UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 2019

For the transition period from _______________ to _______________

Commission file number:  333-225927

Riviera Resources, Inc.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code

(281) 840-4000

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities

Act.     Yes ☐     No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes ☐     No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒     No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ☒     No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.       ☐

Indicate by check-mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes ☐     No ☒

Aggregate market value of the Company’s common stock held by non-affiliates of the registrant as of June 28, 2019, was $293,404,582 based on the closing price on the OTCQX Market.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒     No ☐

As of January 31, 2020, there were 58,037,642 shares of common stock, par value $0.01 per share, outstanding.

Documents Incorporated By Reference:

Portions of the registrant’s definitive proxy statement relating to its 2020 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2019, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Annual Report on Form 10‑K.

TABLE OF CONTENTS

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Glossary of Terms

As commonly used in the oil and natural gas industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:

Basin.  A large area with a relatively thick accumulation of sedimentary rocks.

Bbl.  One stock tank barrel or 42 United States gallons liquid volume.

Bcf.  One billion cubic feet.

Bcfe.  One billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Btu.  One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.

Development well.  A well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation.  A stratum of rock that is recognizable from adjacent strata consisting primarily of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.

MBbls.  One thousand barrels of oil or other liquid hydrocarbons.

MBbls/d.  MBbls per day.

Mcf.  One thousand cubic feet.

Mcfe.  One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

MMBbls.  One million barrels of oil or other liquid hydrocarbons.

MMBtu.  One million British thermal units.

MMcf.  One million cubic feet.

MMcf/d.  MMcf per day.

MMcfe.  One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

MMcfe/d.  MMcfe per day.

MMMBtu.  One billion British thermal units.

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

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NGL.  Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

Productive well.  A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves.  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves.  Reserves that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped drilling location.  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs.  Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.  Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Recompletion.  The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reservoir.  A porous and permeable underground formation containing a natural accumulation of economically productive natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Royalty interest.  An interest that entitles the owner of such interest to a share of the mineral production from a property or to a share of the proceeds there from.  It does not contain the rights and obligations of operating the property and normally does not bear any of the costs of exploration, development and operation of the property.

Spacing.  The number of wells which conservation laws allow to be drilled on a given area of land.

Standardized measure of discounted future net cash flows.  The after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the regulations of the Securities and Exchange Commission and discounted using an annual discount rate of 10%.

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, natural gas and NGL regardless of whether such acreage contains proved reserves.

Unproved reserves.  Reserves that are considered less certain to be recovered than proved reserves.  Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover.  Maintenance on a producing well to restore or increase production.

Zone.  A stratigraphic interval containing one or more reservoirs.

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Part I

This Annual Report on Form 10-K contains forward-looking statements based on expectations, estimates and assumptions as of the date of this filing.  These statements by their nature are subject to a number of risks and uncertainties.  Actual results may differ materially from those discussed in the forward-looking statements.  For more information, see “Cautionary Statement Regarding Forward-Looking Statements” included at the end of this Item 1. “Business” and see also Item 1A. “Risk Factors.”

References

Unless otherwise indicated or the context otherwise requires, references herein to the “Company,” “we,” “our,” and “us” refer (i) prior to the Spin-off (as defined below) to Linn Energy, Inc. (the “Parent”) and its consolidated subsidiaries, and (ii) after the Spin-off, to Riviera Resources, Inc. (“Riviera”) and its consolidated subsidiaries.  Unless otherwise indicated or the context otherwise requires, references herein to “LINN Energy” refer to Linn Energy, Inc. and its consolidated subsidiaries.  References to “Successor” relate to the financial position and results of operations of the Company subsequent to LINN Energy’s emergence from bankruptcy on February 28, 2017.  References to “Predecessor” relate to the financial position of the Company prior to, and results of operations through and including February 28, 2017.  Riviera is a successor issuer of the Parent pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

The reference to a “Note” herein refers to the accompanying Notes to Consolidated and Combined Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”

Overview

Riviera is an independent oil and natural gas company with a strategic focus on efficiently operating its mature low-decline assets, developing its growth-oriented assets, and returning capital to shareholders.  Riviera is quoted for trading on the OTCQX Market under the ticker “RVRA.”  The Company has two operating segments: upstream and Blue Mountain.

