What changed in this filing

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Item 2. Properties

2021-03-16 compared with 2020-03-16 · 80 added, 68 removed, 209 unchanged (41% of the section changed)

16 unchanged sentences

Significant Operations

Northwest Shelf – Gaines, 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%.

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.

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

Our reserve estimates include 69 proved horizontal and 13 non-operated horizontal PUD wells.

Our reserve estimates include 72 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.

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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.

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

Our reserve estimates include 40 proven vertical and 29 horizontal PUD wells.

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

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.

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%.

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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.

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

Our reserve estimates include 26 proved 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.

Title to Properties

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Summary of Oil and Natural Gas Reserves

As of December 31, 2019, our estimated proved reserves had a pre-tax PV10 value of approximately $6 million and a Standardized Measure of Discounted Future Cash Flows of approximately $455.9 million, 100% of which relates to our properties in the Permian Basin in Texas and New Mexico.

As of December 31, 2020, our estimated proved reserves had a pre-tax PV10 value of approximately $638.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $555.9 million, 100% of which relates to our properties in the Permian Basin in Texas and New Mexico.

We spent approximately $466.9 million on acquisitions and capital projects during 2019 and 2020.

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Net Cash Flows

1,102,795,800

The Company presents the pre-tax PV10 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.

Reserve Quantity Information

Our estimates of proved reserves and related valuations are based on internally prepared reports and audited by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.

The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Our oil and natural gas reserves are attributable solely to properties within the United States.

Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.

These reserves are attributable solely to properties within the United States.

A summary of the changes in quantities of proved (developed and undeveloped) oil and natural gas reserves is shown below.

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Extensions and discoveries

Sales of minerals in place

Upward revisions of estimates

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Downward revision of estimates due to removal of undeveloped locations

Downward revision of estimates due to removal of waterflood reserves

Balance, December 31, 2019

Purchase of minerals in place

Improved recovery

Extensions and discoveries

Sales of minerals in place

Upward revisions of estimates

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Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows.

This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our oil and natural gas properties.

Our reserve estimates as of December 31, 2019 are based on an average price of $52.41 for oil and $1.47 for natural gas compared to $58.74 for oil and $3.26 for natural gas as of December 31, 2018.

This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties.

Our estimates of reserves and future cash flow as of December 31, 2020 and 2019 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, 2020 and 2019, 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, 2019, our reserves are based on an SEC average price of $52.19 per Bbl of WTI oil posted and $2.58 per MMBtu Henry Hub natural gas.

Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.

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

Standardized Measure of Discounted Cash Flows

Standardized Measure of Discounted Future Net Cash Flows

Future cash flows

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(244,323,270)

(252,457,833)

Future income taxes

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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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(1,260,536,809)

Standardized Measure of Discounted Cash Flows

Standardized Measure of Discounted Future Net Cash Flows

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

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(368,974,767)

(219,608,128)

Net change in estimated future development costs

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

Revision of previous quantity estimates as a result removal of proved undeveloped locations due to changes in previously adopted development plans

(178,024,754)

Revision of estimated timing of cash flows

(139,039,115)

(107,443,484)

Net change in income taxes

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Our proved reserves by state as of December 31, 2020 are summarized in the table below.

Proved Reserves

Discounted Future

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Total Proved:

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.

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

As of December 31, 2019, approximately 53% of the proved reserves have been classified as proved developed producing, or “PDP”.

Proved developed non-producing, or “PDNP” reserves constitute approximately 5% and proved undeveloped, or “PUD”, reserves constitute approximately 42%, of the proved reserves.

As of December 31, 2019, our total proved reserves had a net pre-tax PV10 value of approximately $1.1 billion and a Standardized Measure of Discounted Future Net Cash Flows of approximately $923.2 million.

Approximately $651.0 million and $544.9 million, respectively, of total proved reserves are associated with the PDP reserves, which is approximately 59% of the total proved reserves’ pre-tax PV10 value.

An additional $62.8 million and $52.5 million, respectively, are associated with the PDNP reserves, which is approximately 6% of total proved reserves’ pre-tax PV10 value.

As of December 31, 2020, approximately 57.5% of the proved reserves have been classified as proved developed, or “PD” and the remaining 42.5% are proved undeveloped, or “PUD”.

As of December 31, 2020, our total proved reserves had a net pre-tax PV10 value of approximately $638.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $555.9 million.

Approximately $438.2 million and $381.8 million, respectively, of total proved reserves are associated with the PD reserves, which is approximately 69% of the total proved reserves’ pre-tax PV10 value.

The remaining $199.9 million and $174.1 million, respectively, are associated with PUD reserves.

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Below is a description of the changes in our PUD reserves from December 31, 2019 to December 31, 2020.

During the year ended December 31, 2019, we incurred costs of approximately $33.9 million to convert 6,046,028 BOE of reserves from PUD to PDP through development.

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:

● Purchase of minerals in place of 28,427,806 BOE, primarily from the Wishbone Acquisition;

● Sale of minerals in place of 709,208 BOE by selling a non-operated interest in wells and acreage acquired in the Wishbone Acquisition;

● Extensions and discoveries of 5,394,118 BOE;

● 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 2,794,713 BOE as the result of well performance due to reduction of offsetting production;

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

● Downward revision of 2,446,347 BOE for the removal of locations due to lack of development within the prescribed time frame as the result of changes in our development plan following the Wishbone Acquisition and the removal of locations added as part of the Wishbone Acquisition that were removed because the offsetting justification was inactive and had been reduced to a PDNP category.

