18

54

Colorado Energy & Carbon Management Commission Approved

18

54

Colorado Energy & Carbon Management Commission Fully Permitted

10

10

For more information regarding regulations affecting our permitting, refer to Regulation of the Oil and Natural Gas Industry—Related Permits and Authorizations below.

5

Table of Contents

Reserves

Our reserve estimates as of December 31, 2025 and 2024, are based on a reserve report prepared by Cawley, Gillespie & Associates Inc. (“CG&A”) in accordance with the rules and regulations of the SEC in
Regulation S–X, Rule 4–10, and do not include probable or possible reserves. All of our proved reserves presented below are located in the DJ Basin.

The following table presents our estimated proved reserves by category, the standardized measure of discounted future net cash flows, PV–10, and the prices used in the calculation of net proved reserves estimates
for the years indicated:

Year Ended December 31,

2025

2024

Net reserve volumes:

Proved developed producing:

Oil (MBbls)

27,900

1,967

Natural gas (MMcf)

122,975

4,887

NGL (MBbls)

17,974

600

Total (MBoe) (1)

66,370

3,382

Proved developed non–producing:

Oil (MBbls)

1,406

1,782

Natural gas (MMcf)

2,258

4,419

NGL (MBbls)

330

536

Total (MBoe) (1)

2,112

3,054

Proved undeveloped:

Oil (MBbls)

30,725

10,594

Natural gas (MMcf)

70,041

31,932

NGL (MBbls)

10,238

3,767

Total (MBoe) (1)

52,637

19,683

Total proved:

Oil (MBbls)

60,031

14,343

Natural gas (MMcf)

195,274

41,238

NGL (MBbls)

28,542

4,903

Total (MBoe) (1)

121,119

26,119

Reserves data (in thousands):

Standardized measure of discounted future net cash flows

$
851,702

$

255,142

PV–10 (2)

$

1,219,814

$

303,159

SEC Prices (3):

Oil (per Bbl)

$

65.34

$

74.63

Natural gas (per MMBtu)

$

3.39

$

1.60

NGL (per Bbl)

$

19.28

$

21.63

(1)

Assumes a ratio of 6 MMcf of natural gas per MBoe.

(2)

PV–10 is a financial measure not presented in accordance with U.S. GAAP. PV–10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure
for proved reserves. PV–10 is a computation of the Standardized Measure on a pre–tax basis and is equal to the Standardized Measure at the applicable date, before deducting future income taxes discounted at 10%.

(3)

Our estimated proved reserves and the related net revenues were determined using the 12–month unweighted arithmetic average of the first–day–of–the–month price for each month in the
period January through December (“SEC Prices”). The SEC Prices are adjusted for treating costs and/or crude quality and gravity corrections.

6

Table of Contents

Reconciliation of Standardized Measure to PV–10

PV–10 is a financial measure not presented in accordance with U.S. GAAP. PV–10 is derived from Standardized Measure, which is the most directly comparable GAAP financial measure for proved reserves. PV–10 is a
computation of the Standardized Measure on a pre–tax basis and is equal to the Standardized Measure at the applicable date, before deducting future income taxes discounted at 10%. Neither PV–10 nor the Standardized Measure represents an
estimate of the fair market value of the applicable crude oil, natural gas, and NGLs properties. We believe that the presentation of PV–10 is relevant and useful to our investors as supplemental disclosure to the Standardized Measure, or
after–tax amount, because it presents the discounted future net cash flows attributable to our reserves before considering future corporate income taxes and our current tax structure. PV–10 has limitations as a financial measure since it
excludes future income taxes and should not be considered as an alternative to, or more meaningful than, Standardized Measure calculated in accordance with GAAP.

The following table provides a reconciliation of the Standardized Measure to the PV–10 of our estimated proved reserves for the years indicated:

Year Ended December 31,

2025

2024

(In thousands)

Standardized Measure

$
851,702

$

255,142

Present value of future income taxes discounted at 10%

368,112

48,017

PV–10

$

1,219,814

$

303,159

Proved Reserves

The following table presents the changes in our estimated proved reserves during the year ended December 31, 2025:

Total

(MBoe)

Proved reserves as of January 1, 2025

26,119

Acquisitions of reserves

95,344

Production

(6,748

)

Revisions to previous estimates

6,404

Proved reserves as of December 31, 2025

121,119

As of December 31, 2025, our estimated proved reserves are 121.1 MMBoe, which are primarily comprised of 95.3 MMBoe reserves acquired during the year ended December 31, 2025 and revisions to previous reserve estimates of 6.4 MMBoe.

Proved Undeveloped Reserves

Proved undeveloped oil and natural gas reserves are reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for
completion. Proved undeveloped reserves on undrilled acreage are limited to those directly offsetting development spacing areas which are reasonably certain of production when drilled, unless evidence using reliable technology exists that
establishes reasonable certainty of economic productivity at greater distances.

