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Item 2. Properties

2022-03-16 compared with 2021-03-16 · 104 added, 79 removed, 210 unchanged (47% of the section changed)

General Background

Ring is currently engaged in oil and natural gas acquisition, exploration, development and production, with activities and operations currently in Texas and New Mexico.

While our business model includes pursuing acquisition opportunities, our near-term focus will be on the development of our existing properties.

Ring is currently engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in Texas and New Mexico.

Management’s Business Strategy Related to Properties

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In addition, as of December 31, 2021, we owned interests in approximately 22,722 gross (13,399 net) undeveloped acres.

While our near-term plans are focused towards drilling wells on our existing acreage to develop the potential contained therein, our long term plans also include continuing to evaluate acquisition and leasing opportunities.

While our near-term plans are focused towards drilling wells on our existing acreage to develop the potential contained therein, our long-term plans also include continuing to evaluate acquisition and leasing opportunities that can earn attractive rates of return on capital employed.

Pursuing Profitable Acquisitions

We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations.

We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties.

We have an experienced team of management and engineering professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.

We have an experienced team of management, engineering, geoscience, and land professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.

Summary of Oil and Natural Gas Properties and Projects

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Northwest Shelf –Yoakum, Runnels and Coke County, Texas and Lea County, New Mexico – In 2019, we acquired properties consisting of 49,754 gross (38,230 net) acres with an average working interest of 77% and an average net revenue interest of 58%.

As of December 31, 2020, our acreage position in these counties is 46,972 gross (32,915 net) acres with 11,723 gross (8,085 net) developed and held by production and 35,249 gross (24,830 net) being undeveloped.

As of December 31, 2021, our acreage position in these counties is 35,810 gross (25,655 net) acres with 17,950 gross (13,662 net) developed acres held by production and 17,860 gross (11,993 net) undeveloped acres.

Our reserve estimates include 79 identified proved horizontal drilling locations and 11 proved vertical drilling locations.

Our reserve estimates include the capital costs required to develop these wells.

We believe the Northwest Shelf leases contain a considerable number of remaining potential drilling locations.

Central Basin Platform - Andrews and Gaines County, Texas leases – In 2011, we acquired a 100% working interest and a 75% net revenue interest in the Company’s initial leases in Andrews and Gaines counties.

We believe the Northwest Shelf leases contain additional potential drilling locations.

Central Basin Platform - Andrews and Gaines County, Texas leases – In 2011, we acquired a 100% working interest and a 75% net revenue interest in our initial leases in Andrews and Gaines counties.

Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County and Gaines County leases.

The working interests range from 1-100% and the net revenue interests range from 1-88%.

In total as of December 31, 2020, we own 38,714 gross (25,362 net), acres with 23,668 gross (18,712 net) acres developed and held by production and the remaining 15,046 gross (6,650 net) acres being undeveloped.

Our reserve estimates include 2 proved vertical and 32 horizontal PUD wells.

In total as of December 31, 2021, we own 29,065 gross (20,288 net), acres with 24,203 gross (18,882 net) developed acres held by production and the remaining 4,862 gross (1,406 net) acres being undeveloped.

Our reserve estimates include 2 vertical and 38 horizontal PUD wells in this area.

Our reserve estimates include the capital costs required to develop these wells.

We believe the Central Basin Platform leases contain a considerable number of remaining potential drilling locations.

We believe the Central Basin Platform leases contain additional potential drilling locations.

Delaware Basin - Culberson and Reeves County, Texas leases – In 2015, we acquired properties consisting of 19,983 gross (19,679 net) acres with an average working interest of 98% and an average net revenue interest of 79%.

Since that time, we have acquired additional undeveloped acreage in and around our Culberson and Reeves County leases.

In total as of December 31, 2020, we own 18,769 gross (18,468 net) acres with 18,521 gross (18,256 net) acres developed and held by production and the remaining 248 gross (212 net) acres being undeveloped.

Our reserve estimates include 26 proved vertical and 4 horizontal PUD wells.

In total as of December 31, 2021, we own 18,729 gross (18,437 net) acres, all of which is developed and held by production (no undeveloped acreage).