The Company’s upstream reporting segment properties are currently primarily located in two operating regions in the United States (“U.S.”): the Mid-Continent and North Louisiana.  Proved reserves at December 31, 2019, were approximately 316 Bcfe, of which approximately 89% were natural gas, 6% were natural gas liquids (“NGL”) and 5% were oil.  Approximately 90% were classified as proved developed, with a total standardized measure of discounted future net cash flows of approximately $159 million.  At December 31, 2019, the Company operated 1,446 or approximately 55% of its 2,635 gross productive wells.

In the first quarter of 2020, the Company completed the sale of its interests in non-operated properties located in the Drunkards Wash field in the Uinta Basin, the Overton field in East Texas and the Personville field in East Texas.  These properties are included in “assets held for sale” on the consolidated balance sheet as of December 31, 2019.  Reserve information as of December 31, 2019, includes amounts associated with these properties.  See Note 4 for additional information.

The Blue Mountain reporting segment consists of a state of the art cryogenic natural gas processing facility, a network of gathering pipelines and compressors and produced water services and a crude oil gathering system located in the Merge/SCOOP/STACK play, each of which is owned by Blue Mountain Midstream LLC (“Blue Mountain Midstream”), a wholly owned subsidiary of the Company.

In April 2018, the Parent announced its intention to separate Riviera from LINN Energy.  To effect the separation, the Parent and certain of its then direct and indirect subsidiaries undertook an internal reorganization (including the conversion of Riviera Resources, LLC from a limited liability company to a corporation named Riviera Resources, Inc.), following which Riviera holds, directly or through its subsidiaries, substantially all of the assets of LINN Energy, other than LINN Energy’s 50% equity interest in Roan Resources LLC (“Roan”).  A subsidiary of the Company held the equity interest in Roan until the Parent’s internal reorganization on July 25, 2018 (the “Reorganization Date”).  Following the internal reorganization, the Parent distributed all of the outstanding shares of Riviera common stock to the Parent’s shareholders on a pro rata basis (the “Spin-off”).  The Spin-off was completed on August 7, 2018.

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Prior to the Spin-off, the accompanying consolidated and combined financial statements were prepared on a stand-alone basis and derived from the Parent’s consolidated financial statements and accounting records for the periods presented as the Company was historically managed as a subsidiary of the Parent.

Historically, a subsidiary of the Company also owned a 50% equity interest in Roan.  The Company’s equity earnings (losses), consisting of its share of Roan’s earnings or losses, are included in the consolidated and combined financial statements through the Reorganization Date.  However, on the Reorganization Date, the equity interest in Roan was distributed to the Parent and is no longer affiliated with Riviera.  As such, the Company has classified the investment and equity earnings (losses) in Roan as discontinued operations on its consolidated and combined financial statements.  See Note 4 for additional information.  In December 2019, stockholders of Roan Resources, Inc. approved an Agreement and Plan of Merger (“Merger”) between Roan Resources, Inc. and a subsidiary of Citizen Energy Operating, LLC (“Citizen Operating”) under which Roan Resources, Inc., including its subsidiary Roan Resources LLC, became wholly owned subsidiaries of Citizen Operating.  The effective date of the Merger was December 6, 2019, and as a result of the Merger, the Company and Roan Resources, Inc. no longer share certain mutual directors and significant stockholders.

Strategy

Riviera is strategically focused on efficiently operating its mature low-decline assets, developing its growth-oriented assets, and returning capital to shareholders.  The Company has producing properties currently located primarily in Oklahoma and Louisiana.  The Company’s wholly owned subsidiary, Blue Mountain Midstream, is an emerging midstream company with assets in central Oklahoma focused on providing its customers with comprehensive natural gas, oil, natural gas liquids, and water solutions in a safe and environmentally sound manner, including gas and oil gathering and processing, water gathering and treatment, and delivery of product to lucrative downstream markets.  In the future, Blue Mountain Midstream looks to expand the scale and scope of its service capabilities in the Merge/SCOOP/STACK through organic growth and strategic acquisitions.

Recent Developments

Divestitures

Below are the Company’s completed divestitures in 2019:

On November 22, 2019, the Company completed the sale of its interest in the remaining properties located in the Hugoton Basin (the “Hugoton Basin Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $286 million. During the year ended December 31, 2019, the Company recorded a noncash impairment charge of approximately $100 million to reduce the carrying value of these assets to fair value. In connection with the Hugoton Basin Assets Sale, the buyer also acquired the Company’s interests in Mayzure, LLC, a wholly owned subsidiary of the Company, which was the counterparty to the volumetric production payment agreements based on helium produced from certain oil and natural gas properties in the Hugoton Basin.