The following table presents the changes in our estimated proved undeveloped reserves during the year ended December 31, 2025:

Total

(MBoe)

Proved undeveloped reserves as of January 1, 2025

19,683

Converted to proved developed reserves

(10,452

)

Acquisitions of reserves

41,452

Revisions to previous estimates

1,954

Proved undeveloped reserves as of December 31, 2025

52,637

During the year ended December 31, 2025, we converted 20% of our proved undeveloped reserves, which is comprised of 34 gross wells representing net reserves of 10.5 MMBoe, at an average cost of $3.9 million net
per well. Additionally, we had acquisitions of proved undeveloped reserves of 41.5 MMBoe and revisions of 2.0 MMBoe during the year ended December 31, 2025.

7

Table of Contents

Management reviews all proved undeveloped reserves on an annual basis to ensure an appropriate plan for development exists. As per SEC rules, all of our proved undeveloped reserves are required to be converted to
proved developed reserves within five years of the date they are first booked as proved undeveloped reserves, unless the reserves are associated with an existing producing zone. We expect that development costs associated with our estimated
proved undeveloped reserves as of December 31, 2025 will require us to invest an additional $689.6 million for those reserves to be brought to production. Our ability to make the necessary investments to generate these cash inflows is
subject to factors that may be beyond our control. Refer to Risk Factors – The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures
than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not ultimately be developed or produced.

Qualifications of Technical Persons

Our proved reserve estimates as of December 31, 2025 and 2024 included in this Annual Report have been prepared by CG&A, an independent Petroleum Reserve Evaluation Firm. Our full reserve report as of
December 31, 2025, prepared by CG&A, should be read in its entirety, and is attached as Exhibit 99.1 to this Annual Report. These proved reserve estimates were prepared in accordance with the Standards Pertaining to the Estimating and
Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers (“SPE”) and the guidelines established by the SEC.

The technical personnel responsible for preparing the reserve estimates of CG&A meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards
Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the SPE. The estimates of our reserves presented in the CG&A reserve report were overseen by W. Todd Brooker. Mr. Brooker is the
President of CG&A and has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, expert reporting and testimony, field/reservoir studies, pipeline resource
assessments, field development planning and acquisition/divestiture analysis. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker graduated with honours from The
University of Texas at Austin in 1989 with a Bachelor of Science Degree in Petroleum Engineering. He is a registered Professional Engineer in the State of Texas (License #83462), and a member of the SPE and the Society of Petroleum Evaluation
Engineers (“SPEE”). No director, officer or key employee of CG&A has any financial ownership in use or any of our affiliates. CG&A’s compensation for preparation of its report is not contingent upon the results obtained and reported.
CG&A has not performed other work for us or any of our affiliates that would affect its objectivity. CG&A does not own an interest in our properties.

Timothy Smith, our Senior Vice President of Engineering, works closely with CG&A to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their preparation
of reserve estimates. Mr. Smith is primarily responsible for overseeing the preparation of both our internal and external reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors
set forth in the Standards Pertaining to Estimation and Auditing of Oil and Natural Gas Reserves Information promulgated by the SPE. Mr. Smith’s qualifications include a Bachelor of Arts Degree in Geology from the University of Colorado at
Boulder, a Master of Science Degree in Civil Engineering from Colorado State University, and a Master of Science Degree in Petroleum Engineering from the University of Southern California. Additionally, he has 16 years of practical experience
in estimating and evaluating reserve information, the majority of which have included overseeing, estimating, and evaluating reserves and is a member of SPE.

Internal Controls over Estimated Proved Reserves

The preparation of our proved reserve estimates is completed in accordance with our internal control procedures. As part of this process, we provide historical information to the independent reserve engineers
relating to the ownership interest, oil and natural gas production, well data, commodity prices, and operating and development costs of our properties.

Technical, geological, and engineering reviews of our assets are performed throughout the year and data obtained from these reviews, in conjunction with economic data and our ownership information, is used in
making a determination of estimated proved reserve quantities. These procedures are intended to ensure reliability of reserve estimations, and include the review and verification of historical production data, working interests, net revenue
interest, lease operating statements, capital costs, severance and ad valorem taxes and the review of all significant reserve changes and all new proved undeveloped reserves additions.

8

Table of Contents

Production, Average Sales Prices, and Production Costs

Our production volumes, average sales prices, and average production costs are as follows:

Year Ended December 31,

2025 (1)

2024

Production:

Oil (MBbls)

3,406

96

Natural gas (MMcf)

10,753

245

NGL (MBbls)

1,550

33

Total production (MBoe) (2)

6,748

170

Average sales volumes per day (Boe/d)

18,487

464

Average sales price (excluding effects of derivatives):

Oil (per MBbls)

$

59.91

$

68.60

Natural gas (per MMcf)

$

0.88

$

2.25

NGL (per MBbls)

$

18.16

$

24.03

Average price (per MBoe) (2)

$

35.81

$

46.70

Average lease operating expenses (per Boe)

$

6.14

$

7.44

(1)

Total revenues and production for the year ended December 31, 2025, include revenue and production volumes from the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through
December 31, 2025.

(2)

MBoe is calculated using six MMcf of natural gas equivalent to one MBbl of oil.

For additional information, refer to Part II – Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

9

Table of Contents

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and crude oil wells awaiting connection to
production facilities. Gross wells are the total number of productive wells in which we have an interest and net wells are the sum of our fractional working interests owned in gross wells.