Our reserve estimates include 5 vertical and 4 horizontal PUD wells.

Our reserve estimates include the capital costs required to develop these wells.

We believe the Delaware Basin leases contain a considerable number of remaining potential drilling locations.

We believe the Delaware Basin leases contain additional potential drilling locations.

Title to Properties

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With respect to our properties of which we are not the record owner, we rely on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.

Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other customary burdens, minor encumbrances, easements and restrictions.

Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to lending agreements, current taxes and other customary burdens, minor encumbrances, easements and restrictions.

We do not believe any of these burdens will materially interfere with our use of these properties.

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The following table summarizes our total net proved reserves, pre-tax PV-10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2021.

All of our reserves are in the Permian Basin in the States of Texas and New Mexico.

All of our reserves are in the Permian Basin in Texas and New Mexico.

Pre-Tax PV-10

Discounted Future

Net Cash Flows

1,332,097,625

1,137,364,848

(1) Six Mcf is the equivalent of one Boe.

(2) PV-10 is a non-GAAP financial measure.

See below for a reconciliation.

The Company presents the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Annual Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies.

PV-10 is a non-GAAP measure that differs from a measure under GAAP known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes.

PV-10 does not necessarily represent the fair market value of oil and natural gas properties.

PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows ( in thousands ):

Present value of estimated future net revenues

Future income taxes, discounted at 10%

Standardized measure of discounted future net cash flows

Reserve Quantity Information

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Balance, December 31, 2019

Extensions, discoveries and improved recovery

Revisions of previous quantity estimates

Balance, December 31, 2020

Purchase of minerals in place

Improved recovery

Extensions and discoveries

Extensions, discoveries and improved recovery

Sales of minerals in place

Upward revisions of estimates

Downward revision of estimates due to well performance

Downward revision of estimates due to commodity prices

Downward revision of estimates due to removal of undeveloped locations

Balance, December 31, 2019

Improved recovery

Upward revisions of estimates

Downward revision of estimates due to well performance

Downward revision of estimates due to commodity prices

Downward revision of estimates due to removal of undeveloped locations

Revisions of previous quantity estimates

Balance, December 31, 2021

(1) Six Mcf is the equivalent of one Boe.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2021, the Company’s extensions and discoveries of 4,838 MBOE resulted primarily from new proved undeveloped locations resulting from the 2021 operated drilling program in the Northwest Shelf and Central Basin Platform as well as non-operated activity in the Northwest Shelf.

Negative revisions of 2,172 MBOE were the result of Delaware PUD removal due to the 5 Year Rule, well performance, and increased cost from 2021 industry activity increase partially offset by commodity price increases.

Our proved oil and natural gas reserves are shown below.

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Our estimates of reserves and future cash flow as of December 31, 2021 and 2020 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2021 and 2020, respectively, in accordance with SEC guidelines.

As of December 31, 2020, our reserves are based on an SEC average price of $36.04 per Bbl of WTI oil posted and $1.99 per MMBtu Henry Hub natural gas.

As of December 31, 2021, our reserves are based on an SEC average price of $63.04 per Bbl of WTI oil posted and $3.598 per MMBtu of Henry Hub natural gas.

As of December 31, 2020, our reserves are based on an SEC average price of $36.04 per Bbl of WTI oil posted and $1.99 per MMBtu Henry Hub natural gas.

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Standardized Measure of Discounted Future Net Cash Flows

Future cash flows

Future cash inflows

4,853,709,000

2,682,488,655

3,825,773,515

Future production costs

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(821,515,126)

(964,887,856)

Future development costs

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(244,323,270)

(252,457,833)

Future income taxes

1 unchanged sentence

(208,645,934)

(424,715,966)

Future net cash flows

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1,408,004,325

2,183,711,860

10% annual discount for estimated timing of cash flows

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(852,133,072)

(1,260,536,809)

Standardized Measure of Discounted Future Net Cash Flows

1,137,364,848

The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Beginning of the year

Purchase of minerals in place

Improved recovery, less related costs

Extensions and discoveries, less related costs

Extensions, discoveries and improved recovery

Development costs incurred during the year

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(154,615,685)

(137,663,314)

Sales of minerals in place

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Net change in estimated future development costs

Upward revisions

Revision of previous quantity estimates as a result well performance

Revision of previous quantity estimates as a result of commodity prices

Revision of previous quantity estimates as a result removal of uneconomic proved undeveloped locations

Revision of estimated timing of cash flows

Revisions of previous quantity estimates

(126,143,669)

Changes in estimated timing of cash flows

(139,039,115)

(107,443,484)

Net change in income taxes

(112,496,394)

End of the Year

1,137,364,848

Our proved reserves by state as of December 31, 2021 are summarized in the table below.