● 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

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.

Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves

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

Estimated Oil

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Development Costs

Internal Controls Over Reserves Estimates

All of our proved reserves estimates shown in this Annual Report on Form 10-K at December 31, 2019, have been independently prepared by Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions.

Preparation and Internal Controls Over Reserves Estimates

All the proved oil and natural gas reserves disclosed in this report are based on reserve estimates determined and prepared by independent reserve engineers Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions.

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 January 30, 2020, 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 10, 2021, filed as an exhibit to this Annual Report on Form 10-K, was Mr.

Zane Meekins.

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he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The Company provides its third party independent consultants, including CGA, with full access to complete and accurate information pertaining to the property, and to all applicable personnel of the Company.

Our reserves estimates and process for developing such estimates are reviewed and approved by our Vice President of Operations, Daniel D.

Wilson, a petroleum engineer, and our Chief Executive Officer, Kelly Hoffman, to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of the third party consultants.

Wilson, a petroleum engineer and businessman, has over 30 years of experience in operating, evaluating and exploiting oil and natural gas properties.

Hoffman has over 40 years of well-rounded experience in the oil and natural gas industry.

Our management is ultimately responsible for reserve estimates and reserve disclosures and ensuring that they are in accordance with the applicable regulatory requirements and industry standards and practices.

Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature.

These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs.

The process also requires assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped reserves.

These reports should not be construed as the current market value of our reserves.

The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir.

Because of the uncertainties inherent in the interpretation of this data, we cannot be certain that the reserves will ultimately be realized and our actual results could differ materially.

The proved oil and natural gas reserves disclosed in this report are based on reserve estimates determined and prepared by independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells.

To establish reasonable certainty with respect to our estimated proved reserves, the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability.

Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area.

These wells were considered to be analogous based on production performance from the same formation and completions using similar techniques.

The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests.

This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers.

This consultation included review of properties, assumptions and available data.

Internal reserve estimates were compared to those prepared by independent reserve engineers to test the estimates and conclusions before the reserves were included in this report.

The accuracy of the reserve estimates is dependent on many factors, including the following:

● the quality and quantity of available data and the engineering and geological interpretation of that data;

● estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

● the accuracy of economic assumptions;

● the judgment of the personnel preparing the estimates.

Ring’s Executive Vice President of Engineering and Corporate Strategy, Mr.

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 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.

We encourage ongoing professional education for our engineers and analysts on new technologies and industry advancements as well as refresher training on basic skill sets.

In order to ensure the reliability of reserves estimates, the Corporate Reserves department follows comprehensive SEC-compliant internal controls and policies to determine, estimate and report proved reserves including:

● confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;

● ensuring the information provided by other departments within the Company such as Accounting is accurate;

● communicating, collaborating, and analyzing with technical personnel in our business units;

● comparing and reconciling the internally generated reserves estimates to those prepared by third parties;

● 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.

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.

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 production for the month of December 2019 is summarized below.

The following table indicates the percentage of our estimated December 2019 average daily production of 11,498 BOE/d attributable to oil versus natural gas production.

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2019 by region (net acreage is our percentage ownership of gross acreage).

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, 2020 by region (net acreage is our percentage ownership of gross acreage).

Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

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Total (per Boe)

Average production cost (per Boe)

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

Average production taxes (per Boe)

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Productive Wells

The following table presents our ownership at December 31, 2019, in productive oil and natural gas wells (a net well is our percentage ownership of a gross well).

The following table presents our ownership as of December 31, 2020 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well).

All of such wells are in the Permian Basin in Texas and New Mexico.

Drilling Activity

During 2019, we drilled 30 gross (29.33 net) wells in the Central Basin Platform, Delaware Basin and Northwest Shelf in the Permian Basin.

We completed and placed on production all 30 of these wells.

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 completed during the periods indicated.

Each of these wells was drilled in the Permian Basin, on the Northwest Shelf, Central Basin Platform or Delaware Basin.

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

For the year ended December 31,

(1) All of the wells drilled by the Company to date, with the exception of those wells included in the row for exploratory dry wells in the table above, have been development wells.

The Company considers the exploratory dry wells to be “science wells”.

“Science well” is a term used in the industry to describe a well that is drilled for purposes of determining the stratigraphic composition of a particular area, and is not intended to be completed to produce any oil or natural gas.

Since these exploratory wells have not been completed for production, we have designated them as dry wells.

Present Activities

There were no wells in the process of being drilled or awaiting completion as of December 31, 2019.

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.

Cost Information

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(1) Wishbone Acquisition in 2019 includes $28.3 million in fair value of stock issued as consideration in acquisitions.

(2) Acquisition of proved properties in 2018 includes $11.2 million in fair value of stock issued as consideration in acquisitions.

Other Properties and Commitments

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

The leased office space consists of approximately 15,000 square feet.

Additionally, we lease office space in Tulsa, Oklahoma which serves as our primary accounting office and consists of approximately 3,700 square feet.

We also lease office space in Andrews, Texas for a field office consisting of approximately 2,000 square feet.

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.

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.

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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