Blue Mountain Midstream entered into an agreement with a potential customer to construct a gathering system, as well as gather and process gas.  During the third quarter of 2019, a decision was made not to proceed with the gas gathering and processing contract, and as a result, the customer reimbursed Blue Mountain Midstream for capital deployed and operating expenses incurred, in addition to paying a success fee for constructing the assets.  During the year ended December 31, 2019, Blue Mountain Midstream received a capital reimbursement of approximately $20 million.  Blue Mountain Midstream also received approximately $4 million for the success fee and the expense reimbursement, which is included in “(gains) losses on sale of assets and other, net” on the consolidated and combined statement of operations.

On September 5, 2019, the Company completed the sale of its interest in properties located in Illinois.  Cash proceeds from the sale of these properties were approximately $4 million and the Company recorded a net gain of approximately $4 million.

On August 30, 2019, the Company completed the sale of its interest in non-core assets located in North Louisiana.  Cash proceeds from the sale were approximately $2 million and the Company recorded a net gain of approximately $376,000.

On July 3, 2019, the Company completed the sale of its interest in properties located in Michigan (the “Michigan Assets Sale”).  Cash proceeds from the sale of these properties were approximately $39 million.  The Company recorded a noncash

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impairment charge to reduce the carrying value of these assets to fair value of approximately $18 million for the year ended December 31, 2019.

On May 31, 2019, the Company completed the sale of its interest in non-operated properties located in the Hugoton Basin in Kansas.  Cash proceeds received from the sale of these properties were approximately $29 million and the Company recognized a net loss of approximately $10 million.

On January 17, 2019, the Company completed the sale of its interest in properties located in the Arkoma Basin in Oklahoma.  Cash proceeds received from the sale of these properties were approximately $64 million (including a deposit of approximately $5 million received in 2018), and the Company recognized a net gain of approximately $28 million.

Divestitures – Subsequent Events

On January 15, 2020, the Company completed the sale of its interests in non-operated properties located in the Drunkards Wash field in the Uinta Basin (the “Drunkards Wash Asset Sale”).  Cash proceeds from the sale of these properties were approximately $4 million (including a deposit of approximately $450,000 received in 2019).

On January 31, 2020, the Company completed the sale of its interest in properties located in the Overton field in East Texas (the “Overton Assets Sale”).  Cash proceeds from the sale of these properties were approximately $17 million (including a deposit of approximately $2 million received in 2019).  During the year ended December 31, 2019, the Company recorded a noncash impairment charge of approximately $13 million to reduce the carrying value of these assets to fair value.

On February 14, 2020, the Company completed the sale of its interest in properties located in the Personville field in East Texas (the “Personville Assets Sale”).  Cash proceeds from the sale of these properties were approximately $29 million (including a deposit of approximately $3 million received in 2019).  During the year ended December 31, 2019, the Company recorded a noncash impairment charge of approximately $72 million to reduce the carrying value of these assets to fair value.

On November 20, 2019, the Company signed an agreement to sell its building located in Oklahoma City, Oklahoma for an amended contract price of $21 million.  The sale is expected to close in the first quarter of 2020.  During the year ended December 31, 2019, the Company recorded a noncash impairment charge of approximately $5 million to reduce the carrying value of this asset to fair value.

The assets and liabilities associated with the sale of the Oklahoma office building, the Drunkards Wash Asset Sale, the Overton Assets Sale and the Personville Assets Sale are classified as held for sale on the consolidated balance sheet at December 31, 2019.

2019 Oil and Natural Gas and Midstream Capital Expenditures

During the year ended December 31, 2019, the Company had total capital expenditures, excluding acquisitions, of approximately $172 million, including approximately $63 million related to its oil and natural gas capital program and approximately $105 million related to Blue Mountain Midstream.

2020 Oil and Natural Gas and Midstream Capital Budget

For 2020, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $52 million, including approximately $25 million related to its oil and natural gas capital program and approximately $27 million related to Blue Mountain Midstream.  This estimate is under continuous review and subject to ongoing adjustments.

Financing Activities

Riviera Credit Facility

Riviera’s credit agreement provides for a senior secured reserve-based revolving loan facility (the “Riviera Credit Facility”).  On September 27, 2019, the Company entered into an amendment to the Riviera Credit Facility to, among other things, extend its maturity date to August 4, 2021.  The amendment resulted in a borrowing commitment reduction from $230 million to $90 million, primarily due to asset sales, with the next scheduled borrowing base redetermination to occur on April 1, 2020.