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Future Capital

Pre-tax PV-10

Net Cash Flows

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Proved Reserves

We have approximately 76.5 million BOE of proved reserves, consisting of approximately 87% oil and 13% natural gas, as summarized in the table above as of December 31, 2020, on a net pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows basis.

We have approximately 77.8 million BOE of proved reserves, consisting of approximately 85% oil and 15% natural gas, as summarized in the table above as of December 31, 2021.

Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).

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Below is a description of the changes in our PUD reserves from December 31, 2020 to December 31, 2021.

During the year ended December 31, 2020, we incurred costs of approximately $10.0 million to convert 1,698,122 BOE of reserves from PUD to PD through development.

Other changes to our PUD reserves included:

● Upward revisions of 3,521,992 BOE as the result of a reduction in lease operating expenses in certain areas and improved offsetting production due to pump optimization and improved completion practices;

● Downward revisions of 1,794,900 BOE as the result of changes in commodity prices;

● Downward revision of 1,614,628 BOE for the removal of locations due to lack of development within the prescribed time frame due to changes in anticipated development programs as a result of market conditions

During the year ended December 31, 2021, we incurred costs of approximately $22.9 million to convert 2,899 MBOE of reserves from PUD to PD through development.

The increase in proved undeveloped reserves was primarily attributable to extensions of 4,110 MBOE resulting primarily from the 2021 operated drilling program in the Northwest Shelf and Central Basin Platform as well as non-operated activity in the Northwest Shelf.

The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development.

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CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.

Within CGA, the technical person primarily responsible for preparing the estimates set

forth in the CGA letter dated February 10, 2021, filed as an exhibit to this Annual Report on Form 10-K, was Mr.

Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated February 28, 2022, filed as an exhibit to this Annual Report on Form 10-K, was Mr.

Zane Meekins.

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Alex Dyes, is the technical professional primarily responsible for overseeing the preparation of our reserves estimates.

He has a Bachelor of Science degree in Petroleum Engineering with over 14 years of practical industry experience, including over 10 years of estimating and evaluating reserve information.

He has a Bachelor of Science degree in Petroleum Engineering from the University of Texas with over 15 years of practical industry experience, including over 11 years of estimating and evaluating

reserve information.

He is a member of the Society of Petroleum Engineers since 2013 and his qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.

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● utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates.

● ensuring compensation for the reserve engineers is not tied to the amount of reserves recorded.

Each quarter, the Executive Vice President of Engineering and Corporate Strategy presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives.

Additionally, the five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer, Chief Financial Officer, Executive Vice President of Operations, the Executive Vice President of Land, Legal, Human Resources, and Marketing, and the Executive Vice President of Engineering and Corporate Strategy.

Additionally, the five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer, Chief Financial Officer, Executive Vice President of Operations, and the Executive Vice President of Land, Legal, Human Resources, and Marketing.

The Corporate Reserves department works closely with independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates.

These independently developed reserves estimates are

presented to the Audit Committee.

These independently developed reserves estimates are presented to the Audit Committee.

In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves.

Summary of Oil and Natural Gas Properties and Projects

Production Summary

Our estimated average daily total Company net production for the month of December 2020 is 9,201 BOE/d.

The following table provides the calculation of this daily production rate for the month of December 2020.

Total production (BOE)

Daily production (Boe/d)

The following table summarizes gross and net developed and undeveloped acreage as of December 31, 2021 by region (net acreage is our percentage ownership of gross acreage).