The following table presents a summary of our productive wells as of December 31, 2025:

Oil

Operated

Non–operated

Total

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Productive wells

550

365

388

351

162

14

550

365

Drilling and Completion Activities

The following tables present a summary of our operated development activity for the years indicated.

Development wells consist of wells completed and/or turned to sales during the period, regardless of when drilling was initiated.

Year Ended December 31,

2025

2024

Gross

Net

Gross

Net

Development wells turned to sales

33

30

8

6

In–progress development wells consist of wells which are in the process of being drilled or have been drilled and are waiting to be completed and/or for pipeline connection. All of the in–progress wells presented
below came online throughout the first quarter of 2026.

As of December 31, 2025

Gross

Net

Development in–progress wells

10

7

We did not have any exploratory drilling activities or any dry holes during the years ended December 31, 2025 and 2024.

Acreage

The following table presents certain information regarding the total developed and undeveloped acreage in which we own a working interest as of December 31, 2025. Acreage related to royalty, overriding royalty,
and other similar interests is excluded from this summary.

Developed Acres

Undeveloped

Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

DJ Basin

53,350

41,302

44,778

26,711

98,128

68,013

Certain leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to
such date, in which event the lease will remain in effect until the cessation of production.

The following table presents our undeveloped acreage, as of December 31, 2025, which will expire in the years indicated unless production is established within the spacing units covering the acreage or the
lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

Expiring 2026

Expiring 2027

Expiring 2028

Expiring 2029

and Beyond

Gross

Net

Gross

Net

Gross

Net

Gross

Net

DJ Basin

23,424

14,311

8,647

4,206

10,596

7,694

2,111

500

Approximately 14,311 net acres, or 21%, may expire in 2026 if production is not established or if we do not extend lease terms, of which approximately 2,269 net acres, or 16%, will be held by production by the
end of 2026, and approximately 3,544 net acres, or 25%, contain the extension terms, which we plan on exercising. We intend to extend our strategic leases to the extent possible. Decisions to let certain leaseholds expire generally relate
to areas outside of our core area of development or when the expirations do not pose material impacts to development plans or reserves.

10

Table of Contents

Title to Properties

Our properties are subject to customary royalty interests, overriding royalty interests, obligations incident to operating and joint venture agreements, liens for current taxes, other industry–related constraints,
and certain other leasehold restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business. We believe that we have satisfactory title to all of our producing
properties. Although title to our properties is subject to complex interpretation of multiple conveyances, deeds, reservations, and other instruments that serve to affect mineral title, we believe that none of these risks will materially
detract from the value of our properties or from our interest therein or otherwise materially interfere with the operation of our business.

Commodity Price Risks and Price Risk Management Activities

Production from our properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production are negotiated based on factors normally considered in the
industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. In an effort to reduce the impact of price volatility, and in compliance
with requirements under our Credit Facility, we enter into derivative contracts to economically hedge a portion of our estimated production from our proved, developed, producing oil and natural gas properties against adverse fluctuations in
commodity prices. By doing so, we believe we can mitigate, but not eliminate, the potential negative effects of decreases in oil and natural gas prices on our cash flows from operations. However, our hedging activity could reduce our
ability to benefit from increases in oil and natural gas prices. Further, we could sustain hedge losses to the extent our oil and natural gas derivative contract prices are lower than market prices and, conversely, we could recognize gains
to the extent our oil and natural gas derivative contract prices are higher than market prices. For additional information, refer to Part II – Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations.

Customers

We closed the Bayswater Acquisition in March 2025 and fully took over operations of the assets acquired in the Bayswater Acquisition in the third quarter of 2025. During the integration of the Bayswater
Acquisition, we renegotiated certain purchaser agreements associated with the assets acquired and as a result certain purchasers which were customers at the close of the acquisition are no longer customers. During the second half of 2025,
two of our largest customers accounted for approximately 83% and 10% of our oil, natural gas, and NGL revenues. While the loss of a single purchaser may result in a temporary interruption in sales of, or a lower price for, our production,
we do not believe the loss of any single purchaser would have a material impact our business because we believe we could readily find alternative purchasers in our producing region.

Transportation Commitments

As a result of the Bayswater Acquisition, we are party to an oil transportation agreement which includes a minimum volume commitment, requiring us to transport a fixed determinable quantity of crude oil on a
monthly basis. Under the terms of this agreement, we may be required to make periodic deficiency payments for any shortfalls in delivering the minimum gross volume to be transported by the counterparty. Additionally, one of our gas
gathering contracts requires a monthly guaranteed payment intended to reimburse the counterparty for costs incurred to connect to the gathering facility. Refer to Part II – Item 8. Financial Statements
and Supplementary Data – Note 12 – Commitments and Contingencies for additional discussion.

Competition

The oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that often have greater resources. Many of these companies explore for, produce, and market oil
and natural gas, carry on refining operations, and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our
drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, attracting and retaining qualified personnel, and obtaining transportation for the oil and natural gas we produce. There is
also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation
considered from time to time by federal, state, and local governments; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such
laws and regulations may, however, substantially increase the costs of exploring for, developing, or producing oil and natural gas and may prevent or delay the commencement or continuation of certain operations. The effect and potential
impacts of these risks are difficult to accurately predict.