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Blue Mountain Midstream Credit Facility

Blue Mountain Midstream’s credit agreement provides for a senior secured revolving loan facility (the “Blue Mountain Midstream Credit Facility”).  On February 8, 2019, the borrowing commitment under the Blue Mountain Midstream Credit Facility was increased to $200 million.  The Blue Mountain Credit Facility together with the Riviera Credit Facility, are referred to as the “Credit Facilities.”

Cash Distributions

On November 21, 2019, the Board of Directors of the Company declared a cash distribution of $4.25 per share.  A cash distribution totaling approximately $249 million was paid on December 12, 2019, to shareholders of record as of the close of business on December 5, 2019.  In addition, approximately $11 million for potential future distributions was recorded in restricted cash at December 31, 2019.  In December 2019, distributions payable of approximately $2 million related to outstanding share-based compensation awards was also recorded.  These amounts are included in “other accrued liabilities” and “asset retirement obligations and other noncurrent liabilities” on the consolidated balance sheet at December 31, 2019.

Share Repurchase Program

On July 18, 2019, the Company’s Board of Directors increased the share repurchase authorization to $150 million of the Company’s outstanding shares of common stock.  During the year ended December 31, 2019, the Company repurchased an aggregate of 8,475,514 shares of common stock at an average price of $12.72 per share for a total cost of approximately $108 million.  Included in this number are private purchases of 2,380,425 shares of common stock purchased at a discount to market, at an average price of $10.91 for a total cost of approximately $26 million.  See Note 12 for additional information.  For the period from January 1, 2020 through February 21, 2020, the Company repurchased 171,107 shares of common stock at an average price of $7.84 for a total cost of approximately $1 million.  At February 21, 2020, approximately $23 million was available for share repurchases under the program.  Any share repurchases are subject to restrictions in the Riviera Credit Facility.

Tender Offer

On June 13, 2019, the Company’s Board of Directors announced the intention to commence a tender offer to purchase $40 million of the Company’s common stock.  In July 2019, upon the terms and subject to the conditions described in the Offer to Purchase dated June 18, 2019, the Company repurchased an aggregate of 2,666,666 shares of common stock at a price of $15.00 per share for a total cost of approximately $40 million (excluding expenses of approximately $440,000 related to the tender offer).

Commodity Derivatives

During the year ended December 31, 2019, the Company entered into commodity derivative contracts consisting of natural gas fixed price swaps and NGL fixed price swaps for 2019 and oil fixed price swaps and natural gas basis swaps for 2020.  In July 2019, in connection with the closing of the Michigan Assets Sale, the Company canceled its MichCon natural gas basis swaps for 2019 and 2020.

Oil Services Agreement

On July 17, 2019, a subsidiary of Blue Mountain Midstream entered into an agreement with Roan to gather Roan’s oil in the Merge/SCOOP/STACK play.  The agreement provides for a 10-year term covering an 89,000 net acre dedicated area in nine Townships in central Oklahoma.  Blue Mountain plans to construct an initial crude system consisting of approximately 28 miles of gathering pipelines with two downstream interconnections providing Roan with direct access to the Cushing market.  The Blue Mountain system will initially be capable of transporting up to 60,000 barrels per day of crude oil.  Services will commence in the first half of 2020.  On December 6, 2019, Roan became a wholly owned indirect subsidiary of Citizen Operating.

Water Services Agreement

On January 31, 2019, a subsidiary of Blue Mountain Midstream entered into an agreement with Roan to exclusively manage all of Roan’s water needs for its drilling and completion operations in Central Oklahoma.  Blue Mountain Midstream provides comprehensive water management services including pipeline gathering, disposal, treatment and redelivery of recycled water for re-use.  The agreement is supported by a 10-year acreage dedication in 67 Townships covering portions of seven Oklahoma Counties.  On December 6, 2019, Roan became a wholly owned indirect subsidiary of Citizen Operating.

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Upstream Reporting Segment Operating Regions

The Company’s upstream reporting segment properties are currently primarily located in two operating regions in the U.S.:

In the first quarter of 2020, the Company completed the sale of its interests in non-operated properties located in the Drunkards Wash field in the Uinta Basin, the Overton field in East Texas and the Personville field in East Texas.  These properties are included in “assets held for sale” on the consolidated balance sheet as of December 31, 2019.  Reserve information as of December 31, 2019, includes amounts associated with these properties.  See Note 4 for details of the Company’s divestitures.