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Undeveloped acreage

Central Basin Platform

Delaware Basin

Northwest Shelf

Production History

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Oil (per Bbl)

Central Basin Platform

Delaware Basin

Northwest Shelf

Natural gas (per Mcf)

Central Basin Platform

Delaware Basin

Northwest Shelf

Total (per Boe)

Average production cost (including ad valorem taxes) (per Boe)

Central Basin Platform

Delaware Basin

Northwest Shelf

Years Ended December 31,

Average lease operating expenses (per Boe)

Central Basin Platform

Delaware Basin

Northwest Shelf

Average gathering, transportation and

processing costs (per Boe)

Central Basin Platform

Delaware Basin

Northwest Shelf

Average ad valorem taxes (per Boe)

Central Basin Platform

Delaware Basin

Northwest Shelf

Average production taxes (per Boe)

The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels “Bbl”.

The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in thousand cubic feet “Mcf”.

The total average sales price amounts are calculated by dividing total revenues by total volume sold, in BOE.

Central Basin Platform

Delaware Basin

Northwest Shelf

The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels “Bbl.” The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in thousand cubic feet “Mcf.” The total average sales price amounts are calculated by dividing total revenues by total volume sold, in BOE.

The average production costs above are calculated by dividing production costs by total production in BOE.

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Drilling Activity

During 2020, we drilled 6 gross (5.61 net) wells in the Northwest Shelf in the Permian Basin.

We completed and placed on production 4 of these wells during the first quarter 2020.

Two wells were drilled in December 2020 and subsequently completed and placed on production during 2021.

All of these wells were successful and there were no dry wells.

The table below contains information regarding the number of wells drilled during the periods indicated.

During 2021, we drilled 11 gross (9.91 net) wells in the Northwest Shelf and Central Basin Platform in the Permian Basin.

We completed and placed on production each of these wells during 2021, and completed and placed on production two gross (1.998 net) wells that were drilled in December 2020.

In addition, Ring also participated in two gross (.23 net) non-operated wells in the Northwest shelf.

These wells were successful and there were no dry wells.

The table below contains information regarding the number of wells drilled and participated in during the periods indicated.

For the year ended December 31,

Present Activities

There were no wells in the process of being drilled, however, there were two wells waiting to be being completed as of December 31, 2020.

We had no wells in the process of being drilled or completed as of December 31, 2021.

Cost Information

We conduct our oil and natural gas activities entirely in the United States.

As noted in the table under “Production Prices and Production Costs”, our average production costs, per BOE, were $12.45, $12.28 and $11.49 during the years ended December 31, 2018, 2019 and 2020, respectively, and our average production taxes, per BOE, were $2.52, $2.31 and $1.63 for the years ended December 31, 2018, 2019 and 2020, respectively.

As noted in the table under “Production Prices and Production Costs”, our average production costs, per BOE, were $11.88 and $11.49 for the years ended December 31, 2021 and 2020, respectively, and our average production taxes, per BOE, were $2.93 and $1.63 for the years ended December 31, 2021 and 2020, respectively.

These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in BOE.

Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2019 and 2020 are shown below:

Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2021 and 2020 are shown below:

Wishbone Acquisition (1)

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Divestiture of proved properties

Acquisition of unproved properties

Exploration costs

Development costs

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Other Properties and Commitments

Our principal executive offices are in leased office space in The Woodlands, Texas.

The lease for this office space was entered into subsequent to December 31, 2020.

Prior to this and throughout 2020, our principal offices were in Midland, Texas.

Effective January 1, 2021, the Company moved its corporate headquarters to The Woodlands, Texas.

Prior to this, our principal offices were in Midland, Texas.

Those offices now serve as an operations office.

We also lease office space in Tulsa, Oklahoma, which serves as our current accounting office, but which will be closed following the transition of those functions to The Woodlands offices.

We expect our current office space to be adequate as we move forward.

Legal Proceedings

In the ordinary course of business, we may be, from time to time, a claimant or a defendant in various legal proceedings.

We do not presently have any material litigation pending or threatened requiring disclosure under this item.

Mine safety disclosures

Not applicable.

Our office space lease in Tulsa, Oklahoma was terminated as of March 31, 2021.

We expect our current office space to be adequate for the foreseeable future.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 2. Properties