11

Table of Contents

Regulation of the Oil and Natural Gas Industry

Our operations are affected by extensive federal, state, and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes,
and numerous other laws and regulations, including laws and regulations relating to environmental, health and safety matters. The jurisdictions in which we own and operate properties or assets for oil and natural gas production have statutory
provisions regulating the exploration for and development and production of oil and natural gas, including, among other things, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the
location of wells, the method of drilling and casing wells, the production and operation of wells and other facilities, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the
drilling and completion process, and the proper abandonment of wells and pipelines. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration
units, the number of wells that may be drilled in an area and the size of associated facilities, and the unitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and
that impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties and the suspension or cessation of operations. Our competitors in the oil and natural gas industry are generally
subject to similar regulatory requirements and restrictions to those which affect our operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial
compliance with all applicable laws and regulations, such laws and regulations are frequently revised and amended through various legislative actions and rulemakings. Therefore, we are unable to predict the future costs or impact of
compliance. Additional rulemakings, proposals and proceedings that affect the oil and natural gas industry are regularly considered at the federal, state, and various local government levels, including statutorily and through powers granted
to various agencies that regulate our industry, and various court actions. We cannot predict when or whether any such future rulemakings, proposals or proceedings may become effective or if the outcomes will negatively affect our operations.

We believe that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows, or results of operations. However, current regulatory
requirements may change, currently unforeseen environmental, health, or safety incidents may occur, or past noncompliance with environmental, health and safety laws or regulations may be discovered, any of which could have a material
adverse effect on our financial position, cash flows, or results of operations. Additionally, any other new requirements of the Colorado Energy & Carbon Management Commission (“CECMC”) or other federal, state and local governmental
bodies, could make it more difficult and costly to develop new oil and natural gas wells and to continue to produce existing wells, increase our costs of compliance and doing business, and delay or prevent development in certain areas or
under certain conditions. We cannot assure that the existing rules, as implemented, or any future rulemaking, will not have a material and adverse impact on our financial position, cash flows, or results of operations.

In addition, governmental, scientific, and public concern over the threat of climate change arising from increasing global emissions of greenhouse gases (“GHGs”) has resulted in higher political and regulatory
scrutiny in the U.S., including climate change–related pledges made by certain administrations. Former President Biden identified addressing climate change as a priority under his administration and issued executive orders in furtherance of
that priority. Although President Trump’s administration has eliminated many of the Biden–era restrictions, future administration changes could result in new restrictions on GHG emissions that directly or indirectly impact our exploration,
production, and development activities, or affect the demand for our products, which could have a material adverse effect on our business and financial position.

Regulation of Production of Oil, Natural Gas, and NGLs

The production of oil, natural gas, and NGLs is subject to regulation under a wide range of local, state, and federal statutes, rules, orders, and regulations. Federal, state, and local statutes and regulations
require, among other things, permits for drilling operations, drilling bonds, and reports concerning operations. Colorado, the state in which we own all of our properties, regulates drilling and operating activities by, among other things,
requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties
upon which wells are drilled and the plugging and abandonment of wells. The laws of Colorado also govern a number of conservation matters, including provisions for the spacing and unitization or pooling of oil and natural gas properties, the
establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing and well density, and procedures for proper plugging and abandonment of wells and associated facilities. These regulations
effectively identify well densities by geologic formation and the appropriate spacing and pooling unit size to effectively drain the resources. These regulations can have the effect of limiting the amount of oil, natural gas, and NGLs that we
can produce from our wells and limiting the number of wells or the locations where we can drill, although we can apply for exceptions to such regulations, including applications to increase well densities and reduce lease boundary setbacks to
more effectively recover oil and natural gas resources. Moreover, Colorado imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdiction.

Colorado also regulates drilling and operating activities by requiring, among other things, permits for new pad locations, the drilling of wells, best management practices and/or conditions of approval for
operating wells, maintaining bonding requirements in order to drill or operate wells, regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and
the plugging and abandonment of wells. Colorado laws also govern a number of environmental, health and safety matters that may impact our drilling and operating activities, including setbacks from buildings, schools, and other occupied areas,
sensitive habitats and/or disproportionately impacted communities, consideration of alternative locations for new wells, the handling and disposal of waste materials, haul routes, prevention of venting and flaring, mitigation of noise,
lighting, visual, odor, and dust impacts, air pollutant emissions permitting, protection of certain wildlife habitat, protection of public health, safety, welfare, and environment, and evaluation of cumulative impacts.

12

Table of Contents

Regulation of Transportation and Sales of Oil

Sales of oil, condensate, and NGLs from producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.

Our sales of crude oil are affected by the availability, terms, conditions and cost of transportation services. Transportation of oil in interstate commerce by common carrier pipelines is also subject to rate
and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act (“ICA”),
the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that
transport crude oil and refined products, be just and reasonable and non–discriminatory and that such rates and terms and conditions of service be filed with FERC.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny
given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil
transportation rates will not affect our operations in any way that is materially different from how it affects operations of our competitors who are similarly situated.