During 2019, the Company divested all of its properties located in the Hugoton Basin and Michigan/Illinois operating regions.  During 2018, the Company divested all of its properties located in the Permian Basin operating region.  During 2017, the Company divested all of its properties located in the California and South Texas operating regions.  As a result of the Company’s strategic exit from California in 2017 (completed by the sale of its interest in properties located in the San Joaquin Basin and the Los Angeles Basin in California), the Company classified the results of operations and cash flows of its California properties as discontinued operations on its consolidated and combined financial statements.

East Texas

At December 31, 2019, the East Texas region consisted of properties located in east Texas primarily producing natural gas from the Travis Peak, Cotton Valley and Bossier formations at depths ranging from 7,000 feet to 12,500 feet.  The Company’s properties in this region are primarily mature, low-decline natural gas wells.  To more efficiently transport its natural gas in east Texas to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 590 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area.

East Texas proved reserves represented approximately 40% of total proved reserves at December 31, 2019, all of which were classified as proved developed.  This region produced approximately 42 MMcfe/d of the Company’s 2019 average daily production.  During 2019, the Company invested approximately $1 million to develop the properties in this region.  As noted above, the majority of the Company’s properties located in East Texas are included in “assets held for sale” on the consolidated balance sheet as of December 31, 2019.

Mid-Continent

The Mid-Continent region consists of properties located in the Northwest STACK, as well as other Oklahoma properties.  The Company’s properties in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 3,500 feet to 19,000 feet.

Mid-Continent proved reserves represented approximately 22% of total proved reserves at December 31, 2019, all of which were classified as proved developed.  This region produced approximately 36 MMcfe/d of the Company’s 2019 average daily production.  During 2019, the Company invested approximately $9 million to develop the properties in this region and approximately $43 million in exploration activity.

North Louisiana

The North Louisiana region consists of properties located in north Louisiana and primarily producing natural gas from the Hosston, Cotton Valley, Bossier and Smackover formations at depths ranging from 7,000 feet to 12,500 feet.

North Louisiana proved reserves represented approximately 25% of total proved reserves at December 31, 2019, of which 61% were classified as proved developed.  This region produced approximately 31 MMcfe/d of the Company’s 2019 average daily production.  During 2019, the Company invested approximately $10 million to develop the properties in this region.

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Uinta Basin

Uinta Basin proved reserves represented approximately 13% of total proved reserves at December 31, 2019, all of which were classified as proved developed.  The Uinta Basin region produced approximately 18 MMcfe/d of the Company’s 2019 average daily production.  During 2019, the Company invested approximately $1 million to develop the properties in the Uinta Basin region.  As noted above, these properties are included in “assets held for sale” on the consolidated balance sheet as of December 31, 2019.

Blue Mountain Segment

Blue Mountain Midstream currently provides natural gas and oil gathering, compression and processing and produced water services to producers in the Merge/SCOOP/Stack play in the Mid-Continent Region of Oklahoma.  Blue Mountain Midstream’s assets primarily consist of the state of the art 250 MMcf/d design-capacity Cryo 1 natural gas plant as well as a network of natural gas gathering pipelines and compressors and produced water services (collectively, the “Blue Mountain System”).  Blue Mountain Midstream’s gathering and processing agreements for its gathering and processing system include long-term, fee-based or percent of proceeds contracts.  Based on Blue Mountain Midstream’s contracts, it gathers natural gas and NGLs from producers that it then processes and delivers to third party customers.

Blue Mountain Midstream is aggressively pursuing growth to its midstream business primarily in Oklahoma.  Additions to the Blue Mountain System are continually underway adding low and high-pressure gathering pipelines and interconnections that will accommodate incremental volume throughput.  During 2019, Blue Mountain Midstream invested approximately $102 million for plant and pipeline construction activities primarily associated with the Blue Mountain System.

Drilling and Acreage

The following table sets forth the wells drilled during the years indicated:

There were no lateral segments added to existing vertical wellbores during the years ended December 31, 2019, December 31, 2018, or December 31, 2017.  As of December 31, 2019, the Company had 14 gross (no net) wells in progress, and no wells were temporarily suspended.

This information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and the quantities or economic value of reserves found.  Productive wells are those that produce commercial quantities of oil, natural gas or NGL, regardless of whether they generate a reasonable rate of return.

Productive Wells

The following table sets forth information relating to the productive wells in which the Company owned a working interest as of December 31, 2019.  Productive wells consist of producing wells and wells capable of production, including wells

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awaiting pipeline or other connections to commence deliveries.  The number of wells below does not include approximately 2,331 gross productive wells in which the Company owns a royalty interest only.

Developed and Undeveloped Acreage

The following table sets forth information relating to leasehold acreage as of December 31, 2019:

Future Acreage Expirations

The Company’s investment in developed and undeveloped acreage comprises numerous leases.  The terms and conditions under which the Company maintains exploration or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property.  If production is not established or the Company takes no other action to extend the terms of the related leases, undeveloped acreage will expire.  The Company currently has no material undeveloped acreage due to expire during the next three years.

Programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration.  In some instances, the Company may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension.  In cases where additional time may be required to fully evaluate acreage, the Company has generally been successful in obtaining extensions.  The Company utilizes various methods to manage the expiration of leases, including drilling the acreage prior to lease expiration or extending lease terms.

Production, Price and Cost History

The Company’s natural gas production is primarily sold under short-term, market-sensitive contracts that are typically priced at the published natural gas index for the producing area plus or minus a differential attributable to the natural gas quality and the proximity to major consuming markets.  In certain circumstances, the Company has entered into natural gas processing contracts whereby the residue natural gas is sold under short-term contracts but the related NGL are sold under long-term contracts.  In all such cases, the residue natural gas and NGL are sold at market-sensitive index prices.  As of December 31, 2019, the Company had no natural gas or NGL delivery commitments under long-term contracts.

The Company’s natural gas production is sold to purchasers under spot price contracts, percentage-of-index contracts or percentage-of-proceeds contracts.  Under percentage-of-index contracts, the Company receives a percentage of the published index price for the producing area for its residue natural gas and NGL.  Under percentage-of-proceeds contracts, the Company receives a percentage of the resale price received by the purchaser for sales of residue natural gas and NGL

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recovered after transportation and processing of natural gas.  These purchasers sell the residue natural gas and NGL based primarily on spot market prices.

The Company’s natural gas is transported through its own and third-party gathering systems and pipelines.  The Company incurs processing, gathering and transportation expenses to move its natural gas from the wellhead to a purchaser-specified delivery point.  These expenses vary based on the volume, distance shipped and the fee charged by the third-party processor or transporter.

The Company’s oil production is primarily sold under short-term, market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser-posted prices for the producing area.  As of December 31, 2019, the Company had no oil delivery commitments under long-term contracts.

The following table sets forth information regarding total production, average daily production, average prices and average costs for each of the years indicated:

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The following table sets forth information regarding production volumes for fields with greater than 15% of the Company’s total proved reserves for each of the years indicated:

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Reserve Data

Proved Reserves

The following table sets forth estimated proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows at December 31, 2019, based on reserve reports prepared by independent engineers, DeGolyer and MacNaughton:

During the year ended December 31, 2019, the Company’s PUDs decreased to 32 Bcfe from 65 Bcfe at December 31, 2018, representing a decrease of approximately 33 Bcfe.  The decrease was primarily due to divestitures.  Reserves classified as PUDs at December 31, 2018, that were converted to proved developed reserves during the year ended December 31, 2019, were not material.

Based on the December 31, 2019, reserve reports, the amounts of capital expenditures estimated to be incurred in 2020, 2021 and 2022 to develop the Company’s PUDs are approximately $5 million, $5 million and $5 million, respectively.  The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and product prices.  None of the 32 Bcfe of PUDs at December 31, 2019, has remained undeveloped for five years or more.  All PUD properties are included in the Company’s current five-year development plan.

Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGL that cannot be measured exactly.  The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment.  Accordingly, reserve estimates may vary from the quantities of oil, natural gas and NGL that are ultimately recovered.  Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows.  The standardized measure of discounted future net cash flows should not be construed as the market value of the reserves at the dates shown.  The 10% discount factor required to be used under the provisions of applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry.  The standardized measure of discounted future net cash flows is materially affected by assumptions regarding the timing of future production, which may prove to be inaccurate.