The Federal Trade Commission (“FTC”) has the authority under the Federal Trade Commission Act (“FTCA”) and the Energy Independence and Security Act of 2007 (“EISA”) to regulate wholesale petroleum markets.
The FTC has adopted anti–market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are
likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of approximately $1,510,803 as of 2025
(adjusted annually for inflation) per violation per day.

Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we
cannot predict what future action FERC or state regulatory bodies will take.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas
transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed
controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”), and by regulations and
orders promulgated by FERC under the NGA. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

FERC issued a series of orders in 1996 and 1997 to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been greatly reduced and replaced
by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster
increased competition within all phases of the natural gas industry.

13

Table of Contents

The federal Energy Policy Act of 2005 (“EPAct of 2005”) introduced significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct of 2005 amended the
NGA to add an anti–market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore, provides FERC with additional civil penalty authority. The EPAct of 2005
provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day,
with such penalties adjusted regularly for inflation. For example, in January 2025, the maximum penalty increased to $1,584,648 per violation per day to account for inflation. The civil penalty provisions are applicable to entities that
engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti–market manipulation provision of the EPAct of 2005, and subsequently denied rehearing. The
rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or
indirectly to: (1) use or employ any device, scheme, or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act or
practice that operates as a fraud or deceit upon any person. The anti–market manipulation rule does not apply to activities that relate only to intrastate or other non–jurisdictional sales or gathering. However, it does apply to activities
of gas pipelines and storage companies that provide interstate services, as well as otherwise non–jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases, or transportation subject to
FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti–market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

We are required to observe such anti–market manipulation laws and related regulations enforced by FERC under the EPAct of 2005 and those enforced by the Commodity Futures Trading Commission (“CFTC”) under the
Commodity Exchange Act, as amended (“CEA”), and CFTC regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce, as well as the market
for financial instruments on such commodity, such as futures, options, or swaps. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or
conditions that affect or tend to affect the price of a commodity. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1,487,712 as of 2025 (adjusted annually for inflation) or triple the
monetary gain to the violator for violations of the anti–market manipulation sections of the CEA. Should we violate the anti–market manipulation laws and regulations, we could also be subject to related third–party damage claims by, among
others, sellers, royalty owners and taxing authorities.

Natural gas gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering
facilities and services from regulation by FERC as a “natural gas company” under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non–jurisdictional gathering function or a jurisdictional
transportation function, FERC’s determinations as to the classification of facilities are done on a case–by–case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transportation facilities as
non–jurisdictional gathering facilities, and depending on the scope of that decision, our costs of delivering gas to point–of–sale locations may increase.

We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company.
However, the distinction between FERC–regulated transportation services and federally unregulated gathering services relies on a fact–intensive analysis that is the subject of ongoing litigation, so the classification and regulation of
our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress.

State regulation of natural gas gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory–take requirements. Although nondiscriminatory–take regulation
has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and
scrutiny given to intrastate natural gas pipeline rates and services vary from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable
basis, we believe that the regulation of similarly situated intrastate natural gas transportation in the state in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially
different from how it affects operations of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the
revenues we receive for sales of our natural gas.

Changes in law and to FERC and/or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines and intrastate pipelines. Changes in law and
to FERC and state utility commission policies and regulations also may result in increased regulation of our business and operations, and we cannot predict what future action FERC or any state utility commission will take. We do not believe,
however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers, and marketers with which we compete.

14

Table of Contents

Regulation of Environmental and Occupational Safety and Health Matters

Our operations are subject to stringent federal, state and local laws and regulations governing the occupational safety and health aspects of our operations, the discharge of materials into the environment, and
protection of the environment and natural resources (including threatened and endangered species and their habitats). Numerous governmental entities, including the U.S. Occupational Safety and Health Administration (“OSHA”), and U.S.
Environmental Protection Agency (the “EPA”) and analogous state agencies, such as the Colorado Department of Public Health and Environment (the “CDPHE”), have the power to enforce compliance with these laws and regulations and the permits
issued under them, often requiring costly investigation or actions. These laws and regulations may, among other things, (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types,
quantities and concentrations of various substances that can be released into the environment or injected into formations in connection with drilling and production activities; (iii) limit or prohibit drilling activities on certain lands
lying within wilderness, wetlands, and other protected areas; (iv) require remedial measures to prevent or mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) apply specific
health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the
assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining
performance of some or all of our operations.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be
subject, and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Handling Wastes

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non–hazardous solid wastes. Pursuant
to rules issued by the EPA, states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and other wastes associated with the exploration,
development and production of oil, natural gas, and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non–hazardous solid waste provisions,
state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non–hazardous solid wastes could be classified as hazardous wastes in the future. In addition, in
the course of our operations, we may generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have
hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or
the legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners or operators of the site where the release
occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or
the environment, and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighbouring landowners and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment. We may generate materials in the course of our operations that may be regulated as hazardous substances.

Water Discharges

The Clean Water Act (the “CWA”) and comparable state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of hazardous substances, into state
waters and waters of the United States (“WOTUS”). The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and
countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In
addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative,
civil and criminal penalties for noncompliance with discharge permits or other CWA requirements and analogous state laws and regulations.

The CWA also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by permit. The EPA and the U.S. Army Corps of Engineers (the “Corps”) have issued rules
attempting to clarify the federal jurisdictional reach over WOTUS since 2015, including the Navigable Waters Protection Rule during the first Trump administration, rules reverting back to the 1986 WOTUS definition during the Biden
administration, and rules reinstating the pre–2015 definition in January of 2023. However, in May 2023, the Supreme Court decided Sackett v. EPA, which sharply curtailed the EPA’s and Corps’
jurisdictional reach by limiting the types of wetlands that fell under WOTUS. Sackett codified the definition of WOTUS as only geographical features that are described in ordinary parlance as
“streams, oceans, rivers, and lakes” and to adjacent wetlands that are “indistinguishable” from those bodies of water due to a continuous surface connection. In September 2023, the EPA and the Corps published a direct–to–final rule
redefining WOTUS to amend the January 2023 rule and align with the decision in Sackett. The final rule eliminated the “significant nexus” test from consideration when determining federal
jurisdiction and clarified that the CWA only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water. The final rule is currently subject to challenges in federal
district courts. As such, uncertainty remains with respect to future implementation of the rule and any resulting litigation. In addition, in November of 2025, the EPA and the Corps issued a proposed rule to further narrow the scope of
federal jurisdiction under the CWA. It is likely that this proposed rule, if finalized, will also be challenged.

15

Table of Contents

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and
liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening WOTUS or adjoining shorelines. For example, operators of certain oil and natural gas facilities must
develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil
discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of
public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Subsurface Injections

In the course of our operations, we produce water in addition to natural gas, crude oil and NGLs. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non–producing
subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program
requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be
disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example,
in response to recent seismic events near below–ground disposal wells used for the injection of natural gas– and oil–related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased
seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional
requirements related to seismic safety. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies, as well as the owners of underground injection wells. Increased costs associated
with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability.

Air Emissions

The federal Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries, through air emissions standards, construction and operating
permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre–approval for the construction or modification of certain projects or facilities expected to produce or
significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential
to delay the development of our projects. Recently, there has been increased regulation with respect to air emissions from the oil and natural gas sector.

In June 2016, the EPA published final New Source Performance Standards (“NSPS”) at 40 CFR Part 60, Subpart OOOOa establishing new air emission controls for methane and volatile organic compound (“VOC”) emissions
from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, as an iteration to the previous standards at Subpart
OOOO. The EPA announced the latest iterations on these standards, Subpart OOOOb and OOOOc, on December 2, 2023. These rules require the phase–out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well
sites and compressor stations, as well as emissions standards for existing sources. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing
methane from existing sources followed by three years from the plan submission deadline for existing sources to comply. However, in July 2025, the EPA extended the two–year deadline to January 2027. The regulations are subject to legal
challenge and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. In addition, the new rules have been
appealed by various parties and it is also possible that the new presidential administration will seek to revise or retract these rules. As a result, future implementation of the standards is uncertain at this time.

The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air–quality permitting purposes applicable to the oil and natural gas
industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays
or require us to install costly pollution control equipment.

16

Table of Contents

Regulation of GHG Emissions

In response to findings in 2009 that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA,
including rules requiring the monitoring and annual reporting of GHG emissions from large GHG emission sources in the U.S., including certain onshore and offshore natural gas, oil and NGL production sources, which include certain of our
operations. An executive order, signed on January 20, 2025, instructed the EPA and other agency heads to brief the White House on the “legality and continuing applicability” of the 2009 endangerment findings. This could presage an attempt to
void the 2009 findings, which, if successful, could result in voiding many of the EPA’s rules for GHG emissions.

The EPA in July 2023 issued a proposed rule to expand the scope of its Greenhouse Gas Reporting Program for certain petroleum and natural gas facilities. The proposed rule would make the reach of the program
both broader and more granular, creating reporting obligations for a wider set of methane and other gas emissions events and requiring increased technical detail for certain other preexisting reporting obligations. The rule was finalized in
May of 2024 with an effective date of January 1, 2025. This rule could raise our costs of regulatory compliance. However, on September 12, 2025, the EPA proposed to permanently remove 46 source categories from GHG Reporting Program
requirements and to otherwise delay reporting for onshore petroleum and natural gas production until 2034.

In addition, the SEC issued a final rule in March 2024 that would mandate disclosure of climate–related risks, including financial impacts, physical and transition risks, related governance and strategy, and GHG
emissions, for certain public companies. Compliance dates under the final rule were to be phased in by registrant category with some filers required to incorporate the disclosures in fiscal year 2025 filings. However, the rule was
challenged and, in March of 2025, the SEC voted to withdraw its defense of the new disclosure rules. The rules have not been rescinded, although the U.S. Court of Appeals for the Eighth Circuit has ordered that litigation be held in
abeyance until such time as the SEC either reconsiders the rules or resumes its defense of the rules.

Also, the United Nations–sponsored Paris Agreement calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets.
However, the Paris Agreement does not impose any binding obligations on its participants. Former President Biden recommitted the U.S. to the Paris Agreement and, in April 2021, announced a goal of reducing the U.S.’ emissions by 50–52%
below 2005 levels by 2030. Incremental reduction measures have been agreed to at subsequent meetings, Conference of the Parties (“COP”) 26 held in Glasgow in November 2021, COP27 held in Sharm–El Sheik in November 2022, COP28 held in Dubai
in November to December 2023 and COP29 held in Baku in November 2024. Relatedly, the U.S. and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030
relative to 2020 levels, including “all feasible reductions” in the energy sector, which was reaffirmed at COP27. However, on January 20, 2025, President Trump signed an executive order to start the process of withdrawing the U.S. from the
Paris Agreement. This signals that the U.S. will also not provide funding or otherwise adhere to the nonbinding commitments made in subsequent COPs, although a future President may choose to rejoin the Paris Agreement.

In addition, the Inflation Reduction Act of 2022 (the “IRA”), signed by former President Biden in August 2022, provides significant funding and incentives for research and development of low–carbon energy
production methods, carbon capture, and other programs directed at addressing climate change. The IRA also includes a methane emissions reduction program that amends the CAA to include a Methane Emissions and Waste Reduction Incentive
Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. On
November 18, 2024, the EPA published a final rule imposing a charge for “waste methane” emissions from the oil and gas sector. The amount of the charge would have started at $900 per metric ton of methane emitted in 2024, $1,200 per metric
ton for emissions in 2025 and $1,500 per metric ton for 2026 and beyond. This rule may result in significant costs for our operations. However, in early 2025 Congress used the Congressional Review Act to void the implementing rule. A future
Congress could implement a similar methane charge in the future.

Although it is not possible at this time to predict how new laws or regulations that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal
requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or
restrict our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas, oil and NGLs we produce and lower the value of our reserves.

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of
storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

17

Table of Contents

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas, and NGLs from dense subsurface rock formations, and is used as part of our operations.
Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process.

From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing
process. Meanwhile, the regulation of hydraulic fracturing has continued at the state level. For example, Colorado has promulgated rules that require oil and natural gas operators to disclose the volume of water and all chemicals used during
the hydraulic fracturing process to an online registry.

In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal
requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

ESA and Migratory Birds

The federal Endangered Species Act (“ESA”) and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered,
restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas
where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. In June 2023, the Biden Administration
announced proposed revisions concerning the procedures and criteria used for listing, reclassifying, and delisting protected species, and designating critical habitat.

The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from
species protection measures, time delays or limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as
critical or suitable habitat, it could adversely impact the value of our leases.

OSHA

We are subject to the requirements of the OSHA and comparable state statutes, the purpose of which is to protect the health and safety of workers. In addition, OSHA’s hazard communication standard, the Emergency
Planning and Community Right–to–Know Act, comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information
be provided to employees, state and local governmental authorities and citizens.

State Laws

Our properties located in Colorado are subject to the authority of the CECMC, as well as other state agencies. Over the past several years, the CECMC has approved new rules regarding various matters, including
wellbore integrity, hydraulic fracturing, well control, waste management, spill reporting, spacing of wells and pooling of mineral interests, and an increase in potential sanctions for CECMC rule violations. We do not believe that any of
these CECMC rules will affect us in a way that materially differs from the way they will affect other oil and natural gas producers, gatherers, and marketers with which we compete.

In April 2019, Colorado Senate Bill 19–181 (“SB 181”) became effective, which substantially changes the state’s regulation of oil and natural gas exploration and production activities. SB 181 changed the CECMC’s
mission from “fostering” responsible and balanced development “consistent with protection” of public health and the environment to “regulating” development “to protect” public health and the environment. SB 181 also instituted several
state–wide regulatory changes, namely it: (i) changed Colorado’s statutory pooling provisions to require an applicant to own, or obtain the consent of, more than 45% of the applicable working or mineral interest, whereas previously the
consent of only one mineral interest owner was required; (ii) requires that, after production is established, an applicant must pay force–pooled working or mineral interest owners a 16% royalty on oil production and a 13% royalty on gas
production; (iii) changed state pre–emption law to afford local governments greater control over oil and natural gas siting; and (iv) initiated a comprehensive rulemaking to amend CECMC’s rules consistent with the agency’s revised mission.

Among the most significant changes under SB 181 was the aforementioned provision giving local governments greater control over facility siting and surface impacts associated with oil and natural gas development.
Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements. Further, local governments can inspect oil and
natural gas operations and impose fines for leaks and spills. Regulation in the municipalities and areas where we operate could result in increased costs, delays in securing permits and other approvals related to our operations, and
otherwise materially impact our ability to operate and drill new wells in the areas where we hold oil and natural gas interests.

18

Table of Contents

The CECMC has adopted significant additional regulations to implement SB 181. The legislation mandated CECMC rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are
inactive, temporarily abandoned or shut–in, financial assurance, wellbore integrity, and application fees. In November 2022, the CECMC completed a rulemaking on flowlines and wells that are inactive, temporarily abandoned, or shut–in and
completed a rulemaking on wellbore integrity in June 2020. In January 2021, the results of a major rulemaking took effect addressing a wide range of topics, including facility siting, cumulative impacts, development approvals, asset
transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection.
Those rules apply to permit applications pending on, or submitted after, the date the rule became effective, and generally to operations occurring on or after that date. The CECMC has also issued rules on financial assurance, application
fees, and high–priority habitat. The financial assurance rule increased the amounts that operators are required to provide as a surety bond to ensure that wells will be properly plugged and abandoned at the end of their lifecycle. On
October 15, 2024, the CECMC adopted new rules regarding the cumulative impacts of oil and natural gas operations, including increased scrutiny on a project’s proximity to other industrial sites, residential and school areas,
disproportionately impacted communities, and “cumulatively impacted communities.” The rules set GHG emissions intensity targets for oil and natural gas operators and require regulators to consider such targets in their cumulative impacts
analysis, as well as the potential to restrict operations during the summer in Ozone Nonattainment Areas. Depending on how these and any other new rules are applied and enforced, they could add substantial increases in well costs for our
Colorado operations. The rules could also impact our ability to operate and extend the time necessary to obtain drilling permits, which would create substantial uncertainty about future development plans.

SB 181 also required the CDPHE, in conjunction with the Air Quality Control Commission (“AQCC”), to undertake rulemaking efforts to minimize methane emissions and emissions of other hydrocarbons, volatile organic
compounds and nitrogen oxides associated with certain oil and natural gas facilities. The CDPHE and AQCC adopted more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and
maintenance frequencies, and for reducing emissions from pneumatic devices. In December 2019, the AQCC also expanded storage tank control and loadout control requirements. The legislation also grants the CDPHE and AQCC regulatory authority
over a broad range of oil and natural gas facilities during pre–production activities, drilling, and completion.

On December 20, 2024, the CDPHE adopted new rules to reduce GHG emissions from midstream oil and gas operations that the agency touted as “first–of–its–kind.” Under these rules, midstream operators must capture
and recover hydrocarbon emissions from activities such as pipeline pigging and blowdown of equipment. These new requirements may increase overall costs for the oil and gas industry in Colorado. It is possible that the CDPHE will propose
additional rules to reduce emissions from other segments of the oil and gas sector.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other activities and to
maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of
wells, pipelines and other operations.

For example, when obtaining a permit for new multi–well pads, the State of Colorado Oil and Gas Development Plans (“OGDP”) approval process may be pursued concurrently with the county approval process. Thirty days
prior to the initial filing for a permit, we are required to provide notice to relevant local government authorities and proximate local governments and schools within 2,000 feet of our proposed site. Following such notice, a development
plan may be filed, subject to potential requests for hearings and consultation, with such process lasting on average between 90 and 150 days. Upon approval by state authorities, a development plan will be subject to a 30–day public comment
period (or 45 days in the case of a plan contemplating drilling within 2,000 feet of a disproportionately impacted community), with such period subject to extension at the discretion of state authorities. Upon completion of the public
comment period, the CECMC Director will make a recommendation to approve, approve with conditions of approval, or deny the development plan. The CECMC will then hold a hearing to determine whether to approve, deny or stay an application 7
to 14 days after the recommendation of the CECMC Director. If the development plan is approved, drilling on the applicable pad may commence after a 60– to 90–day wellbore permitting administrative process.

Concurrent with the state approval process, the Weld Oil & Gas Location Assessment (“WOGLA”) application for construction of improvements related to oil and gas exploration and production in Weld County,
Colorado, will be subject to approval by the Weld County Oil and Gas Energy Department. Prior to the application, a meeting hosted by Weld County will review all alternate locations within the development area attended by all other relevant
state and local regulatory agencies. Following the pre–application meeting, a 30–day notice is submitted to Weld County stating a WOGLA application will be filed. Subsequently, a WOGLA application may be filed with a public intervention
period occurring 20 days prior to a hearing. The hearing for WOGLA applications is scheduled for a minimum of 45 days from the date of submission. The Weld County hearings officer will hear the WOGLA applications for approval, and upon such
approval, an order will be issued and a grading permit application must be filed prior to construction upon location.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of these activities. However, this insurance is limited to activities at
the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event
that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

19

Table of Contents

Intellectual Property

We do not currently own any intellectual property.

Employees

As of December 31, 2025, we employed 59 full–time employees. We have never experienced a work stoppage and believe we maintain positive relationships with our employees.

Offices

As of December 31, 2025, we have leased office space in Houston, Texas, where our principal office is located, and in Denver and Greeley, Colorado.

Available Information, Website and Availability of Public Filings

Our principal executive offices are located at 55 Waugh, Suite 400, Houston, Texas 77007. We also maintain an office in Denver, Colorado. Our website is located at www.prairieopco.com.

We furnish or file our Annual Reports on Form 10–K, our Quarterly Reports on Form 10–Q, our Current Reports on Form 8–K and amendments to such reports and other documents with the SEC under the Exchange Act. The
SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with
the SEC. We also make these documents available free of charge at www.prairieopco.com under the “Investor Relations” link as soon as reasonably practicable after they are filed or furnished with
the SEC.

Information on our website is not incorporated into this Annual Report or our other filings with the SEC and is not a part of them.

Our common stock is listed and traded on the Nasdaq Capital Market under the symbol “PROP.”