The reserve estimates reported herein were prepared by independent engineers, DeGolyer and MacNaughton.  The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data provided by the Company.  When preparing the reserve estimates, the independent engineering firm did not independently verify the accuracy and completeness of the information and data furnished by the Company with respect to ownership interests, production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production.  However, if in the course of their work, something came to their

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attention that brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.  The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years.  The independent engineering firm also prepared estimates with respect to reserve categorization, using the definitions of proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of the Company’s reserve estimates in accordance with SEC regulations.  The preparation of reserve estimates was overseen by the Company’s Director of Reserves and Business Development who has a Master of Petroleum Engineering degree and 10 years of oil and natural gas industry experience.  The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer.  For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data.”  The Company has not filed reserve estimates with any federal authority or agency, with the exception of the SEC.

Operational Overview

General

The Company generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects intended to not only replace production, but also to add value through reserve and production growth and future operational synergies.  Many of the Company’s wells are completed in multiple producing zones with commingled production and long economic lives.

Principal Customers

For the year ended December 31, 2019, sales to ONEOK Hydrocarbon, L.P. accounted for approximately 19% of the Company’s total revenues.  If the Company were to lose any one of its major oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of its oil and natural gas in that particular purchaser’s service area.  If the Company were to lose a purchaser, it believes it could identify a substitute purchaser.  However, if one or more of the large purchasers ceased purchasing oil and natural gas altogether, it could have a detrimental effect on the oil and natural gas market in general and on the prices and volumes of oil, natural gas and NGL that the Company is able to sell.

Competition

The oil and natural gas industry is highly competitive.  The Company encounters strong competition from other independent operators in contracting for drilling and other related services, as well as hiring trained personnel.  The Company is also affected by competition for drilling rigs and the availability of related equipment.  In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases.  The Company is unable to predict when, or if, such shortages may occur or how they would affect its drilling program.

Operating Hazards and Insurance

The oil and natural gas industry involves a variety of operating hazards and risks that could result in substantial losses from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, and suspension of operations.  The Company may be strictly liable for environmental damages caused by previous owners of property it purchases and leases.  As a result, the Company may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds otherwise available, or result in the loss of properties.  In addition, the Company participates in wells on a non-operated basis, and therefore may be limited in its ability to control the risks associated with the operation of such wells.

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In accordance with customary industry practices, the Company maintains insurance against some, but not all, potential losses.  The Company cannot provide assurance that any insurance it obtains will be adequate to cover any losses or liabilities.  The Company has elected to self-insure for certain items for which it has determined that the cost of available insurance is excessive relative to the risks presented.  In addition, pollution and environmental risks generally are not fully insurable.  The occurrence of an event not fully covered by insurance could have a material adverse effect on the Company’s financial position, results of operations and cash flows.  For more information about potential risks that could affect the Company, see Item 1A. “Risk Factors.”

Title to Properties

Prior to the commencement of drilling operations, the Company conducts a title examination and performs curative work with respect to significant defects.  To the extent title opinions or other investigations reflect title defects on those properties, the Company is typically responsible for curing any title defects at its expense prior to commencing drilling operations.  Prior to completing an acquisition of producing leases, the Company performs title reviews on the most significant leases and, depending on the materiality of properties, the Company may obtain a title opinion or review previously obtained title opinions.  As a result, the Company has obtained title opinions on a significant portion of its properties and believes that it has satisfactory title to its producing properties in accordance with standards generally accepted in the industry.

Seasonality and Cyclicality

Seasonal weather conditions and lease stipulations can limit the drilling and producing activities and other operations in regions of the U.S. in which the Company operates.  These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations.  For example, the Company’s operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.

The demand for natural gas typically decreases during the summer months and increases during the winter months.  Seasonal anomalies sometimes lessen this fluctuation.  In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

The Company’s operations are subject to the same stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection as other companies in the oil and natural gas industry.  These laws and regulations may:

These laws and regulations may also restrict the production rate of oil, natural gas and NGL below the rate that would otherwise be possible.  The regulatory burden on the industry increases the cost of doing business and consequently affects

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profitability.  Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary fines or penalties, the imposition of investigatory or remedial requirements, and the issuance of orders enjoining future operations.  Moreover, accidental releases or spills may occur in the course of the Company’s operations, which may result in significant costs and liabilities, including third-party claims for damage to property, natural resources or persons.  Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly requirements for the oil and natural gas industry could have a significant impact on operating costs.

The environmental laws and regulations applicable to the Company and its operations include, among others, the following U.S. federal laws and regulations: