Riley Exploration Permian, Inc. - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - 8-K - Riley Exploration Permian, Inc.	nt10022719x2_8k.htm

Exhibit 99.1

Riley Exploration Permian, Inc. Disclosure as of April 7, 2021

As used in this Exhibit 99.1, unless the context indicates otherwise, references to “Riley,” the “Company,” “REPX,” “we,” “us,”, “our” and similar references refer to Riley Exploration Permian, Inc. (formerly known as Tengasco, Inc. or “Tengasco” or “TGC”) and its wholly owned subsidiaries, and references to “REP” refer to Riley Exploration – Permian, LLC, a wholly-owned subsidiary of the Company.

Explanatory Note

The information contained herein includes certain disclosure originally set forth in the Company’s Form S-4 (Registration No. 333-250019) and is included below, with certain contextual updates, to be incorporated by reference into a registration statement on Form S-3 to be filed by the Company on the date hereof. Except as otherwise indicated, the information in this document speaks as of REP’s fiscal year end of September 30, 2020.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this prospectus and the documents incorporated by reference herein may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should”, “could”, “may”, “will”, “believe”, “plan”, “intend”, “expect”, “potential”, “possible”, “anticipate”, “estimate”, “forecast”, “view”, “efforts”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included our 2020 Annual Report on Form 10-K, and those factors summarized below, as well as similar information incorporated by reference herein:

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fluctuations in the price we receive for our oil, gas, and NGL production, including local market price differentials;

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the impact of the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental and societal actions taken in response to the COVID-19 pandemic, and stay-at-home orders or illness that may cause interruptions to our operations;

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cost and availability of gathering, pipeline, refining, transportation and other midstream and downstream activities and our ability to sell oil, gas, and NGLs, which may be negatively impacted by the COVID-19 pandemic;

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severe weather and other risks and lead to a lack of any available markets;

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risks related to our recently completed merger, including challenges associated with integrating operations and diversion of management’s attention to merger-related issues;

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our ability to successfully complete mergers, acquisitions and divestitures;

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risks relating to our operations, including development drilling and testing results and performance of acquired properties and newly drilled wells;

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any reduction in our borrowing base from time to time and our ability to repay any excess borrowings as a result of such reduction;

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the impact of our derivative instruments and hedging activities;

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continuing compliance with the financial covenant contained in our amended and restated credit agreement;

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the loss of certain federal income tax deductions;

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risks associated with executing our business strategy, including any changes in our strategy;

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inability to prove up undeveloped acreage and maintaining production on leases;

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risks associated with concentration of operations in one major geographic area;

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deviations from our forecasts and budgets, including our 2021 capital expenditure budget;

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the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations to agree to, adhere to and maintain oil price and production controls;

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legislative or regulatory changes, including initiatives related to hydraulic fracturing, emissions, and disposal of produced water, which may be negatively impacted by the recent change in Presidential administration or legislatures;

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the ability to receive drilling and other permits or approvals and rights-of-way in a timely manner (or at all), which may be negatively impacted by the impact of COVID-19 restrictions on regulatory employees who process and approve permits, other approvals and rights-of-way and which may be restricted by new Presidential and Secretarial orders and regulation and legislation;

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risks related to litigation; and

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cybersecurity threats, technology system failures and data security issues.

Selected Historical Consolidated Financial Data of REP

The following tables summarize REP’s consolidated financial data. The selected historical financial data for the years ended September 30, 2020, 2019, 2018, 2017, and 2016 were derived from REP’s audited historical financial statements. You should read the following selected consolidated financial data together with “REP Management’s Discussion and Analysis of Financial Condition and Results of Operations” and REP’s consolidated financial statements and the related notes included elsewhere in this document or in our Form 8-K filed March 4, 2021. REP’s historical results are not necessarily indicative of results that should be expected in any future period.

Consolidated Statements of Operations Data
($ in thousands)	For the Years Ended September 30,
	2020			2019			2018			2017			2016
Revenues:
Oil and natural gas sales, net	$	73,133		$	101,096		$	69,872		$	21,808		$	4,130
Contract services – related		3,800			1,900			—			—			—
Total Revenues		76,933			102,996			69,872			21,808			4,130
Costs and Expenses:
Lease operating expenses		20,997			23,808			11,044			5,796			2,779
Gathering, processing & transportation		—			—			735			—			—
Production taxes		3,526			4,804			3,207			1,206			194
Exploration costs		9,923			5,074			5,992			11,882			45
Depletion, depreciation, amortization and accretion		21,479			20,182			15,714			5,876			1,366
General and administrative:
Administrative Costs		10,826			12,168			14,175			5,806			3,863
Unit-based compensation expense		963			898			—			—			—
Cost of contract services – related parties		503			21			—			—			—
Transaction Costs		1,431			4,553			878			1,766			—
Total Costs and Expenses		69,648			71,508			51,745			32,332			8,247
Income (Loss) From Operations	$	7,285		$	31,488		$	18,127		$	(10,524	)	$	(4,117	)
Other Income (Expense):
Interest expense		(5,299	)		(4,924	)		(1,707	)		—			—
Gain (loss) on derivatives		33,876			26,712			(17,143	)		(1,450	)		—
Total Other Income (Expense)		28,577			21,788			(18,850	)		(1,450	)		—
Net Income (Loss) Before Income Taxes		35,862			53,276			(723	)		(11,974	)		(4,117	)
Income tax expense		(718	)		(1,410	)		—			—			(9	)
Net Income (Loss)		35,144			51,866			(723	)		(11,974	)		(4,126	)
Dividends on preferred units		(3,535	)		(3,330	)		(3,129	)		(1,409	)		—
Net Income (Loss) Attributable to Common Unitholders	$	31,609		$	48,536		$	(3,852	)	$	(13,383	)	$	(4,126	)
Net Income (Loss) per Unit:
Basic	$	20.67		$	31.87		$	(2.57	)	$	(11.63	)		—
Diluted	$	17.24		$	26.03		$	(2.57	)	$	(11.63	)		—
Weighted Average Common Units Outstanding:
Basic		1,529			1,523			1,500			1,151			—
Diluted⁽¹⁾		2,038			1,992			1,500			1,151			—

(1)	For the fiscal year ended September 30, 2018, and September 30, 2017, Preferred and Restricted Units were excluded from the calculation of diluted net income (loss) per unit due to their anti-dilutive effect.

Consolidated Balance Sheet Data ($ in thousands)	As Of September 30,
		2020		2019		2018		2017		2016
Cash and cash equivalents	$	1,660	$	3,726	$	3,339	$	3,683	$	—
Oil and natural gas properties, net (successful efforts)		310,726		289,301		239,506		166,596		42,530
Total Assets	$	350,992	$	326,747	$	258,483		177,989		43,407
Revolving credit facility		101,000		97,000		53,500		—		—
Total Liabilities		124,083		120,554		97,555		16,640		6,087
Series A Preferred Units		60,292		56,810		53,529		49,823		—
Total Liabilities and Members’ Equity	$	350,992		326,747		258,483		177,989		43,407

Statement of Cash Flow Data

($ in thousands)

Year Ended

September 30,

	2020			2019			2018			2017			2016
Statement of Cash Flows Data:
Net cash (used) in/provided by operating activities	$	62,550		$	52,007		$	38,619		$	3,289		$	(9,125	)
Net cash used in investing activities	$	(51,521	)	$	(83,398	)	$	(88,389	)	$	(54,781	)	$	(24,087	)
Net cash (used) in/provided by financing activities	$	(13,095	)	$	31,778		$	49,426		$	55,175		$	33,212

RILEY EXPLORATION — PERMIAN, LLC BUSINESS

The following discussion should be read in conjunction with the “Selected Historical Financial Data” and the accompanying financial statements and related notes included elsewhere in this document and in our Form 8-K filed March 4, 2021 with the SEC.

References to REP’s estimated reserves are derived from REP’s reserve report as of September 30, 2020 prepared by Netherland, Sewell & Associates, Inc., or NSAI, and referred to as the NSAI Report.

Overview

REP is a capital efficient, independent oil and natural gas company focused on steadily growing its reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas, and natural gas liquids, or NGLs, reserves in the Permian Basin. REP’s objective is to maximize shareholder returns by generating stable free cash flow through steady oil-weighted production growth and industry-leading operating margins. Free cash flow will be allocated towards capital return to shareholders in the form of a quarterly cash dividend and/or capital spend to maximize production growth. REP intends to maintain a conservative balance sheet and low leverage.

REP was formed with the goal of building a premier exploration, development and production company, focusing on opportunities (i) with favorable reservoir and geological characteristics primarily for oil development, (ii) that offer large contiguous acreage positions with significant untapped potential in terms of ultimate recoverable reserves and (iii) with a high degree of operational control, which allows REP to execute its development plan based on projected well performance and commodity price forecasts in order to attempt to grow REP’s cash flow and generate significant equity returns from REP’s capital program. REP believes these characteristics enhance its horizontal production capabilities, recoveries and commercial outcomes, which enables REP to return capital to unitholders.

By nature of REP’s conventional assets’ low-decline profile, REP is able to maintain production with minimal capital spend. This allows REP to adapt to the market environment more ably and maximize efficient use of capital. Free cash flow generated in excess of maintenance capital expenditures provides REP optionality to (i) manage production growth prudently; (ii) maintain REP’s quarterly cash dividend; and (iii) grow both production and cash dividend per share.

REP’s acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, focused on the San Andres Formation on the Northwest Shelf. REP’s assets offset legacy Permian Basin San Andres fields, to include the Wasson and Brahaney Fields, which have produced more than 2.1 billion barrels of oil equivalent and 108.0 million barrels of oil equivalent, respectively, from the San Andres Formation since development in the area began in the 1930’s and 1940’s. Based on the close proximity to these productive fields, combined with the horizontal San Andres wells REP has drilled to date and the wells drilled by offset operators, REP believes it has significantly delineated its acreage.

REP has grown its average net production from 1,379 BOE/d for its fiscal year ended September 30, 2017 to an average net production of 7,081 BOE/d for REP’s fiscal year ended September 30, 2020, of which approximately 80% was oil, 10% was natural gas and 10% was NGLs. The annual volume increase is primarily due to the development of REP’s properties.

As of September 30, 2020, REP maintained operational control on approximately 90% of its net undeveloped acreage position which enables the horizontal drilling of long laterals, resulting in significant drilling efficiencies through strong operational and cost controls that REP believes improve its returns on capital employed and enhance the economic development of its acreage position. REP believes the ability to drill long-lateral wells improves REP’s returns by (i) increasing REP’s estimated ultimate recoveries, or EUR, per well, (ii) allowing REP to contact more reservoir rock with fewer wellbores thereby reducing drilling and completion costs on a per unit basis and (iii) allowing REP to hold more acreage per well drilled. Additionally, the contiguous nature of REP’s acreage provides economies of scale by allowing REP to better leverage its existing infrastructure. The following table provides summary information regarding REP’s proved, probable and possible reserves as of September 30, 2020, based on the NSAI Report.

Reserve Type	Oil (MBbls)⁽¹⁾		Natural Gas (MMcf)⁽¹⁾		NGL (MBbls)⁽¹⁾		Total (MBoe)⁽¹⁾		%Oil			% Liquids⁽²⁾			% Developed⁽³⁾
Proved Reserves		37,157.5		53,683.4		10,681.6		56,786.3		65	%		84	%		53	%
Probable Reserves		42,612.5		53,601.8		11,580.5		63,126.6		68	%		86	%		2	%
Possible Reserves		9,422.3		9,376.3		2,021.1		13,006.3		72	%		88	%		0	%

(1)	Prices used in this document are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2019 through September 2020. For oil and NGL volumes, the average West Texas Intermediate (WTI) spot price of $43.63 per barrel is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $1.967 per MMBTU is adjusted for energy content, transportation fees, and market differentials. As a reference, the average NYMEX WTI and NYMEX Henry Hub prices for the same period were $43.40 per barrel and $2.020 per MMBTU, respectively. For more information on the differences between the categories of proved, probable and possible reserves, see “—Oil and Natural Gas Data.”
(2)	Includes both oil and NGLs.
(3)	Includes both Proved Developed Producing and Proved Developed Non-Producing.

REP’s total well count was 130 gross producing (71 net) wells as of the fiscal year ended September 30, 2020, increasing from 119 gross (67 net) wells as of the fiscal year ended September 30, 2019. As of the fiscal year ended September 30, 2020, REP’s average working interest was 54% in the total 130 gross producing wells. Of these 130 gross producing wells, REP operated 63 gross wells, in which REP had an average working interest of 95%. REP’s strategy is to increase the number of wells REP operates in its undeveloped locations, and as a result increase REP’s average working interest over time.

In addition to REP’s 130 gross producing (71 net) wells, REP identified a total of approximately 330 gross (228 net) drilling locations across REP’s acreage as of September 30, 2020, 233 gross (174 net) of which represented proved, probable, or possible reserves. See “—Drilling Locations” for more information. REP’s gross and net remaining horizontal drilling locations as of September 30, 2020 relating to its proved, probable and possible locations are as follows:

Reserve Type	Gross Horizontal Drilling Locations		% by Reserve Type			Net Horizontal Drilling Locations		% by Reserve Type
Proved		69		30	%		50		29	%
Probable		117		50	%		97		56	%
Possible		47		20	%		27		15	%
Total		233		100	%		174		100	%

In addition to the 233 gross (174 net) proved, probable and possible locations above, as of September 30, 2020 REP has an additional 97 gross (54 net) drilling locations that are specifically identified locations in REP’s New Mexico Assets that have been identified by REP’s management team. Although these 97 gross (54 net) additional locations are determined using the same geologic and engineering methodology of location determination as those locations to which REP’s proved, probable, or possible reserves are attributed, they fail to satisfy all criteria for proved, probable and possible reserves for reasons such as development timing, economic viability at SEC pricing, and production volume certainty, REP believes that one of the benefits of its focus on conventional producing reservoirs where REP can apply its experience in horizontal drilling is the slower decline profile of most conventional reservoirs as compared to un-conventional shale production characteristics. As a result, REP believes that its production volumes can be maintained by deploying less capital to maintain our current production. For instance, REP believes that by maintaining a single rig operating in our acreage position in our Northwest Shelf assets, REP will not only hold its production flat but will increase overall production volumes.

While REP has continued to experience improved well performance as REP continues to learn more about its assets, and improve its drilling and production practices, REP’s historical well results support its belief that REP’s slower decline rates will provide it with a more stable production profile in the future.

REP’s Business Strategies

REP plans to achieve its primary objective—to increase shareholder value—by executing the following business strategies:

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Steadily grow production and generate sustainable free cash flow by developing its existing horizontal well inventory. REP considers its inventory of horizontal drilling locations to have relatively low development risk because of the information gained from REP’s operating experience on its acreage, industry activity by offset operators surrounding its acreage and historic activity on the San Andres Formation. REP intend to economically grow production, reserves and cash flow by utilizing its technical expertise to develop REP’s multi-year drilling inventory while efficiently allocating capital to maximize the value of REP’s resource base.

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Leverage its experience operating in the Permian Basin to maximize returns. REP was an early entrant to the horizontal development of the San Andres Formation of the Permian Basin. Substantially all of REP’s current properties are positioned in what REP believes to be the core of the horizontal San Andres Formation play in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, where horizontal production on the San Andres Formation has increased by more than 915% since January 2014. As of September 30, 2020, REP has operated or participated in 130 gross (71 net) wells, which affords it keen insight and expertise on the reservoir characteristics of the play. REP intends to leverage its management and technical teams’ experiences in applying unconventional drilling and completion techniques in the Permian Basin to maximize its returns.

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Maintain a high degree of operational control to continuously drive its operating costs lower and capture efficiencies. REP intends to maintain operational control of a substantial majority of its drilling inventory, by owning in excess of 50% of the working interest in the associated locations. REP believes that maintaining operating control enables it to steadily increase REP’s reserves while lowering REP’s per unit development costs, and allows REP to drive to its goal of free cash flow. REP’s control over operations and its ownership and operation of associated infrastructure for salt water disposal systems and electricity distribution allows REP to utilize what it believes to be cost-effective operating practices. These cost-effective practices include the selection of drilling locations, timing of development and associated capital expenditures and continuous improvement of drilling, completion and stimulation techniques.

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Maintain financial flexibility and apply a disciplined approach to capital allocation. REP seeks a capital structure with sufficient liquidity to execute its growth plans, while maintaining conservative leverage, and providing financial and operational flexibility through the various commodity price cycles. To achieve more predictable cash flow and reduce volatility during commodity price cycles, REP also enters into hedging arrangements for its crude oil production. REP expects to fund REP’s growth primarily through cash flow from operations. REP intends on taking advantage of its conservatively capitalized balance sheet to maintain its low-cost debt. Consistent with REP’s disciplined approach to financial management, REP has an active commodity hedging program that seeks to reduce REP’s exposure to downside commodity price fluctuations.

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Identifying accretive opportunities with disciplined, value enhancing framework. REP’s capital disciplined approach allows it to return capital while also growing its reserves, production and cash flow through REP’s return-focused organic growth opportunities driven by the exploration, development and production of oil, natural gas, and natural gas liquids, or NGLs, reserves. REP will seek to expand on its success in targeting contiguous acreage positions within the Northwest Shelf and particularly the San Andres Formation. REP has developed internal geologic models that incorporate publicly available third-party data, including well results and drilling and completion reports, to confirm REP’s geologic model and define the various core acreage positions of a play. Once REP believes that it has identified a core location, REP intends to execute on its acquisition strategy to establish a largely contiguous acreage position in proximity to the core. REP believes its evaluation techniques uniquely-position REP to better identify acquisition targets to grow its resource base and increase shareholder value.

REP’s Competitive Strengths

REP believes that the following strengths will allow REP to successfully execute its business strategies:

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Large contiguous asset base in one of North America’s leading oil resource plays. REP’s acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico, producing from the San Andres Formation, which is one of the most active areas in the Northwest Shelf. This acreage is characterized by a multi-year, oil-weighted inventory of horizontal drilling locations that REP believes provides attractive growth and return opportunities. As of September 30, 2020, REP had approximately 45,178 net acres (Champions 26,347 net acres and New Mexico 18,831 net acres). REP believes that its Champions Assets are located in the core of the Northwest Shelf, which have been substantially de-risked and expect to generate positive free cash flow. Most recent well results demonstrate that many of the wells on REP’s acreage are capable of producing single-well rates of return that are competitive with many of the top performing basins in the United States. As a result, REP believes it is well-positioned to continue to grow its reserves, production and cash flows in the current commodity price environment.

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Proven management team with substantial technical expertise. REP’s Chief Executive Officer, Bobby Riley, was one of the original designers of systems for down-hole data acquisition in gravel pack and frack pack operations and has more than 40 years of experience in the independent oil and gas sector. REP’s management and technical teams have a total of over 100 years of collective oil and gas experience, including significant experience in horizontal drilling in the Central Basin Platform and Northwest Shelf. This complements REP’s team’s prior experience in horizontal drilling in the Eagle Ford Shale play in South Texas, Wolfcamp play in the Permian Basin, Bakken Shale location in North Dakota and Barnett Shale location in North Texas, among other locations. REP believes its team’s technical capabilities and experience enhance REP’s horizontal drilling and production capabilities and ultimate well recoveries.

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High degree of operational control with reduced development costs. REP believes that maintaining operating control enables REP to increase its reserves while lowering its development costs. REP’s control over operations also allows REP to determine the selection of drilling locations, timing of development and associated capital expenditures and continuous improvement of drilling, completion and stimulation techniques. For example, REP has made the strategic decision to own and operate the salt water disposal systems and electricity distribution infrastructure necessary to support operations. This has allowed REP to significantly reduce its operating costs and keep pace with its expected development program. In addition, all of the Champions Assets are dedicated to a third-party crude and natural gas gathering system with the contracts structured as acreage dedications, which allows REP to avoid fees or penalties associated with minimum volume commitments. REP believes these factors will contribute to its ability to grow production and maintain positive free cash flows even in lower commodity price environments.

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Conservative balance sheet. REP expects to maintain financial flexibility that will allow REP to continue its development activities by funding capital expenditures with operating cash flow. REP also has an active commodity hedging program that seeks to reduce REP’s exposure to downside commodity price fluctuations as part of its maintenance of a conservative financial management program. After giving effect to the merger, REP expects to have approximately $100 million of outstanding debt. At current commodity prices, REP expects to generate positive free cash flow over the calendar year 2021 while also growing production. REP intends to utilize its positive free cash flow to pay down debt and return capital to shareholders.

REP’s Properties

As of September 30, 2020, substantially all of REP’s properties were located in Yoakum County, Texas on the Northwest Shelf sub-basin of the Permian Basin and Chaves, Lea and Roosevelt Counties, New Mexico. REP’s acreage is primarily located on large, contiguous blocks in Yoakum County, Texas on the San Andres Formation, which is a shelf margin deposit on the Central Basin Platform and Northwest Shelf. As of September 30, 2020, REP’s acreage position consisted of 45,178 net acres, all of which target the San Andres Formation. Additionally, approximately 42% of REP’s net acreage is held by production and 9% held by obligations, respectively. Unless production is established within the spacing units covering the remaining acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates, the leases will expire in accordance with their respective terms. See “—Developed and Undeveloped Acreage” below.

REP’s estimated total proved, probable and possible reserves at September 30, 2020 based on the NSAI Report were approximately 56,786, 63,127 and 13,006 MBoe, respectively. As of September 30, 2020, REP had a total of 130 gross producing (71 net) wells, of which all were horizontal wells and REP’s proved reserves had a PV-10 of $306MM. REP’s average net daily production during fiscal year ended September 30, 2020 was approximately 7,081 BOE/d. As of September 30, 2020, REP had an average working interest of 54% in 130 total gross producing wells and an average working interest of 95% in 63 operated gross wells. REP’s strategy is to operate wells in its undeveloped locations, and as result REP’s average working interest is expected to increase further over time.

REP continues to expand its proved reserves in this area by drilling undeveloped horizontal locations. As of September 30, 2020, REP had an identified drilling inventory of approximately 330 gross (228 net) undeveloped horizontal drilling locations of which 69 gross (50 net) are PUDs with varying lateral lengths on REP’s acreage with average well costs of $3.7 million ($3.0 million normalized to 5,200 foot lateral length). During fiscal years 2020, 2019 and 2018, REP drilled and completed 12, 20 and 25 gross horizontal wells, respectively.

Permian Basin and Sub-Basin References

References herein to the “Permian Basin” or the “Central Basin Platform” or the “Northwest Shelf” or the “San Andres Formation” refer to those areas defined by the Railroad Commission of Texas, or the TRRC. The TRRC defines the (i) Permian Basin as an oil-and-gas producing area located in West Texas and the adjoining area of southeastern New Mexico covering an area approximately 250 miles wide and 300 miles long, and encompasses several sub-basins, including the Delaware Basin, Midland Basin, Central Basin Platform and Northwest Shelf; (ii) Central Basin Platform as a sub-basin of the Permian Basin; (iii) Northwest Shelf as a sub-basin of the Permian Basin; and (iv) San Andres Formation as a shelf margin deposit composed of dolomitized carbonates.

Drilling Locations

REP and its predecessor entities have a long history in the Permian Basin, where, as of September 30, 2020, REP has assembled approximately 66,671 gross leasehold acres (approximately 45,178 net) and have over 330 gross (228 net) specifically identified drilling locations for potential future drilling. As of September 30, 2020, approximately 233 gross (174 net) of these drilling locations represented proved, probable and possible reserves. These locations were developed using existing geologic and engineering data. The additional 97 gross (54 net) drilling locations are specifically identified locations in REP’s New Mexico Assets that have been identified by REP’s management team. Although these 97 gross (54 net) additional locations are determined using the same geologic and engineering methodology of location determination as those locations to which REP’s proved, probable, or possible reserves are attributed, they fail to satisfy all criteria for proved, probable and possible reserves for reasons such as development timing, economic viability at SEC pricing, and production volume certainty. In evaluating and determining those locations, REP also considered the availability of local infrastructure, drilling support assets, property restrictions and state and local regulations. The drilling locations that REP actually drills will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors, and may differ from the locations currently identified. Any drilling activities REP is able to conduct on these identified locations may not be successful and may not result in additional proved reserves. Further, to the extent the drilling locations are associated with acreage that expires, REP would lose its right to develop the related locations.

Production Status

For REP’s fiscal year ended September 30, 2020, REP’s average net daily production was 7,081 BOE/d, of which approximately 80% was oil, 10% was natural gas and 10% was NGLs. As of September 30, 2020, REP’s producing well count was 130 gross producing (71 net) wells.

Facilities

REP’s land-based oil and gas processing facilities are typical of those found in the Permian Basin. REP’s facilities located at well locations or centralized lease locations include saltwater disposal wells and associated gathering lines, storage tank batteries, oil/gas/water separation equipment and pumping equipment. In addition, REP owns a substantial majority of the electrical power infrastructure on its acreage position, which include power distribution lines and equipment.

Recent and Future Activity

As of September 30, 2020 REP produced from 130 gross (71 net) wells that included both its operated and non-operated wells combined. This represented an increase of 11 gross (3 net) wells, which includes the addition of 22 gross (13.7 net) wells, and the subtraction of 11 gross (10.3 net) wells from REP’s producing well count. During the fiscal year ended September 30, 2020, REP incurred capitalized costs of $49 million, of which approximately $35.7 million was allocated for drilling and completion activity, approximately $4.3 million for continued infrastructure buildout (e.g. saltwater disposal and electrical infrastructure), approximately $5.3 million for leasehold acquisition and renewal efforts, and approximately $3.6 million for capitalized workovers.

REP’s fiscal 2021 capital budget is $50 million, of which approximately $32.5 million is allocated for drilling and completion activity for an estimated 11 gross (8.5 net) wells, $11.6 million completion activity for drilled but uncompleted wells for an estimated 5 gross (4.7 net) wells, approximately $1.0 million for continued infrastructure buildout (e.g. saltwater disposal and electrical infrastructure), approximately $2.5 million for capitalized workovers, and approximately $2.4 million in other expenditures such as leasehold acquisition and renewal efforts. REP’s capital budget excludes any amounts that may be paid for future acquisitions. The wells are expected to be drilled at an estimated average drilling and completion gross well cost of $3.5 million to $4.3 million per horizontal well with completed lateral lengths ranging from 4,500 to 7,300 feet. In this document, REP defines identified potential drilling locations as locations specifically identified by management based on evaluation of applicable geologic and engineering data accrued over REP’s multi-year historical drilling activities, in addition to what is credited in the NSAI Report. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant are considered in determining such locations. The drilling locations on which REP actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

Oil and Natural Gas Data

Evaluation and Review of Reserves. REP’s historical reserve estimates as of September 30, 2020 were prepared based on a report by NSAI, REP’s independent petroleum engineers, which REP refers to as the NSAI Report. Within REP, the technical person primarily responsible for overseeing the preparation of the estimates for REP is Mr. Kevin Riley. Mr. Kevin Riley has been with REP since 2016 and has over 13 years of industry experience. Mr. Kevin Riley holds a degree in Business Administration from the University of Central Oklahoma and a Master of Business Administration with emphasis in Energy from the University of Oklahoma. He is a member of the Independent Petroleum Association of America, American Association of Petroleum Landmen and the Society of Petroleum Engineers. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein is Mr. James E. Ball. Mr. Ball, a Licensed Professional Engineer in the State of Texas (No. 57700), has been practicing consulting petroleum engineering at NSAI since 1998 and has over 17 years of prior industry experience. He graduated from Texas A&M University in 1980 with a Bachelor of Science Degree in Petroleum Engineering. The technical principal meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in any of REP’s properties, nor is it employed by REP on a contingent basis.

Internal Controls. REP maintains an internal staff of petroleum engineers and geoscience professionals who worked closely with REP’s independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate REP’s reserves relating to REP’s assets in the Permian Basin. REP’s internal technical team members meet with REP’s independent reserve engineers periodically during the period covered by the NSAI Report to discuss the assumptions and methods used in the proved reserve estimation process. The qualifications of the technical person(s) primarily responsible for overseeing the preparation of the estimates of REP’s reserves are set forth in “—Evaluation and Review of Reserves”. REP provides historical information to the independent reserve engineers for REP’s properties, such as ownership interest, oil and natural gas production, well test data, commodity prices, and operating and development costs.

The preparation of REP’s reserve estimates is completed in accordance with REP’s internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•	review and verification of historical production data, which data is based on actual production as reported by REP;
•	preparation of reserve estimates; and
•	verification of property ownership by REP’s land department.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known SEC rules, proved reserves are those quantities of oil and natural gas, which, 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, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of REP’s proved reserves as of September 30, 2020 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for REP’s properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

To estimate economically recoverable proved reserves and related future net cash flows, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to REP’s estimated proved reserves, the technologies and economic data used in the estimation of REP’s proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, historical well cost and operating expense data.

Estimation of Probable and Possible Reserves.

Estimates of probable reserves are inherently imprecise and are more uncertain than proved reserves, but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed either together or with estimates of proved reserves. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

REP attributes the probable category to wells within REP’s acreage that are on strike or above two or more bounding proved wells where REP has reasonable certainty of continuity of the reservoir between those proved wells based on the available geoscience data, but that REP is more than one undeveloped location away from any proved location.

Estimates of possible reserves are also inherently imprecise and are more uncertain than proved reserves, but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed either together or with estimates of proved reserves. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserve where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir. Possible reserves also include incremental quantities associated with a greater percentage of recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and REP believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

REP attributes the possible category to areas where REP has offset proved production but that more than one location away REP is less certain of the vertical and lateral limits of the reservoir. This is typically on the edge of the field where REP does not have the locations bound by proved production on all sides and geoscience data is too sparse to clearly define a commercial boundary.

Summary of Oil, Natural Gas and NGL Reserves. The following table summarizes REP’s estimated proved, probable and possible reserves at September 30, 2020 from the NSAI Report and based on SEC pricing.

	As of September 30, 2020⁽¹⁾
Proved Reserves:
Oil (MBbls)		37,157.5
Natural Gas (MMcf)		53,683.4
Natural Gas Liquids (MBbls)		10,681.6
Total Proved Reserves (MBoe)		56,786.3
Proved Developed Producing Reserves:
Oil (MBbls)		19,149.0
Natural Gas (MMcf)		31,137.5
Natural Gas Liquids (MBbls)		5,847.1
Proved Developed Producing Reserves (MBoe)		30,185.7
Proved Developed Producing Reserves as a % of Proved Reserves		53	%
Proved Developed Non-Producing Reserves:
Oil (MBbls)		—
Natural Gas (MMcf)		—
Natural Gas Liquids (MBbls)		—
Proved Developed Non-Producing Reserves (MBoe)		—
Proved Developed Non-Producing Reserves as a % of Proved Reserves		—
Proved Undeveloped Reserves:
Oil (MBbls)		18,008.6
Natural Gas (MMcf)		22,545.9
Natural Gas Liquids (MBbls)		4,834.5
Proved Undeveloped Reserves (MBoe)		26,600.7
Proved Undeveloped Reserves as a % of Proved Reserves		47	%
Probable Reserves:⁽²⁾
Oil (MBbls)		42,612.5
Natural Gas (MMcf)		53,601.8
Natural Gas Liquids (MBbls)		11,580.5
Total Probable Reserves (MBoe)		63,126.6
Probable Developed Non-Producing Reserves:⁽²⁾
Oil (MBbls)		704.3
Natural Gas (MMcf)		967.6
Natural Gas Liquids (MBbls)		210.4
Probable Developed Non-Producing Reserves (MBoe)		1,076.0
Probable Undeveloped Reserves:⁽²⁾
Oil (MBbls)		41,908.2
Natural Gas (MMcf)		52,634.2
Natural Gas Liquids (MBbls)		11,370.1
Probable Undeveloped Reserves (MBoe)		62,050.6
Possible Reserves:⁽³⁾
Oil (MBbls)		9,422.3
Natural Gas (MMcf)		9,376.3
Natural Gas Liquids (MBbls)		2,021.2
Possible Undeveloped Reserves (MBoe)		13,006.3

(1)	Prices used in this document are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2019 through September 2020. For oil and NGL volumes, the average West Texas Intermediate (WTI) spot price of $43.63 per barrel is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $1.967 per MMBTU is adjusted for energy content, transportation fees, and market differentials. As a reference, the average NYMEX WTI and NYMEX Henry Hub prices for the same period were $43.40 per barrel and $2.020 per MMBTU, respectively. For more information on the differences between the categories of proved, probable and possible reserves, see “Oil and Natural Gas Data.”
(2)	REP’s estimated probable reserves are classified as both developed non-producing and as undeveloped.
(3)	All of REP’s estimated possible reserves are classified as undeveloped.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs.

Additional information regarding REP’s reserves can be found in the notes to REP’s financial statements included in our Form 8-K filed with the SEC on March 4, 2021.

Proved Undeveloped Reserves (PUDs)

As of September 30, 2020, REP’s proved undeveloped reserves were composed of 18,008.6 MBbls of oil, 22,545.9 MMcf of natural gas and 4,834.5 MBbls of NGL, for a total of 26,600.7 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes REP’s changes in REP’s estimated PUDs during the year ended September 30, 2020 (in MBoe):

Proved undeveloped reserves at September 30, 2019	25,711.3
Conversions	(1,310.8	)
Extensions, discoveries and other additions	2,008.1
Revisions	192.1
Proved undeveloped reserves at September 30, 2020	26,600.7

During the year ended September 30, 2020, REP incurred costs of approximately $6.9 million to convert 1,310.8 MBoe of proved undeveloped reserves to proved developed reserves.

During the year ended September 30, 2020, extensions and discoveries comprised of 2,008.1 MBoe. The increase was primarily the result of drilling successful wells and booking PUD offsets to such wells.

During the year ended September 30, 2020, REP revisions for the decline curves for the proved undeveloped reserves comprised 192.1 MBoe. The increase from revisions was primarily the result of performance of wells in the immediate offset areas.

As of September 30, 2020, REP had 0 proved undeveloped reserves that had remained undeveloped for more than five years since initial booking.

Estimated future development costs relating to the development of REP’s proved undeveloped reserves at September 30, 2020 are approximately $129.4 million, over the next five years, which REP expects to finance through cash flow from operations, borrowings under REP’s revolving credit facility and other sources of capital. All of REP’s proved undeveloped reserves are expected to be developed within five years of initial booking.

As a result of the COVID-19 outbreak that spread quickly across the globe, federal, state and local governments mobilized to implement containment mechanisms and minimize impacts to their populations and economies. Various containment measures, which included the quarantining of cities, regions and countries, while aiding in the prevention of further outbreak, have resulted in a severe drop in general economic activity and a resulting decrease in energy demand. In an effort to minimize the capital deployed as a result of the decrease in energy demand cause by the COVID-19 outbreak, REP made the decision to reduce its planned capital activity for Fiscal Year 2020. Those proved undeveloped locations not developed in Fiscal Year 2020 are planned to be developed over the next five years.

Oil, Natural Gas and NGL Production Prices and Production Costs

Production and Operating Data

The following table sets forth information regarding REP’s production, realized prices and production costs for the years ended September 30, 2020, September 30, 2019 and September 30, 2018. For additional information, please see “REP Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	For the Years Ended September 30,
	2020			2019			2018
Total Sales Volumes:
Oil (MBbls)		2,060			1,975			1,195
Natural Gas (MMcf)		1,628			886			197
NGL (MBbls)		260			135			41
Total (MBoe)⁽¹⁾		2,592			2,258			1,269
Daily Sales Volumes:
Oil sales (Bbl/d)		5,630			5,411			3,274
Natural gas sales (Mcf/d)		4,448			2,428			541
Natural gas liquids sales (Bbl/d)		710			370			113
Total (BOE/d)⁽¹⁾		7,081			6,186			3,477
Average sales price⁽¹⁾:
Oil sales (per Bbl)	$	36.35		$	51.45		$	57.19
Oil sales with derivative settlements (per Bbl)⁽²⁾		49.41			51.71			50.89
Natural gas sales (per Mcf)		(0.78	)		(0.32	)		2.04
Natural gas sales with derivative settlements (per Mcf)⁽²⁾		(0.78	)		(0.32	)		2.04
Natural gas liquids sales (per Bbl)		(1.90	)		(1.74	)		27.45
Natural gas liquids with derivative settlements (per Bbl)⁽²⁾		(1.90	)		(1.74	)		27.45
Average price per BOE excluding derivative settlements⁽¹⁾⁽²⁾		28.22			44.78			52.53
Average price per BOE including derivative settlements⁽¹⁾⁽²⁾		38.61			45.00			46.60
Expenses per BOE⁽¹⁾:
Lease operating expenses	$	8.10		$	10.54		$	8.70
Production and ad valorem taxes		1.36			2.13			2.53
Exploration expenses		3.83			2.25			4.72
Depletion, depreciation, amortization, and accretion		8.29			8.94			12.38
General and administrative expenses, inclusive of unit-based compensation expense⁽³⁾		3.08			4.95			11.17
Transaction costs⁽⁴⁾		0.55			2.02			0.69

(1)	One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities.
(2)	Average prices shown in table reflect prices both before and after the effects of REP’s settlements of our commodity derivative contracts. REP’s calculation of such effects includes both gains or losses on cash settlements for commodity derivatives.
(3)	General and administrative expenses, inclusive of unit-based compensation expense shown after effect of revenue from contract services for management services agreement.
(4)	Transaction costs include non-cash cost related to our previously aborted IPO.

Productive Wells

As of September 30, 2020, REP owned an average 54% working interest in 130 gross (71 net) productive wells all of which were oil wells.

Proved Developed Producing	Wells		Avg. WI
Operated		67		95	%
Non-Operated		63		11	%
Total		130		54	%

Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which REP has an interest, operated and non-operated, and net wells are the sum of REP’s fractional working interests owned in gross wells.

Developed and Undeveloped Acreage

The following tables set forth information as of September 30, 2020 relating to REP’s leasehold acreage. Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

The following table sets forth REP’s gross and net acres of developed and undeveloped oil and gas leases as of September 30, 2020:

Developed Acreage⁽¹⁾				Undeveloped Acreage⁽²⁾				Total Acreage⁽⁵⁾
Gross⁽³⁾		Net⁽⁴⁾		Gross⁽³⁾		Net⁽⁴⁾		Gross⁽³⁾		Net⁽⁴⁾
	18,529		11,792		48,142		33,385		66,671		45,178

(1)	Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease.
(2)	Undeveloped acreage are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
(3)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(4)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. Substantially all of the leases governing REP’s acreage have continuous development clauses that permit REP to continue to hold the acreage under such leases after the expiration of the primary term if REP initiates additional development within 120 to 180 days after the completion of the last well drilled on such lease, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 120 to 240 days, and generally 180 days, until the entire lease is held by production. None of REP’s horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule or primary term. The following table sets forth the net undeveloped acreage, as of September 30, 2020 that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

Net Undeveloped Acreage⁽¹⁾
2021		2022		2023	+
	23,466		2,084	26,208

(1)	All acreage represented is as of September 30, 2020.

Based on REP’s current development plans, REP expects to maintain substantially all of the acreage that would otherwise expire during fiscal 2021 either through drilling and establishing production, making lease extension payments, or lease renewal efforts. REP intends to extend or renew all of its material leases referenced above to the extent possible and expects to incur $0.8 million to extend or renew every material lease that is set to expire in fiscal year 2021, without taking into account the drilling of PUDs and holding leases by production, and therefore REP does not expect a material reduction in its proved undeveloped reserves as a result of leases expirations. Given REP’s currently planned drilling activities, REP does not expect the amount of any such lease extension payments to be material. Additionally, REP’s Champions acreage is 100% fee leasehold and New Mexico acreage approximately 95% fee and state leasehold with the remaining 5% of New Mexico consisting of Bureau of Land Management leasehold.

The following table sets forth information with respect to (i) the number of total gross and net oil wells drilled and completed by REP during the periods indicated. REP does not have any natural gas wells, therefore the information set forth in the table below only pertains to oil wells. The 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, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

	Year Ended
	September 30,
	2020		2019		2018
	Gross	Net	Gross	Net	Gross	Net
Development Wells:
Productive⁽¹⁾	11	3	20	13	25	13
Dry⁽²⁾	—	—	—	—	—	—
Exploratory Wells:
Productive⁽¹⁾	—	—	—	—	—	—
Dry⁽²⁾	—	—	—	—	—	—
Total Wells:
Productive⁽¹⁾	11	3	20	13	25	13
Dry⁽²⁾	—	—	—	—	—	—

(1)	Although a well may be classified as productive upon completion, future changes in oil, natural gas and NGL prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.
(2)	Does not include a wellbore temporarily abandoned due to mechanical failure.

Since September 30, 2019, REP’s producing well count has increased by 11 gross (3 net) wells, which includes the addition of 22 gross (13.7 net) wells, and the subtraction of 11 gross (10.3 net) wells from REP’s producing well count.

Operations

General

REP operated 89% of its horizontal production for the fiscal year ended September 30, 2020. As operator, REP designs and manages the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by REP provide all of the equipment and personnel associated with these activities. REP employs petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating REP’s oil and natural gas properties. For more information about REP’s properties and the risks associated with the comparability of proved, probable, and possible reserves, please read “—REP Properties” and “—Oil and Natural Gas Data.”

Marketing and Customers

REP markets the majority of the production from properties REP operates for both REP’s account and the account of the other working interest owners in these properties.

REP sells its production to purchasers at market prices. For the fiscal year ended September 30, 2020, one purchaser accounted for more than 10% of REP’s revenue: Stakeholder Crude Oil Marketing, LLC (86%). For the year ended September 30, 2019, one purchaser accounted for more than 10% of REP’s revenue: Stakeholder Crude Oil Marketing, LLC (85%). For the year ended September 30, 2018, one purchaser accounted for more than 10% of REP’s revenue: Stakeholder Crude Oil Marketing, LLC (92%). During such periods, no other purchaser accounted for 10% or more of REP’s revenue. The loss of any of these purchasers could materially and adversely affect REP’s revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, REP believes that the loss of any of its purchasers would not have a long-term material adverse effect on REP’s financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets.

Transportation

During the initial development of REP’s fields, REP considers all gathering and delivery infrastructure in the areas of REP’s production. REP’s oil is collected from the wellhead to REP’s tank batteries and then transported by the purchaser by truck or pipeline to a tank farm, another pipeline or a refinery. A portion of REP’s natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point.

In addition, REP moves substantially all of its produced water by pipeline connected to company-owned saltwater disposal wells rather than by truck. Given the amount of disposal water volume, the connection to saltwater disposal wells helps REP reduce its lease operating expenses.

REP is currently a party to a crude oil pipeline transportation agreement with Stakeholder Midstream Crude Oil Pipeline, LLC that commenced in October 2016 and has a 10-year term. This agreement does not include any volume commitments for REP. As a result, REP benefits from relatively low take-away costs as compared to transportation by truck. In addition, since a volume commitment is not applicable, REP achieves greater operational flexibility. In September 2017, REP entered into a long-term natural gas gathering and processing agreement with Stakeholder Gas Services, LLC, with a 10-year term and no volume commitments for REP. REP began selling natural gas under this agreement in the fourth quarter of fiscal 2018.

Competition

The oil and natural gas industry is intensely competitive, and REP competes with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than REP’s financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil, natural gas and NGL market prices. REP’s larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, and local laws and regulations more easily than REP can, which would adversely affect REP’s competitive position. REP’s ability to acquire additional properties and to discover reserves in the future will be dependent upon REP’s ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because REP has fewer financial and human resources than many companies in REP’s industry, REP may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which REP operates. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon REP’s future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. REP’s larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than REP can, which would adversely affect REP’s competitive position.

Title to Properties

As is customary in the oil and natural gas industry, REP initially conducts only a cursory review of the title to its properties in connection with acquisition of leasehold acreage. At such time as REP determines to conduct drilling operations on those properties, REP conducts a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, REP is typically responsible for curing any title defects at REP’s expense. REP generally will not commence drilling operations on a property until it has cured any material title defects on such property. REP has obtained title opinions on substantially all of REP’s producing properties and believe that REP has satisfactory title to its producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas leases, REP performs title reviews on the most significant leases and, depending on the materiality of properties, REP may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. REP’s oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which REP believes do not materially interfere with the use of or affect its carrying value of the properties.

REP believes that it has satisfactory title to all of its material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, REP believes that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from REP’s interest in these properties or materially interfere with REP’s use of these properties in the operation of REP’s business. In addition, REP believes that it has obtained sufficient rights-of-way grants and permits from public authorities and private parties for REP to operate its business in all material respects as described in this document.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil, natural gas and NGLs. Demand for oil, natural gas and NGLs is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering REP’s properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on REP’s properties generally range from 22.5% to 25.0%, resulting in a net revenue interest to REP generally ranging from 75.0% to 77.5%.

Regulation of the Oil and Gas Industry

REP’s operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which REP owns or operates producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of wells. REP’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. State laws including in Texas govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that REP can produce from its wells and to limit the number of wells or the locations at which REP can drill, although REP can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although REP believes it is in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, REP is unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. REP cannot predict when or whether any such proposals may become effective. REP does not believe that it would be affected by any such action materially differently than similarly situated competitors.

Regulation Affecting Production

The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which REP owns or operates producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. REP’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and gas REP can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGLs and gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from REP’s wells, negatively affect the economics of production from these wells or limit the number of locations REP can drill.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. REP’s competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect REP’s operations.

Regulation of Sales and Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. REP cannot predict whether new legislation to regulate oil and NGLs, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on REP’s operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirement.

REP’s sales of oil are affected by the availability, terms and cost of transportation. Prices received from the sale of crude oil and natural gas liquids may be affected by the cost of transporting those products to market. FERC has jurisdiction under the Interstate Commerce Act (“ICA”), as it existed in 1977, over common carriers engaged in the transportation in interstate commerce by pipeline of crude oil, natural gas liquids and refined petroleum products as part of the continuous movement of the crude oil, natural gas liquids or refined petroleum products in interstate commerce. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service be “just and reasonable.” In general, interstate oil pipeline rates must be cost-based, although indexed rates, settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, REP believes that the regulation of oil transportation will not affect REP’s operations in any way that is of material difference from those of REP’s competitors who are similarly situated.

Regulation of Transportation and Sales of Natural Gas

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

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

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, any market participant that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices to FERC on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case by case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, REP’s costs of getting natural gas to point of sale locations may increase. REP believes that the natural gas pipelines in the gathering systems REP uses meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of the gathering facilities REP owns and uses are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Natural gas gathering may receive greater regulatory scrutiny at the state level. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.

The price at which REP sells natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to REP’s physical sales of these energy commodities, REP is required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should REP violate the anti-market manipulation laws and regulations, REP could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, REP believes that the regulation of similarly situated intrastate natural gas transportation in any states in which REP operates and ships natural gas on an intrastate basis will not affect REP’s operations in any way that is of material difference from those of REP’s competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that REP produces, as well as the revenues REP receives for sales of its natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and REP cannot predict what future action FERC or state regulatory bodies will take. REP does not believe, however, that any regulatory changes will affect REP in a way that materially differs from the way they will affect other natural gas producers and marketers with which REP competes.

Regulation of Environmental and Occupational Safety and Health Matters

REP’s oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental and human health protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may (i) require the acquisition of a permit before drilling or other regulated activity commences; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment; (iii) govern the sourcing and disposal of water used in the drilling and completion process; (iv) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, threatened or endangered species habitat and other protected areas; (v) require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; (vi) establish specific safety and health criteria addressing worker protection; (vii) impose substantial liabilities for pollution resulting from operations or failure to comply with regulations, including permitting requirements; (viii) require the installation of costly emission monitoring and/or pollution control equipment; (ix) require the preparation and implementation of oil spill prevention, control, and countermeasure plans and risk management plans; and (x) require the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with REP’s properties. In addition, these laws and regulations may restrict the rate of production.

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

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and anyone who disposed or arranged for the transport or disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. REP generates materials in the course of REP’s operations that may be regulated as “hazardous substances”. REP is able to control directly the operation of only those wells with respect to which REP acts as operator. Notwithstanding REP’s lack of direct control over wells operated by others, the failure of an operator other than REP to comply with applicable environmental regulations or the failure of a facility receiving hazardous substances for treatment or disposal to manage the substances properly may, in certain circumstances, be attributed to REP and result in CERCLA or comparable liability.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree required EPA to propose a rulemaking no later than March 15, 2019 for revision of the Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. EPA ultimately concluded that revision of the Subtitle D criteria regulations regarding oil and gas wastes is not necessary at this time. But, should future rulemakings or legal challenges result in a loss of the RCRA hazardous-waste exclusion for drilling fluids, produced waters and related wastes, REP’s costs to manage and dispose of generated wastes could increase, which could have a material adverse effect on REP’s results of operations and financial position. In addition, in the course of REP’s operations, REP generates some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are listed as hazardous wastes or have hazardous characteristics.

REP currently owns, leases or operates numerous properties that have been used for oil and natural gas development and production activities for many years. Although REP believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by REP, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling, treatment or disposal. In addition, some of REP’s properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under REP’s control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, REP could be required to undertake response or corrective measures, which could include investigation of the nature and extent of contamination, removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In May 2015, the EPA and the Corps issued a new rule to revise the definition of “waters of the United States” for all Clean Water Act Programs. The 2015 rule made additional waters expressly “waters of the United States” and, therefore, subject to the jurisdiction of the Clean Water Act, rather than subject to a case-specific evaluation. Legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” On February 1, 2018, the EPA officially delayed implementation of the 2015 rule until early 2020. The EPA and the Corps also issued a supplemental rulemaking in July 2018 requesting additional comment on the proposed repeal of the 2015 rule’s definition of “waters of the United States.” However, as the result of an order by the U.S. District Court for the District of South Carolina on August 16, 2018, and subsequent state filings, the 2015 rule was in effect in 23 states, including in Texas. On February 14, 2019, the EPA and the Corps issued a proposed rule to revise the definition of “Waters of the United States.” The proposed rule would narrow the definition, excluding, for example, streams that do not flow year-round and wetlands without a direct surface connection to other jurisdictional waters. In September 2019, EPA finalized the repeal of the 2015 WOTUS rule, and the repeal became effective in December 2019. On June 22, 2020, EPA’s proposed rule revising and narrowing the definition of “Waters of the United States” became effective. Litigation by parties opposing the rule again quickly followed. Due to the administrative procedures required to establish the rule and pending litigation, the new definition of “Waters of the United States” may not be implemented, if at all, for several years. To the extent any litigation or future amendments to the rule expand the scope of the Clean Water Act’s jurisdiction, REP could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or in connection with stream crossings and to preparing and implementing oil spill prevention, control, and countermeasure plans. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to CWA laws and regulations, REP may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water. Spill prevention, control and countermeasure (“SPCC”) requirements imposed under the CWA require operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, to develop, implement, and maintain SPCC plans. REP has undertaken a review of REP’s properties to determine the need for new or updated SPCC plans and, where necessary, REP has developed or upgraded such plans and has implemented the physical and operation controls imposed by these plans.

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

Subsurface Injections

In the course of REP’s operations, REP produces water in addition to oil and natural gas. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the UIC program established under the SDWA and analogous state laws. The UIC program requires permits from the EPA or state agency to which the UIC program has been delegated for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect REP’s ability to dispose of produced water and ultimately increase the cost of REP’s operations. For example, in response to recent seismic events belowground near disposal wells used for the injection of oil and natural gas-related wastewaters, regulators in some states, including Texas, have imposed more stringent permitting and operating requirements for produced water disposal wells. In 2014, the TRRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by REP or by commercial disposal well vendors whom REP may use from time to time to dispose of wastewater, and increased costs of compliance, which could have a material adverse effect on REP’s capital expenditures and operating costs, financial condition, and results of operations.

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. EPA followed up its Request for Comments with an Interpretative Statement and additional Request for Comment in April 2019 stating that the agency does not believe indirect discharges from a point source through a hydrological groundwater connection to surface water are regulated under the CWA, although the agency indicated that this guidance may be amended pending the Supreme Court’s decision. In April, 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. On December 8, 2020, EPA issued a draft guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. EPA is currently soliciting public comments on the guidance. The U.S. Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund could result in increased operational costs for REP if permits are required under the CWA for disposal of REP’s flowback and produced water in disposal wells.

Air Emissions

The Federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require REP to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, REP may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit REP’s ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, beginning in 2012, the EPA adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas and, in 2016, oil wells for which well completion operations are conducted (i.e. use reduced emission completions, also known as “green completions”). These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers, storage vessels, and well-site components (fugitive emissions). In September 2020, EPA scaled back these rules by removing the transmission and storage sectors of the oil and gas industry from regulation under the NSPS and rescinding methane-specific standards for the production and processing segments of the industry. However, legal challenges to the amendments quickly followed. In May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities located in areas where air permitting is implemented by EPA, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. See also “—Regulation of GHG Emissions.” Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase REP’s costs of development, which costs could be significant.

Regulation of GHG Emissions

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal CAA that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect REP’s operations and restrict or delay REP’s ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of REP’s operations. Furthermore, in May 2016, the EPA finalized the NSPS Subpart OOOOa standards that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rules impose leak detection and repair requirements intended to address methane and other emissions leaks known as “fugitive emissions” from equipment, such as valves, connectors, open ended lines, pressure-relief devices, compressors, instruments and meters. Although much of the initial rules remain intact and effective, the rules have been subject to legal challenges, reconsideration by EPA, stays, and proposed amendments. Most recently, EPA published two new rules on September 14 and 15, 2020 that remove the transmission and storage sectors of the oil and gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately. Thus, the ultimate scope of these regulations remains uncertain. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. The BLM also finalized similar rules regarding the control of methane emissions in November 2016 that apply to oil and natural gas exploration and development activities on federal and Indian lands. The rules sought to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. However, due to subsequent BLM revisions and multiple legal challenges, the rules were never fully implemented, and in October 2020, the November 2016 rules were struck down by the District Court of Wyoming as the result of one such challenge. These new and proposed rules could result in increased compliance costs on REP’s operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant legislative activity at the federal level in recent years. However, some initiatives continue to gain attention at the political level; for example, a resolution referred to as the Green New Deal was introduced in the U.S. House of Representatives in February 2019. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact REP’s business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, REP’s equipment and operations could require REP to incur costs to reduce emissions of GHGs associated with REP’s operations. Demand for REP’s products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans developed in connection with the Paris climate conference in December 2015. While the U.S. ratified plans associated with such conference in September 2016, the Trump Administration opted not to continue governance under those plans. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which resulted in an effective exit date of November 2020. However, President-Elect Joe Biden has pledged to rejoin the Paris Agreement on day one of his presidency. If he fulfills this pledge, the U.S.’s return to participation in the Paris Agreement would then become effective after a 30-day waiting period. Many governments also provide, or may in the future provide, tax advantages and other subsidies to support the use and development of alternative energy technologies. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas REP produces and lower the value of REP’s reserves.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, drought, and other climatic events; if any such effects were to occur, they could have a material adverse effect on REP’s operations. At this time, REP has not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on REP’s operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. REP regularly uses hydraulic fracturing as part of its operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted jurisdiction over certain aspects of the process. The EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also taken the following actions: issued final regulations under the federal CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; although final rules have not yet been issued, proposed a rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and, in June 2016, published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands, including requirements for chemical disclosure, wellbore integrity, and handling of flowback water. However, following years of litigation, the BLM rescinded the rule in December 2017. BLM’s repeal of the rule was challenged in court, and in April 2020, the Northern District of California issued a ruling in favor of the BLM. This ruling is now being appealed; thus, the future of the rule remains uncertain. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect REP’s operations.

Certain governmental reviews have recently been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances”, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. More recently, EPA initiated a study of Oil and Gas Extraction Wastewater Management in 2018 that the agency characterizes as a “holistic look” at how produced water is regulated and managed by EPA, states, and tribes, and has sought input on these issues from other stakeholders such as academics, non-governmental organizations, and industry. A primary focus of the study is to evaluate whether federal regulations allowing for more discharge options would be beneficial, for example, in addressing areas with concerns over scarcity of water and/or injection options. EPA released a draft of the study in May 2019 and sought public input until July 1, 2019. EPA’s final report was issued in May 2020, which found mixed support from stakeholders regarding additional produced water discharge options. EPA is still determining what, if any, next steps are appropriate regarding produced water management in light of the report. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA, CWA or other regulatory mechanisms.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule”, which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

Compliance with existing related laws has not had a material adverse effect on REP’s operations or financial position, but if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where REP operates, REP could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

Protected Species

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or that species’ habitat. REP may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act. In the past, the federal government has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. While the Department of Interior under the Trump administration has determined that such “incidental takes” of migratory birds do not violate the Act, this position was overruled by a federal district court in New York in August 2020. Nevertheless, the Department of the Interior is currently moving forward with a formal rulemaking that would limit prosecutorial authority for “incidental takes” of migratory birds. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause REP to incur increased costs arising from species protection measures or could result in limitations on REP’s development activities that could have an adverse impact on REP’s ability to develop and produce reserves. If REP were to have a portion of its leases designated as critical or suitable habitat, it could adversely impact the value of REP’s leases.

OSHA, Emergency Response and Community Right-to-Know, and Risk Management Planning

REP is subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the CAA and comparable state statutes and any implementing regulations require that REP organizes and/or discloses information about hazardous materials used or produced in REP’s operations and that this information be provided to employees, state and local governmental authorities and citizens. These laws also require the development of risk management plans for certain facilities to prevent accidental releases of extremely hazardous substances and to minimize the consequences of such releases should they occur.

Related Permits and Authorizations

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

Related Insurance

REP maintains insurance against some risks associated with above or underground contamination that may occur as a result of REP’s exploration and production activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by REP. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on REP’s financial condition and operations. Further, REP has no coverage for gradual, long-term pollution events.

Employees

As of September 30, 2020, REP employed 46 people. REP is not a party to any collective bargaining agreements with its employees. REP believes its relations with its employees to be satisfactory.

From time to time REP utilizes the services of independent contractors to perform various field and other services.

Facilities

REP’s corporate headquarters is located in Oklahoma City, Oklahoma at 29 E. Reno Avenue, Suite 500, Oklahoma City, Oklahoma 73104.

Legal Proceedings

Please refer to Note 15—Commitments and Contingencies to REP’s audited financial statements for the year ended September 30, 2020 for a discussion on legal proceedings.

REP MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of REP’s financial condition and results of operations should be read in conjunction with REP’s historical financial statements and related notes included elsewhere in this document or in our Form 8-K filed with the SEC March 4, 2021. The following discussion contains “forward-looking statements” that reflect REP’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside REP’s control. REP’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, changes in prices for oil, natural gas and NGL, production volumes and forecasting production results, capital expenditures, availability of acquisitions, estimates of proved reserves, economic and competitive conditions, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as REP’s ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting REP’s business, as well as those factors discussed below and elsewhere in this document or in our Form 10-K and other documents filed with the SEC, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. REP does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

REP is a growth-oriented, independent oil and natural gas company focused on steadily growing its conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”) in the Permian Basin. REP’s activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf. REP was formed to focus on opportunities (i) with favorable reservoir and geological characteristics primarily for oil development, (ii) that offer large contiguous acreage positions with significant untapped potential in terms of ultimate recoverable reserves and (iii) with a high degree of operational control. REP’s acreage is primarily located on large, contiguous blocks in Yoakum County, Texas (the “Champions Assets”) and Lea, Roosevelt, and Chaves Counties, New Mexico.

REP was initially formed as Riley Exploration-Permian, Inc., a wholly-owned subsidiary of Riley Exploration Group, Inc. (“REG”) in June 2016 whereby REG owned 100% of REP’s membership interests. On August 8, 2016, Riley Exploration-Permian, Inc. was converted to a limited liability company, REP.

On January 17, 2017, REG contributed its working interest in the Champions Assets to REP in exchange for common units in REP. Simultaneously, Boomer Petroleum, LLC (“Boomer”) contributed its working interest in oil and natural gas properties and related assets of the Champions Assets to REP in exchange for common units in REP. On March 6, 2017, Bluescape Riley Exploration Acquisition, LLC (“Bluescape”) and each of the Stephen H. Dernick Trust, the David D. Dernick Trust, Dennis W. Bartoskewitz, Alan C. Buckner, the Robert Gary Dernick Trust, and Christopher M. Bearrow, and/or their successors and assigns (collectively referred to as “DR/CM”) contributed their combined working interest in oil and natural gas properties and related assets and liabilities of the Champions Assets in exchange for common units in REP.

The contribution received from REG was considered a transfer of a business between entities under common control and accordingly, REP has recorded the contributed business at historical cost and presented the historical operations of the contributed business on a retrospective bases for all periods presented. The contributions from Boomer, Bluescape and DR/CM were accounted for as business combinations in accordance with Accounting Standards Codification (“ASC”) 805 – Business Combinations (“ASC 805”) and recorded at fair value. REP’s financial statements reflect the operating results of the assets contributed by Boomer, Bluescape and DR/CM for the periods following the respective contributions.

As of September 30, 2020, REP had an estimated 56,786.3 MBoe of proved reserves, consisting of 37,157.7 MBbls of oil, 53,683.4 MMcf of natural gas, and 10,681.6 MBbls of NGLs. Approximately 53% of REP’s proved reserves were classified as proved developed. Production for the year ended September 30, 2020, totaled 2,592 MBoe, or 7,081 BOE per day, of which 80% was oil.

On October 21, 2020, TGC and REP entered into a definitive merger agreement under which TGC acquired REP and all its subsidiaries in exchange for approximately 16.9 million shares of TGC common stock (the “Transaction”). The Transaction is a reverse triangular merger, where TGC formed Antman Sub, LLC (“Merger Sub”) as a direct wholly-owned subsidiary that merged into REP. The merger between REP and Merger Sub resulted in REP’s common units being exchanged into TGC stock. As part of the Transaction TGC changed its name to Riley Exploration Permian, Inc. and changed its symbol for its common stock on the NYSE American from “TGC” to “REPX”.

Under the merger agreement, at the effective time, each Series A unit issued as of immediately prior to the effective time, was converted into that number of shares of TGC common stock equal to the product (rounded down to the nearest whole number) of: (i) the number of REP Series A units held by that holder as of immediately prior to the effective time; and (ii) the exchange ratio for the merger. Immediately prior to the effective time, REP paid any unpaid dividends accruing between October 1, 2020 and the closing date of the merger in accordance with the REP organizational documents in effect immediately prior to the merger.

Current Commodity Environment

During the first calendar quarter of 2020, the balance of supply and demand for oil and other commodities experienced two significant disruptive events. On the demand side, a worldwide outbreak of a novel strain of coronavirus, SARS-CoV-2, causing a disease referred to as COVID-19, created a pandemic which caused various governmental actions in order to mitigate the spread of COVID-19, which resulted in substantial reductions in consumer and business activity adversely impacting the demand for oil and other commodities. On the supply side, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among the Organization of the Petroleum Exporting Countries (“OPEC”) and other countries, such as Russia, further increased uncertainty and volatility around global oil supply-and-demand dynamics. However, during the second and third calendar quarter of 2020, OPEC and other oil producing countries agreed to reduce their crude oil production and then extend such production cuts through at least the first few months of 2021, while U.S. producers substantially reduced or suspended drilling activity, and in most cases curtailed production, due to low oil prices and poor economics. These actions have aided in a partial recovery of global commodity prices. Specifically, WTI spot prices for crude oil fell to a low of negative ($37.63) on April 20, 2020 (due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location in Cushing, Oklahoma) and have since partially recovered to a high of $46.78 on December 10, 2020.

With the commodity prices declining throughout the first half of 2020, REP’s reserve value decreased which also resulted in a decreased borrowing base. While the decline in commodity prices and reduced demand negatively impacted the oil and natural gas industry as a whole, REP had certain commodity hedges in place in order to mitigate and partially offset the negative effects of such price declines. However, REP cannot estimate the full length or gravity of the impacts of these events at this time and if the pandemic and/or decreased oil prices continue, it could continue to have a material adverse effect on REP’s results of operations, financial position, liquidity and the value of oil and natural gas reserves.

REP’s Properties

At September 30, 2020, REP’s net acreage position consisted of 45,178 net acres with 58% in Yoakum County, Texas, 3% in Chaves, 21% in Lea, and 18% in Roosevelt County, New Mexico. For the year ended September 30, 2020, REP operated 89% of its production, and its total estimated proved, probable and possible reserves based on the NSAI Report were approximately 56,786; 63,126; 13,006 MBoe, respectively. REP holds net acreage positions of 1,256 in Chaves, 9,261.63 in Lea and 8,312.78 in Roosevelt County, New Mexico and 26,347.1 in Yoakum County, Texas. REP has excluded 17,669 from net acreage that has already been impaired or abandoned, but has yet to expire. For more information about REP’s properties and the risks associated with the comparability of proved, probable, and possible reserves, please read “REP Business—REP’s Properties” and “REP Business—Oil and Natural Gas Data.”

How REP Evaluates Its Operations

REP uses a variety of financial and operational metrics to assess the performance of its oil and gas operations, including:

•	Sources of revenue;
•	Sales volumes;
•	Realized prices on the sale of oil, natural gas and NGL, including the effect of REP’s commodity derivative contracts;
•	Lease operating expenses, or LOE;
•	Capital expenditures; and
•	Adjusted EBITDAX.

See “—Sources of REP’s Revenues”, “—Sales Volumes”, “—Realized Prices on the Sale of Crude Oil, Natural Gas and NGL” and “—Derivative Arrangements”, “—Principal Components of REP’s Cost Structure”, “—Adjusted EBITDAX” and “—Non-GAAP Financial Measure—Adjusted EBITDAX” for a discussion of these metrics.

Sources of REP’s Revenues

REP’s production revenues are derived primarily from the sale of its crude oil production. For the year ended September 30, 2020, REP’s oil and natural gas sales, net were primarily derived from oil sales with sales from natural gas and NGLs contributing negative cash flows when netted against gathering, processing and transportation costs. Beginning October 1, 2018, REP started reporting oil, natural gas and NGLs sales together netted against any gathering, processing and transportation costs as “oil and natural gas sales, net” on the consolidated statements of operations in connection with the adoption of ASC 606. REP’s oil and natural gas sales in its financial statements do not include the effects of derivatives as those effects are included within other income. REP’s oil and natural gas sales, net may vary significantly from period to period as a result of changes in production sold or changes in oil prices.

REP’s oil and natural gas sales, net may vary significantly from period to period as a result of changes in production sold or changes in oil prices. REP’s contract services – related parties revenue is derived from contracts with related parties to provide certain administrative support services. The contract services – related parties revenue made up 5% of the total revenues for the year ended September 30, 2020.

Sales Volumes

The following table presents historical sales volumes for REP’s properties for the years ended September 30, 2020, 2019 and 2018.

	For the Years Ended September 30,
	2020	2019	2018
Oil (MBbls)	2,060	1,975	1,195
Natural gas (MMcf)	1,628	886	197
NGL (MBbls)	260	135	41
Total (MBoe)⁽¹⁾	2,592	2,258	1,269
Average net sales (BOE/d)⁽²⁾	7,081	6,186	3,477

(1)	One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities.
(2)	Average net sales (BOE/d) was derived by dividing the total MBoe by 366 days for the year ended 2020 and by 365 days for the years ended 2019 and 2018.

Sales volumes directly impact REP’s results of operations. As reservoir pressures decline, production from a given well or formation usually also decreases over time. Growth in REP’s future production and reserves will depend on its ability to continue to add proved reserves in excess of REP’s production. Accordingly, REP plans to maintain its focus on adding reserves through organic drill-bit growth, as well as acquisitions. REP’s ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in REP’s areas of operation and REP’s ability to raise capital, geologic considerations, obtaining regulatory approvals, procuring third-party services and personnel and successfully identifying and consummating acquisitions.

Realized Prices on the Sale of Crude Oil, Natural Gas and NGL

Historically, oil, natural gas and NGLs prices have been extremely volatile, and REP expects this volatility to continue. Because REP’s production consists primarily of oil, REP’s production revenues are more sensitive to fluctuations in the price of oil than they are to fluctuations in the price of natural gas or NGLs.

To achieve more predictable cash flow and to reduce REP’s exposure to adverse fluctuations in commodity prices, REP enters into derivative arrangements for a portion of its production, with an emphasis on REP’s oil production. By removing a portion of price volatility associated with REP’s oil production, REP believes it will mitigate, but not eliminate, the potential negative effects of the reduction in oil prices on REP’s cash flow from operations for the relevant periods. See “—Quantitative and Qualitative Disclosure About the Market Risk of REP—Commodity Price Risk” for information regarding REP’s exposure to market risk, including the effects of changes in commodity prices, and REP’s commodity derivative contracts. REP will sustain losses to the extent its derivatives contract prices are lower than market prices and, conversely, REP will sustain gains to the extent its derivatives contract prices are higher than market prices. In certain circumstances, where REP has unrealized gains in its derivative portfolio, REP may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of REP’s existing positions.

A $1.00 per barrel change in REP’s realized oil price would have resulted in a $2.06 million and $1.97 million change in oil revenues for the years ended September 30, 2020 and 2019, respectively. A $0.15 per Mcf change in REP’s realized natural gas price would have resulted in a de minimis change in its natural gas revenues for the years ended September 30, 2020 and 2019. And likewise, a $1.00 per barrel change in NGL prices would have resulted in a de minimis change to REP’s NGL revenue for both periods presented.

The following table presents REP’s average realized commodity prices, as well as the effects of derivative settlements.

		For the Years Ended September 30,
		2020			2019			2018
Oil
NYMEX WTI High ($/Bbl)	$	63.27		$	76.40		$	77.41
NYMEX WTI Low ($/Bbl)		(36.98	)		44.48			49.34
NYMEX WTI Average ($/Bbl)		42.74			57.76			64.01
Average Realized Price ($/Bbl)		36.35			51.45			57.19
Average Realized Price, with derivative settlements ($/Bbl)		49.41			51.71			50.89
Averaged Realized Price as a % of Average NYMEX WTI⁽¹⁾		85	%		89	%		89	%
Differential ($/Bbl) to Average NYMEX WTI		(6.39	)		(6.30	)		(6.82	)
Natural Gas⁽³⁾
NYMEX Henry Hub High ($/MMBtu)	$	2.87		$	4.70		$	6.24
NYMEX Henry Hub Low ($/MMBtu)		1.33			2.02			2.49
NYMEX Henry Hub Average ($/MMBtu)		2.00			2.90			2.94
Average Realized Price ($/Mcf)		(0.78	)		(0.33	)		2.04
Average Realized Price, with derivative settlements ($/Mcf)		(0.78	)		(0.33	)		2.04
Averaged Realized Price as a % of Average NYMEX Henry Hub		-39	%		-11	%		69	%
Differential ($/Mcf) to Average NYMEX Henry Hub⁽¹⁾		(2.78	)		(3.23	)		(0.90	)
Natural Gas Liquids⁽³⁾
Average Realized Price ($/Bbl)	$	(1.90	)	$	(1.75	)	$	27.44
Averaged Realized Price as a % of Average NYMEX WTI		-4	%		-3	%		43	%
BOE (Barrel of Oil Equivalent)
Average price per BOE⁽¹⁾	$	28.22		$	44.78		$	55.05
Average price per BOE with derivative settlements⁽¹⁾⁽²⁾		38.61			45.00			49.12

(1)	One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities.
(2)	Average prices shown in table reflect prices both before and after the effects of our settlements of REP’s commodity derivative contracts. REP’s calculation of such effects includes both gains or losses on cash settlements for commodity derivatives.
(3)	Realized prices are reflected at net of the deduction of gathering, processing and transportation costs.

While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within REP’s industry, the prices REP receives are affected by quality, energy content, location and transportation differentials for these products.

Derivative Arrangements

REP will continue to use commodity derivative instruments to hedge some of REP’s price risk in the future. Subject to restrictions in REP’s revolving credit agreement, REP’s hedging strategy and future hedging transactions will be determined at REP’s discretion and may be different than what it has done on a historical basis. Under REP’s credit agreement, REP is only permitted to hedge up to 85% of its reasonably anticipated production of each of oil and natural gas for up to 24 months in the future, and up to 75% of its reasonably anticipated production of each of oil and natural gas for 25 to 48 months in the future. REP is also required to hedge a minimum of 50% of its projected oil and natural gas volumes from PDP reserves on a 24-month rolling basis. In respect to interest rate hedging from floating to a fixed rate, REP is only permitted to hedge up to 75% of its then outstanding principal indebtedness for borrowed money that bears interest at a floating rate and the hedge transaction cannot have a maturity date beyond the maturity date of that indebtedness. See “—Liquidity and Capital Resources—REP’s Revolving Credit Facility” for more information.

As a result of recent volatility in the price of oil and natural gas, REP has evaluated a variety of hedging strategies and instruments to hedge its future price risk. To date, REP has utilized swaps, costless collars and basis swaps to reduce the effect of price changes on a portion of REP’s future oil production. REP may also utilize put options, and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of REP’s future oil and natural gas production.

This table presents REP’s open hedge positions as of September 30, 2020:

		Weighted Average Price
Calendar Quarter	Notional Volume	Fixed	Put	Call
	(Bbl)	($ per Bbl)
Crude Oil Swaps⁽¹⁾
Q4 2020	339,000	$57.15	$—	$—
Q1 2021	405,000	$53.01	$—	$—
Q2 2021	405,000	$53.01	$—	$—
Q3 2021	405,000	$53.01	$—	$—
Q4 2021	405,000	$53.01	$—	$—
2022	360,000	$45.25	$—	$—
Crude Oil Collars⁽¹⁾
Q4 2020	45,000	$—	$50.00	$56.48
2022	360,000	$—	$35.00	$42.63
Crude Oil Basis⁽²⁾
Q4 2020	384,000	$0.39	$—	$—
Q1 2021	435,000	$0.40	$—	$—
Q2 2021	435,000	$0.40	$—	$—
Q3 2021	435,000	$0.40	$—	$—
Q4 2021	435,000	$0.40	$—	$—

(1)	Reference Price is NYMEX WTI Price, referring to the West Texas Intermediate crude oil price on the New York Mercantile Exchange.
(2)	Reference Price is NYMEX WTI vs. WTI Midland (Argus) Calendar Trade Month.

The following table summarizes REP’s derivative activities for the years ended September 30, 2020, 2019 and 2018.

		Historical Derivative Positions and Settlement Amounts
		For the Years Ended September 30,
		2020			2019			2018
Fair value of net asset (liability) beginning of period	$	14,959		$	(11,239	)	$	(1,623	)
Gain (loss) on derivatives		33,876			26,712			(17,143	)
Net cash (receipts) from payments on derivatives		(26,914	)		(514	)		7,527
Fair value of net asset (liability) end of period	$	21,921		$	14,959		$	(11,239	)

(1)	NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange.
(2)	Reference Price is NYMEX WTI vs. WTI Midland (Argus) Calendar Trade Month.

Interest Rate Contracts

REP has entered into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage interest rate exposure related to the revolving credit facility. The notional amount of the interest rate swaps, as of September 30, 2020 and September 30, 2019 was $55 million and $40 million, respectively. These contracts expire on September 28, 2021.

Principal Components of REP’s Cost Structure

Lease Operating Expenses (“LOE”). LOE is the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection, disposal, utilities, materials and supplies comprise the most significant portion of our lease expenses.

Production Taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes REP pays correlate to the changes in oil and natural gas revenues. REP is also subject to ad valorem taxes in the counties where its production is located. Ad valorem taxes are generally based on the valuation of REP’s oil and natural gas properties.

Exploration Expenses. Exploration expenses are comprised primarily of impairments and abandonment of unproved properties, geological and geophysical expenditures, the cost to carry and retain unproved properties and exploratory dry hole costs.

Depletion, Depreciation, Amortization and Accretion. REP uses the successful efforts method of accounting for oil and natural gas activities and, as such, REP capitalizes all costs associated with its acquisition and development efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method. The fair value of the asset retirement obligation is recorded as a liability in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for the change in its present value each period and the capitalized costs is depreciated using the units-of-production method.

Impairment of Long-Lived Assets. Impairment of long-lived assets are comprised primarily of impairment of proved oil and gas properties. REP reviews its proved properties for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. See “—Critical Accounting Policies and Estimates” for further discussion. REP has not realized any impairment charges for the periods indicated.

General and Administrative Costs. These are costs incurred for overhead, including payroll and benefits for REP’s corporate staff, costs of maintaining REP’s headquarters, lease costs, numerous software applications, audit and other fees for professional services and legal compliance. REP’s cost for providing administrative support services for contract services with related parties are included as well.

Transaction Costs. Transaction costs consists of those costs associated with investment banking, accounting and other diligence costs related to unsuccessful acquisitions, successful acquisitions accounted for as business combinations in accordance with ASC 805, and costs related to REP’s previously abandoned IPO.

Gain (Loss) on Derivative Instruments. REP utilizes commodity derivative contracts to reduce its exposure to fluctuations in the price of oil. None of REP’s derivative contracts are designated as hedges for accounting purposes. Consequently, REP’s derivative contracts are marked-to-market each period with fair value gains and losses recognized currently as a gain or loss in its results of operations. The amount of future gain or loss recognized on derivative instruments is dependent upon future oil prices, which will affect the value of the contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

Interest Expense. REP finances a portion of its working capital requirements, capital expenditures and certain acquisitions through borrowings from REP’s Revolving Credit Agreement. As a result, REP incurs interest expense that is affected by its financing decisions and may be affected by fluctuations in interest rates. Interest expense reflects interest, unused commitment fees paid to REP’s lender, interest rate swap settlements plus amortization of deferred financing costs (including origination and amendment fees).

Income Tax Expense. REP is subject to the State of Texas enacted margin-based franchise tax law which is commonly referred to as the Texas margin tax and is assessed at a 0.75% rate. The amount is determined by applying the tax rate to the positive difference or margin between REP’s oil, natural gas and NGL revenue less certain operating expenses pertaining to those assets that REP owns in the State of Texas.

Adjusted EBITDAX

REP defines “Adjusted EBITDAX” as net income (loss) adjusted for certain cash and non-cash items, including depreciation, depletion, amortization and accretion, or DD&A, impairment of long-lived assets, provision for the carrying value of assets, exploration expenses, commodity derivative (gain) loss, settlements on commodity derivatives, premiums paid for derivatives that settled during the period, unit-based compensation expense, amortization of debt discount and debt issuance costs included in interest expense, income taxes, and non-recurring charges. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of REP’s operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. REP’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

Non-GAAP Financial Measure

Adjusted EBITDAX is not a measure of net income (loss) as determined by United States generally accepted accounting principles, or GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of financial statements, such as industry analysts, investors, lenders and rating agencies.

REP management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. REP excludes the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within REP’s industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. REP’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. REP believes that Adjusted EBITDAX is a widely followed measure of operating performance.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDAX for each of the periods indicated.

		For the Years Ended September 30,
		(in thousands)
		2020			2019			2018
Reconciliation of Net Income (Loss) to Adjusted EBITDAX
Net Income (Loss)	$	35,144		$	51,866		$	(723	)
Exploration expense		9,923			5,074			5,992
Depletion, depreciation, amortization and accretion		21,479			20,182			15,714
Interest expense		5,299			4,924			1,707
Unrealized (gain)/loss on derivatives		(6,962	)		(26,198	)		9,616
Unit-based compensation expense		963			898			4,000
Restructuring costs		392			—			—
Transaction costs		1,431			4,553			878
Income tax expense		718			1,410			—
Adjusted EBITDAX	$	68,387		$	62,709		$	37,184

Factors Affecting the Comparability of REP’s Financial Condition and Results of Operations

REP’s historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Derivative Activities

For the year ended September 30, 2020 REP’s commodity hedging activities resulted in recognizing a net $33.87 million derivative gain, comprised of a realized $26.91 million gain, and a $6.96 million gain on market-to-market of unrealized contracts, due primarily to decreasing crude oil future prices during that period. As commodity prices fluctuate, so will the income or loss REP recognizes from its hedging activities. For more information regarding REP’s historic hedging activities, please see “—Overview—Derivative Arrangements.”

Public Company Expenses

General and administrative costs related to being a publicly traded company include: Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley compliance; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and director compensation. As a publicly traded company at the closing of this transaction, REP expects that general and administrative costs will increase in future periods.

Income Taxes

REP was organized as a Delaware limited liability company and is treated as a pass-through entity for U.S. federal and applicable state income tax purposes. As a result, REP’s net taxable income and any related tax credits were passed through to the members and were included in their tax returns even though such net taxable income or tax credits may not have actually been distributed.

REP’s operations, which are located in Texas, are subject to an entity-level tax, the Texas margin tax, at a statutory rate of up to 0.75% of revenues less operating expenses attributable to operations in Texas. The tax is considered an entity-level tax which makes it applicable to REP even though it is a partnership for federal tax purposes.

Impact of ASC Topic 606

REP adopted ASC 606 effective October 1, 2018 using the modified retrospective approach, which allows REP to apply the previous revenue guidance and disclosure requirements under ASC Topic 605 in the comparative period presented for the year of adoption. REP modified its accounting and presentation of natural gas and NGL sales and associated volumes, and the gathering, transportation and processing costs, under REP’s marketing agreements. REP’s natural gas and NGL sales will be reported on a net basis with the gathering, transportation, and processing costs associated with these sales, and are included in oil and natural gas sales, net on REP’s consolidated statement of operations.

Impact of ASC Topic 842

REP adopted ASC 842 effective October 1, 2019 using the modified retrospective transition approach, which allows REP to apply the previous lease guidance and disclosure requirements under ASC Topic 840, Leases (“ASC 840”), in the comparative period presented for the year of adoption. The adoption did not require an adjustment to beginning retained earnings for a cumulative effect adjustment.

REP elected certain practical expedients and made certain accounting policy elections that impacted the effect of adoption on the consolidated balance sheet and statement of operations, including; (1) a package of practical expedients which allowed REP to not reassess contracts that commenced prior to adoption in regards to lease terms, lease classification, and indirect costs incurred prior to adoption, (2) excluding land easements that existed or expired prior to adoption, and (3) policy election that eliminates the need for adjusting prior period comparable financial statements prepared under prior lease accounting guidance.

At adoption, REP recorded a total of $1.0 million in operating lease ROU assets and corresponding lease liabilities in other assets and other liabilities on the accompanying consolidated balance sheet.

REP had $417 thousand in lease expense for the year ended September 30, 2020. This is included as general and administrative costs on the accompanying consolidated statement of operations.

Historical Results of Operations and Operating Expenses

Revenues and Operating Expenses

The following table provides the components of REP’s revenues, operating expenses, other income (expense) and net income (loss) for the periods indicated:

	For the Years Ended September 30,
	($ and units in thousands, except per unit amounts)
	2020			2019			2018
Statement of Operations Data:
Revenues:
Oil and natural gas sales, net	$	73,133		$	101,096		$	69,872
Contract services - related parties		3,800			1,900			—
Total Revenues		76,933			102,996			69,872
Operating Expenses:
Lease operating expenses		20,997			23,808			11,044
Gathering, processing & transportation		—			—			735
Production taxes		3,526			4,804			3,207
Exploration costs		9,923			5,074			5,992
Depletion, depreciation, amortization, and accretion		21,479			20,182			15,714
General and administrative costs
Administrative Costs		10,826			12,168			14,175
Unit-based compensation expense		963			898			—
Cost of contract services - related party		503			21			—
Transaction costs		1,431			4,553			878
Total Operating Expenses		69,648			71,508			51,745

Income (Loss) From Operations		7,285			31,488			18,127
Other Income (Expenses):
Interest Expense		(5,299	)		(4,924	)		(1,707	)
Gain (loss) on derivatives		33,876			26,712			(17,143	)
Total Other Income (Expense)		28,577			21,788			(18,850	)

Net Income (Loss) Before Income Taxes		35,862			53,276			(723	)
Income Tax Expense		(718	)		(1,410	)		—
Net Income (Loss)		35,144			51,866			(723	)
Dividends on Preferred Units		(3,535	)		(3,330	)		(3,129	)
Net Income (Loss) Attributable to Common Unitholders	$	31,609		$	48,536		$	(3,852	)
Net Income (loss) per unit:
Basic	$	20.67		$	31.87		$	(2.57	)
Diluted	$	17.24		$	26.03		$	(2.57	)
Weighted Average Common Units Outstanding:
Basic		1,529			1,523			1,500
Diluted		2,038			1,992			1,500

Production and Operating Data

The following table provides a summary of REP’s sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:

	For the Years Ended September 30,
	2020			2019			2018
Total Sales Volumes:
Oil (MBbls)		2,060			1,975			1,195
Natural Gas (MMcf)		1,628			886			197
NGL (MBbls)		260			135			41
Total (MBoe)⁽¹⁾		2,592			2,258			1,269
Daily Sales Volumes:
Oil sales (Bbl/d)		5,630			5,411			3,274
Natural gas sales (Mcf/d)		4,448			2,428			541
Natural gas liquids sales (Bbl/d)		710			370			113
Total (BOE/d)⁽¹⁾		7,081			6,186			3,477
Average sales price⁽¹⁾:
Oil sales (per Bbl)	$	36.35		$	51.45		$	57.19
Oil sales with derivative settlements (per Bbl)⁽²⁾		49.41			51.71			50.89
Natural gas sales (per Mcf)		(0.78	)		(0.33	)		2.04
Natural gas sales with derivative settlements (per Mcf)⁽²⁾		(0.78	)		(0.33	)		2.04
Natural gas liquids sales (per Bbl)		(1.90	)		(1.75	)		27.44
Natural gas liquids with derivative settlements (per Bbl)⁽²⁾		(1.90	)		(1.75	)		27.44
Average price per BOE excluding derivative settlements⁽¹⁾⁽²⁾		28.22			44.78			55.05
Average price per BOE including derivative settlements⁽¹⁾⁽²⁾		38.61			45.00			49.12
Expenses per BOE⁽¹⁾:
Lease operating expenses	$	8.10		$	10.54		$	8.70
Production and ad valorem taxes		1.36			2.13			2.53
Exploration expenses		3.83			2.25			4.72
Depletion, depreciation, amortization, and accretion		8.29			8.94			12.38
General and administrative expenses, inclusive of unit-based compensation expense⁽³⁾		3.08			4.95			11.17
Transaction costs⁽⁴⁾		0.55			2.02			0.69

(1)	One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities.
(2)	Average prices shown in table reflect prices both before and after the effects of REP’s settlements of our commodity derivative contracts. REP’s calculation of such effects includes both gains or losses on cash settlements for commodity derivatives.
(3)	General and administrative expenses, inclusive of unit-based compensation expense shown after effect of revenue from contract services for management services agreement.
(4)	Transaction costs include non-cash cost related to REP’s previously aborted IPO.

Results of Operations – Comparison for the Years Ended September 30, 2020 and 2019

Revenue. REP’s total revenues decreased 25%, or $26.0 million, to $77.0 million for the year ended September 30, 2020 as compared to total revenues of $103.0 million for the year ended September 30, 2019. The decrease was mainly attributable to the drop in commodity prices due to COVID-19 that drastically decreased demand for oil and natural gas. Furthermore, the supply-and-demand imbalance has been exacerbated by uncertainty regarding the future global supply of oil due to disputes between Russia and the members of the Organization of the Petroleum Exporting Countries (“OPEC”), particularly Saudi Arabia, in March 2020. This lead to a swift and material deterioration in commodity prices in early 2020.

REP’s total revenue decrease was slightly offset by the increase of $1.9 million in contract services – related parties revenue, to $3.8 million for the year ended September 30, 2020 as compared to contract services – related parties revenue of $1.9 million for the year ended September 30, 2019. The increase was attributable to REP performing the services for the full year ended September 30, 2020 as compared to only performing the services for several months for the year ended September 30, 2019.

REP’s revenues are primarily from the sale of crude oil. For the year ended September 30, 2020 and 2019, crude oil contributed to 95% and 98% of REP’s total revenue, respectively. REP’s total sales volumes for the year ended September 30, 2020 was 2,592 MBoe compared with 2,258 MBoe for the year ended September 30, 2019. This represents a period over period increase of 15%, or 334 MBoe. REP has grown its average net production from 6,186 Boe/d for the year ended September 30, 2019 to an average net production of 7,081 Boe/d for the year ended September 30, 2020, representing a 14% increase year over year. The increase is primarily due to the development of REP’s properties.

Lease operating expenses. REP’s LOEs decreased by 12%, or $2.8 million, to $21.0 million for the year ended September 30, 2020, from $23.8 million for the year ended September 30, 2019. On a per unit basis, LOE decreased from $10.54 per BOE for the year ended September 30, 2019 to $8.10 per BOE for the year ended September 30, 2020. This decrease in LOE per unit of $2.44 is primarily attributable to a 15% increase in production during the same period and reflects the distribution of fixed costs spread over higher production volumes as well as a general decline in cost associated with the wells that were shut-in during REP’s second and third fiscal quarters due to lower commodity prices caused by COVID-19.

Production taxes. Production taxes decreased $1.3 million to $3.5 million during the year ended September 30, 2020 from $4.8 million during the year ended September 30, 2019 due to lower revenues resulting from lower pricing in 2020.

Exploration costs. REP’s exploration costs of $9.9 million for the year ended September 30, 2020, as compared to $5.0 million for the year ended September 30, 2019, are primarily comprised of $7.9 million in oil and natural gas lease abandonment costs in which REP does not expect to renew prior to expiration. REP also expensed geological and geophysical costs of $2.0 million and $0.2 million, respectively, during the year ended September 30, 2020 and 2019.

Depletion, depreciation, amortization and accretion expense. REP’s depletion, depreciation, amortization and accretion expense, or DD&A, increased $1.3 million to $21.5 million for the year ended September 30, 2020 as compared to $20.2 million for the year ended September 30, 2019. This increase was due to higher production volumes for the year ended September 30, 2020 as compared to the year ended September 30, 2019. On a per unit basis, DD&A decreased from $8.94 per BOE for the year ended September 30, 2019 to $8.29 per BOE for the year ended September 30, 2020. The per BOE decrease was primarily attributable to the increase in total proved reserves and proved developed reserves.

General and administrative cost. General and administrative, or G&A, costs decreased by $1.2 million to $11.8 million for the year ended September 30, 2020 as compared to $13.0 million for the year ended September 30, 2019. This decrease is primarily due to the drop in information technology, legal and consulting expenses. On a per unit basis, G&A costs decreased from $4.95 per BOE for the year ended September 30, 2019 to $3.08 per BOE for the year ended September 30, 2020. This per unit decrease was primarily attributable to higher production volumes.

Transaction costs. Transaction costs were $1.4 million for the year ended September 30, 2020 compared to $4.6 million for the year ended September 30, 2019. The decrease was due to the write-off of approximately $4.6 million of deferred equity issuance costs associated with the preparation and filing of the Company’s previous registration statements on Form S-1 for the year ended September 30, 2019. The $1.4 million of transaction cost for the year ended September 30, 2020 is related to the merger between REP and TGC.

Interest expense. Interest expense was $5.3 million for the year ended September 30, 2020 compared to $4.9 million for the year ended September 30, 2019. The increase was due to the additional borrowings on the revolving credit facility.

Income tax expense. Income tax expense was $0.7 million for the year ended September 30, 2020 compared to $1.4 million for the year ended September 30, 2019. The decrease was due to less income being earned for the year ended September 30, 2020 due to decreased commodity prices as a result of COVID-19.

Results of Operations - Comparison for the Years Ended September 30, 2019 and 2018

Revenue. REP’s total revenues increased 47%, or $33.1 million, to $103.0 million for the year ended September 30, 2019 as compared to total revenues of $69.9 million for the year ended September 30, 2018. The increase was mainly attributable to increased production volumes from REP’s drilling program.

REP’s total revenues included the increase of $1.9 million in contract services – related parties revenue for the year ended September 30, 2019 as compared to contract services – related parties revenue of $0.0 million for the year ended September 30, 2018. The increase was attributable to REP entering into a contract services agreement with Riley Permian Operating Company, LLC during the year ended September 30, 2019.

REP’s revenues are primarily from the sale of crude oil. For the years ended September 30, 2019 and 2018, crude oil contributed to 98% and 98%, respectively, of REP’s total revenues. REP’s total sales volumes for the fiscal year ended 2019 was 2,258 MBoe compared with 1,269 MBoe for the fiscal year ended 2018. This represents a year over year increase of 78%, or 989 MBoe. REP has grown its average net production from 3,477 Boe/d for REP’s fiscal year ended September 30, 2018 to an average net production of 6,186 Boe/d for REP’s fiscal year ended September 30, 2019, representing a 78% increase year over year. The annual volume increase is primarily due to the development of REP’s properties.

Lease operating expenses. REP’s LOE increased by 116%, or $12.8 million, to $23.8 million for the year ended September 30, 2019, from $11.0 million for the year ended September 30, 2018. The year over year increase was primarily attributable to the net increase in well count that was the result of REP’s successful drilling activity. On a per unit basis, LOE increased from $8.70 per BOE for the year ended September 30, 2018 to $10.54 per BOE for the year ended September 30, 2019. This increase in LOE per unit of $1.84 is primarily the result of increased workover activity and higher monthly rental rates for electric submersible pumps and wellhead generators, increased wellhead chemical costs, and an increased number of field employees, resulting in higher company labor costs.

Production taxes. Production taxes increased $1.6 million to $4.8 million during the year ended September 30, 2019 from $3.2 million during the year ended September 30, 2018 due to increased revenues resulting from higher production volumes and commodity prices.

Exploration costs. REP’s exploration costs were $5.1 million for the year ended September 30, 2019, as compared to $6.0 million for the year ended September 30, 2018. REP elected to let a portion of its undeveloped leases expire throughout the year ended September 30, 2019.

Depletion, depreciation, amortization and accretion expense. REP’s depletion, depreciation, amortization and accretion expense, or DD&A, increased $4.5 million to $20.2 million for the year ended September 30, 2019 as compared to $15.7 million for the year ended September 30, 2018. This increase was due to substantially higher production volumes for the year ended September 30, 2019 as compared to fiscal year ended September 30, 2018. On a per unit basis, DD&A expense decreased to $8.94 per BOE for the year ended September 30, 2019 from $12.38 per BOE for the year ended September 30, 2018. The per BOE decrease was primarily attributable to the increase of proved reserves.

Impairment of long-lived assets. For the years ended September 30, 2019 and 2018 respectively, REP did not recognize any impairment expense associated with REP’s proved properties.

General and administrative. General and administrative, or G&A, costs decreased by $1.1 million to $13.1 million for the year ended September 30, 2019 as compared to $14.2 million for the year ended September 30, 2018. This decrease was due to a drop in professional fees, software costs, and other required expenses. On a per unit basis, G&A costs decreased from $11.17 per BOE for the year ended September 30, 2018 to $4.95 per BOE for the year ended September 30, 2019. This per unit decrease was primarily attributable to higher production volumes.

Transaction costs. Transaction costs were $4.6 million for the year ended September 30, 2019 compared to $0.9 million for the year ended September 30, 2018. The $4.6 million was associated with the deferred IPO costs that incorporated the preparation and filing of Riley’s S-1 and the amendments thereto. Furthermore, the amount included an additional $1.9 million incurred in 2019 that was initially capitalized and $2.7 million previously capitalized in 2018. Riley’s planned IPO was abandoned in 2019 so all of the deferred IPO costs were expensed.

Interest expense. Interest expense was $4.9 million for the year ended September 30, 2019 compared to $1.7 million for the year ended September 30, 2018. The increase was due to the additional borrowings on the revolving credit facility.

Income tax expense: Income tax expense was $1.4 million for the year ended September 30, 2020 compared to $0 million for the year ended September 30, 2019. The increase was due to the positive difference for REP’s oil revenue compared to operating expenses pertaining to those assets during the year ended September 30, 2020.

Liquidity and Capital Resources

REP’s development and acquisition activities require it to make significant operating and capital expenditures. REP’s primary use of capital has been for the exploration and development of its oil and gas properties, the supporting infrastructure to include the design and construction of a private gathering and saltwater disposal system, and the power distribution network. Historically, REP’s primary sources of liquidity have been equity provided by investors and cash flows from operations, as well as borrowing under REP’s revolving credit facility. Future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop REP’s properties. For example, REP expects a portion of our future capital expenditures to be financed with cash flows from operations derived from wells drilled in drilling location not associated with proved reserves on REP’s September 30, 2020 reserve report. The failure to achieve anticipated production and cash flows from operations from such wells could result in a reduction in future capital spending. Further, REP’s capital expenditure budget for the year ended September 30, 2020 and 2021 does not allocate any amounts for acquisitions of oil and natural gas properties. In the event REP makes additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, REP could be required to reduce the expected level of capital expenditures and/or seek additional capital. If REP requires additional capital for that or other reasons, it may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, assets sales, offerings of debt or equity securities or other means. REP cannot assure you that needed capital will be available on acceptable terms or at all. If REP is unable to obtain funds when needed or on acceptable terms. REP may be required to curtail its current drilling programs, which could result in a loss of acreage through lease expiration. In addition, REP may not be able to complete acquisitions that may be favorable to it or finance the capital expenditures necessary to replace its reserves.

From REP’s inception through September 30, 2020, REP has raised an aggregate of $50.0 million of capital in exchange for its Series A Preferred Units from its existing investors, consisting of contributions by Yorktown of approximately $21.4 million, Bluescape of approximately $21.4 million and Boomer of approximately $7.2 million. The Series A Preferred Units were entitled to receive dividends of 6.0% per year, payable quarterly in kind by the issuance of additional Series A Preferred Units. However, the REP board of managers may determine in its sole discretion to pay the dividends in cash.

As of September 30, 2020, REP authorized and declared quarterly cash dividends totaling approximately $15 million. The cash dividends were issued on all issued and outstanding common units including the vested 2018 Long-Term Incentive Plan (the “2018 LTIP”) units of REP. The portion of the cash dividend attributable to the unvested restricted units was accrued and will be paid in cash once the unvested restricted units fully vest. Cash dividends are approved at the sole discretion of the REP board of managers. The credit agreement generally restricts the payment of dividends or distributions on any class of REP’s capital stock, with certain accommodations subject to customary conditions.

REP’s decision to pay any future dividends is solely within the discretion of, and subject to approval by, the REP board of managers. The REP board of managers’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend on REP’s results of operations, financial condition, liquidity, capital requirements, contractual restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.

REP plans to continue its practice of entering into hedging arrangements to reduce the impact of commodity price volatility on REP’s cash flow from operations. Under this strategy, REP expects to maintain an active hedging program which REP believes will provide more certainty around its cash flow, returns and its ability to fund its capital program while also securing a portion of REP’s borrowing base under its revolving credit facility.

For the year ended September 30, 2020, REP’s average net daily production was 7,081 BOE/d, of which approximately 80% was oil, 10% was natural gas and 10% was NGLs. As of September 30, 2020, REP produced from 130 gross (71 net) wells that included both its operated and non-operated wells combined. This represented an increase of 11 gross (3 net) wells when compared to the year ended September 30, 2019. During the fiscal year ended September 30, 2020, REP incurred capitalized costs of $49 million, of which approximately $35.7 million was allocated for drilling and completion activity, approximately $4.3 million for continued infrastructure buildout (e.g. saltwater disposal and electrical infrastructure), approximately $5.3 million for leasehold acquisition and renewal efforts, and approximately $3.6 million for capitalized workovers.

Because REP operates a high percentage of its acreage, capital expenditure amounts and timing are largely discretionary and within REP’s control. REP determines its capital expenditures depending on a variety of factors, including, but not limited to, the success of REP’s drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if REP curtails its drilling program, REP may lose a portion of its acreage through lease expirations. See “Riley Exploration—Permian LLC Business—Oil, Natural Gas and NGL Production Prices and Production Costs—Developed and Undeveloped Acreage.” In addition, REP may be required to reclassify some portion of REP’s reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means REP will be unable to develop such reserves within five years of their initial booking.

Effective October 15, 2019, REP amended its credit facility to increase the borrowing base from $135 million to $180 million and reserved the ability to request an increase in its lender commitments up to the approved $200 million borrowing base amount. Effective May 7, 2020, REP amended its credit facility to decrease the borrowing base from $180 million to $150 million.

On August 31, 2020, REP entered into the Sixth Amendment to decrease the borrowing base from $150 million to $132.5 million. Additionally, the Sixth Amendment changed the maximum net leverage ratio for ordinary quarterly covenant compliance to 3.5 to 1.0 from 4.0 to 1.0, and changed the maximum net leverage ratio for Restricted Payments (as defined in REP’s credit agreement) after giving pro forma effect to such Restricted Payments (which includes payments to any holder of REP’s capital units) to 2.75 to 1.0 from 3.0 to 1.0. REP is also required to prepay the credit facility if at any time the consolidated cash balance is in excess of the greater of $15 million and 10% of the borrowing base for five consecutive business days and REP has not identified an approved intended use for the excess cash. REP’s minimum hedging requirement was also increased from 45% to 50%.

If cash flow from operations does not meet REP’s expectations, REP may reduce its expected level of capital expenditures and/or fund a portion of its capital expenditures using borrowings under REP’s revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. REP cannot assure you that necessary capital will be available on acceptable terms or at all. REP’s ability to raise funds through the incurrence of additional indebtedness are limited by the covenants in REP’s revolving credit facility. If REP is unable to obtain funds when needed or on acceptable terms, REP may not be able to complete acquisitions that may be favorable to it or finance the capital expenditures necessary to maintain its production or proved reserves.

Based upon REP’s current oil and natural gas price expectations for fiscal 2021, REP’s cash flow from operations and borrowings under REP’s revolving credit facility will provide it with sufficient liquidity through fiscal 2021 and beyond. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop REP’s properties. If REP requires additional capital for capital expenditures, acquisitions or other reasons, REP may seek such capital through traditional reserve base borrowings, and subject to covenants in its revolving credit facility, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. If REP is unable to obtain funds when needed or on acceptable terms, REP may be required to curtail its current drilling program, which could result in a loss of acreage through lease expirations. In addition, REP may not be able to complete acquisitions that may be favorable to it or finance the capital expenditures necessary to maintain REP production or replace its reserves.

Working Capital

REP’s working capital, which REP defines as current assets minus current liabilities, totaled a surplus of $13.8 million at September 30, 2020. At September 30, 2019, REP had a working capital surplus of approximately $4.0 million. REP may incur working capital deficits in the future due to the amounts that accrue related to its drilling program and changes in the value of its derivative assets and liabilities. REP’s collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. REP’s cash and cash equivalents balance totaled approximately $1.6 million at September 30, 2020 and was $3.7 million at September 30, 2019, respectively. REP expects that its cash flows from operating activities and availability under REP’s revolving credit facility will be sufficient to fund its working capital needs through fiscal 2021. REP expects that its pace of development, production volumes, commodity prices and differentials to NYMEX prices for REP’s oil and natural gas production will be the largest variables affecting REP’s working capital. Please see “—Liquidity and Capital Resources” above for factors relating to liquidity and current expectations.

Cash Flows

The following table summarizes REP’s cash flows for the periods indicated:

		For the Years Ended September 30,
		2020			2019			2018
		($ in Thousands)
Statement of Cash Flows Data:
Net cash provided by operating activities	$	62,550		$	52,007		$	38,619
Net cash used in investing activities	$	(51,521	)	$	(83,398	)	$	(88,389	)
Net cash (used) in/provided by financing activities	$	(13,095	)	$	31,778		$	49,426

Year Ended September 30, 2020 Compared to the Year Ended September 30, 2019

Net cash provided by operating activities. REP’s net cash position provided by operating activities increased by $10.5 million for the year ended September 30, 2020 as compared to the year ended September 30, 2019, primarily due to an increase in settlements on derivative contracts of $26.4 million that was offset by net income decreasing $16.8 million due to a decrease in commodity prices because of COVID-19 pandemic for the year ended September 30, 2020.

Net cash used in investing activities. For the year ended September 30, 2020 as compared to the year ended September 30, 2019, REP’s net cash used in investing activities decreased by $31.8 million, primarily due to lower capital expenditures.

Net cash (used) in/provided by financing activities. For the year ended September 30, 2020 as compared to the year ended September 30, 2019, REP’s net cash used by financing activities decreased by $44.8 million, primarily due to net proceeds received from the revolving credit facility of $43.2 million for the year ended September 30, 2019 as compared to $4.0 million for the year ended September 30, 2020 as well as the payment of common unit dividends of $10.0 million for the year ended September 30, 2019 as compared to $15.3 million for the year ended September 30, 2020. See “—Liquidity and Capital Resources” above for a discussion of REP’s capital structure.

Year Ended September 30, 2019 Compared to the Year Ended September 30, 2018

Net cash provided by operating activities. REP’s net cash position provided by operating activities increased by $13.4 million, primarily due to increased net income of $51.9 million resulting from higher commodity prices and production volumes for the year ended September 30, 2019.

Net cash used in investing activities. For the year ended September 30, 2019 as compared to the year ended September 30, 2018, REP’s net cash used in investing activities decreased by $5.0 million, primarily due to a decrease in acquisitions of oil and natural gas properties.

Net cash provided by financing activities. For the year ended September 30, 2019 as compared to the year ended September 30, 2018, REP’s net cash provided by financing activities decreased by $17.6 million, primarily due to lower net proceeds taken from the revolving credit facility, offset by the approximately $7.5 million in additional dividends paid.

REP’s Revolving Credit Facility

On September 28, 2017, REP and Truist Bank, successor by merger to SunTrust Bank, as administrative agent, entered into a credit agreement to establish a senior secured revolving credit facility. The credit facility had an initial borrowing base of $25 million with a maximum facility amount of $500 million. The scheduled maturity date of the credit facility was originally September 28, 2021, but the scheduled maturity date was extended to September 28, 2023 pursuant to a sixth amendment to the credit facility (the “Sixth Amendment”) on August 31, 2020. Substantially all of REP’s assets are secured under the credit facility.

Effective February 27, 2018, REP amended its credit facility to increase the borrowing base from $25 million to $60 million. Effective May 25, 2018, REP amended its credit facility to increase the borrowing base from $60 million to $100 million. Effective November 9, 2018, REP amended its credit facility to increase the borrowing base from $100 million to $135 million. Effective April 3, 2019, REP amended its credit facility to allow for a future increase in the borrowing base from $135 million to $175 million.

Effective October 15, 2019, REP amended its credit facility to increase the borrowing base from $175 million to $180 million and reserved the ability to request an increase in its lender commitments up to the approved $200 million borrowing base amount. Effective May 7, 2020, REP amended its credit facility to decrease the borrowing base from $180 million to $150 million.

On August 31, 2020, REP entered into the Sixth Amendment to decrease the borrowing base from $150 million to $132.5 million Additionally, the Sixth Amendment changed the maximum net leverage ratio for ordinary quarterly covenant compliance to not more than 3.5 to 1.0 from 4.0 to 1.0, and changed the maximum net leverage ratio for Restricted Payments after giving pro forma effect to such Restricted Payments, which includes payments to any holder of REP ‘s capital units, to 2.75 to 1.0 from 3.0 to 1.0. REP is also required to prepay the credit facility if at any time the consolidated cash balance is in excess of the greater of $15 million and 10% of the borrowing base for five consecutive business days and REP has not identified an approved intended use for the excess cash. REP’s minimum hedging requirement was also increased from 45% to 50%.

The amount available to be borrowed under REP’s revolving credit facility is subject to a borrowing base that is redetermined semiannually each February 1 and August 1 by the lenders in their sole discretion. Additionally, at REP’s option, REP may request an additional redetermination each six-month period between each of February 1 and August 1. The borrowing base depends on, among other things, the volumes of REP’s proved reserves and estimated cash flows from these reserves and REP’s commodity hedge positions as well as any other outstanding debt. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, REP could be required to repay a portion of the debt outstanding or provide additional collateral under its credit agreement.

REP pays a commitment fee on unused amounts of its revolving credit facility of between 0.375% and 0.500% per annum, depending on the utilization percentage of REP’s borrowing base. REP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

REP’s credit agreement contains restrictive covenants that limit REP’s ability to, among other things:

•	incur additional indebtedness and certain types of preferred equity;
•	incur liens;
•	merge or consolidate with another entity or acquire subsidiaries;
•	make investments;
•	make loans to others;
•	make certain payments;
•	sell assets;
•	terminate hedging transactions;
•	enter into certain types of transactions with affiliates;
•	enter into restrictive agreements relating to subsidiaries or the incurrence of liens;
•	enter into sale and leaseback transactions;
•	amend REP’s material documents or make significant accounting changes; and
•	engage in certain other transactions without the prior consent of the lenders.

REP’s credit agreement also requires REP to maintain compliance with the following financial ratios:

•

a current ratio, which is the ratio of REP’s consolidated current assets (including unused commitments under REP’s revolving credit facility and excluding derivatives) to REP’s consolidated current liabilities (excluding the current portion of long-term indebtedness required to be paid within one year and the aggregate principal balance of loans and letters of credit under REP’s credit agreement and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0; and

•

a leverage ratio, which is the ratio of REP’s consolidated total debt (as defined in REP’s credit agreement) as of the last day of each fiscal quarter, less cash and cash equivalents of up to the greater of $15.0 million and 10.0% of the borrowing base, subject to certain exclusions (as described in REP’s credit agreement) to consolidated EBITDAX (as defined in REP’s credit agreement) for the last four consecutive fiscal quarters ending on or immediately prior to the last day of that fiscal quarter, of not greater than 3.5 to 1.0.

REP is also required to prepay the credit facility if at any time the consolidated cash balance is in excess of the greater of $15 million or 10% of the borrowing base for five consecutive business days and REP has not identified an approved intended use for the excess cash. The credit agreement also contains other customary affirmative and negative covenants and events of default. REP’s minimum hedging requirement was 50% as of September 30, 2020.

Further, under REP’s credit agreement, REP is only permitted to hedge up to 85% of its reasonably anticipated production of each of oil and natural gas for up to 24 months in the future, and up to 75% of its reasonably anticipated production of each of oil and natural gas for 25 to 48 months in the future. REP is also required to hedge a minimum of 50% of its projected oil and natural gas volumes from PDP reserves on a 24-month rolling basis. In respect of interest rate hedging from floating to a fixed rate, under REP’s credit agreement, REP is only permitted to hedge up to 75% of its then outstanding principal indebtedness for borrowed money that bears interest at a floating rate and that hedge transaction cannot have a maturity date beyond the indebtedness’ maturity date.

Contractual Obligations

A summary of REP’s contractual obligations as of September 30, 2020 is provided in the following table (in thousands):

	Payments due by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
	(unaudited)
Contractual Obligations
Credit Facility⁽¹⁾	$	101,000	$	—	$	101,000	$	—	$	—
Interest expenses related to Credit Facility⁽²⁾	$	16,524	$	4,131	$	12,393	$	—	$	—
Office lease⁽³⁾	$	740	$	419	$	321	$	—	$	—
Total	$	118,264	$	4,550	$	113,714	$	—	$	—

(1)	The REP credit facility matures on September 28, 2023.
(2)	Includes interest expense on our outstanding borrowings calculated using the weighted average interest rate of 4.09% at September 30, 2020.
(3)	REP leases office headquarters under a five-year operating lease agreement terminating in July 2022. Base rent is subject to a two percent (2%) escalation in each subsequent year.

The above contractual obligations schedule does not include future anticipated settlement of derivative contracts or estimated amounts expected to be incurred in the future associated with the abandonment of REP’s oil and gas properties, as REP cannot determine with accuracy the timing of such payments. For further discussion regarding REP’s derivative contracts and estimated future costs associated with the abandonment of REP’s oil and gas properties, please refer to Note 3—Summary of Significant Accounting Policies under section Derivative Contracts and Asset Retirement Obligations of REP’s historical audited financial statements for the years ended September 30, 2020, 2019 and 2018 and to Note 6—Derivative Instruments. Additionally, for further information regarding REP’s contractual obligations as of September 30, 2020, please refer to Note 15—Commitments and Contingencies to REP’s audited financial statements for the year ended September 30, 2020.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT THE MARKET RISK OF REP

REP is exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about REP’s potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of REP’s market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

REP’s major market risk exposure is in the pricing that REP receives for its oil, natural gas and NGLs production, and primarily REP’s oil production. Pricing for crude oil, natural gas and NGLs has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices REP receives for its oil, natural gas and NGLs depend on many factors outside of REP’s control, such as the strength of the global economy and global supply and demand for the commodities REP produces.

At September 30, 2020 and September 30, 2019 REP had a net asset derivative position of $21.9 million and $14.9 million, respectively, related to REP’s price swaps and collars, to reduce price volatility associated with certain of REP’s oil and natural gas sales. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit REP’s potential gains from future increases in prices. With respect to these fixed price swap contracts, the counterparty is required to make payment to REP if the settlement price for any settlement period is less than the swap price, and REP is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. REP’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate pricing and Crude Oil – Brent and with natural gas derivative settlements based on NYMEX Henry Hub and Waha Hub pricing.

Due to this volatility, REP has historically used, and REP expects to continue to use, commodity derivative instruments, such as swaps and collars, to hedge price risk associated with a portion of REP’s anticipated production. REP’s hedging instruments allow it to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for its drilling program and debt service requirements. Under REP’s credit agreement, REP is only permitted to hedge up to 85% of its reasonably anticipated production of oil and natural gas for up to 24 months in the future, and up to 75% of its reasonably anticipated production of oil and natural gas for 25 to 48 months in the future. REP is also required to hedge a minimum of 50% of its projected oil and natural gas volumes from PDP reserves on a 24-month rolling basis. See “—Liquidity and Capital Resources— REP’s Revolving Credit Facility” above, for more information.

The table below presents REP’s open hedge positions as of September 30, 2020:

				Weighted Average Price
Calendar Quarter		Notional Volume		Fixed		Put		Call
		(Bbl)		($ per Bbl)
Crude Oil Swaps⁽¹⁾
	Q4 2020		339,000	$	57.15	$	—	$	—
	Q1 2021		405,000	$	53.01	$	—	$	—
	Q2 2021		405,000	$	53.01	$	—	$	—
	Q3 2021		405,000	$	53.01	$	—	$	—
	Q4 2021		405,000	$	53.01	$	—	$	—
	2022		360,000	$	45.25	$	—	$	—
Crude Oil Collars⁽¹⁾
	Q4 2020		45,000	$	—	$	50.00	$	56.48
	2022		360,000	$	—	$	35.00	$	42.63
Crude Oil Basis⁽²⁾
	Q4 2020		384,000	$	0.39	$	—	$	—
	Q1 2021		435,000	$	0.40	$	—	$	—
	Q2 2021		435,000	$	0.40	$	—	$	—
	Q3 2021		435,000	$	0.40	$	—	$	—
	Q4 2021		435,000	$	0.40	$	—	$	—

(1)	Reference Price is NYMEX WTI Price, referring to the West Texas Intermediate crude oil price on the New York Mercantile Exchange.
(2)	Reference Price is NYMEX WTI vs. WTI Midland (Argus) Calendar Trade Month.

Counterparty and Customer Credit Risk

REP’s cash and cash equivalents are exposed to concentrations of credit risk. REP manages and controls this risk by investing these funds with major financial institutions. REP often has balances in excess of the federally insured limits.

REP’s derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While REP does not require counterparties to its derivative contracts to post collateral, REP does evaluate the credit standing of such counterparties as it deems appropriate. Certain counterparties are financial institutions that participate as lenders in REP’s revolving credit facility. The counterparties to REP’s derivative contracts currently in place have investment grade ratings.

REP’s principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of its oil and natural gas production due to the concentration of its oil and natural gas receivables with very few significant customers. The inability or failure of REP’s significant customers to meet their obligations to REP or their insolvency or liquidation may adversely affect REP’s financial results.

Joint operations receivables arise from billings to entities that own partial interests in the wells REP operates. These entities participate in REP’s wells primarily based on their ownership in leases on which REP intends to drill. REP has little ability to control whether these entities will participate in its wells.

Interest Rate Risk

Interest is calculated under the terms of REP’s credit agreement based on certain specified base rates plus an applicable margin that varies based on utilization. As of September 30, 2020, REP had $101.0 million of outstanding borrowings and an additional $31.5 million available under its revolving credit facility. REP has entered into floating-to-fixed interest rate swaps to manage interest rate exposure related to the revolving credit facility.

Cyber Security Risk

REP’s reliance on information technology, including those hosted by third parties, exposes REP to cyber security risks that could affect REP’s business, financial condition or reputation and increase compliance challenges.

REP relies on information technology systems, including internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting its business. REP’s information technology systems, as well as those of third parties REP uses in its operations, may be vulnerable to a variety of evolving cybersecurity risks, such as those involving unauthorized access or control, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions. These cybersecurity threat actors, whether internal or external to us, are becoming more sophisticated and coordinated in their attempts to access REP’s information technology systems and data, including the information technology systems of cloud providers and other third parties with whom REP conducts business.

Although REP has implemented information technology controls and systems that are designed to protect information and mitigate the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the enhanced controls REP has installed may be breached. If REP’s information technology systems cease to function properly or REP’s cybersecurity is breached, REP could suffer disruptions to its normal operations. A cyber attack involving REP’s information systems and related infrastructure, or that of its business associates, could negatively impact its operations in a variety of ways, including, but not limited to, the following:

•	Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on REP’s ability to compete for oil and natural gas resources;
•	A cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt REP’s major development projects;
•	A cyber attack on third-party gathering, pipeline, or rail transportation systems could delay or prevent REP’s outside operators from transporting and marketing production, resulting in a loss of revenues;
•	A cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for REP’s production, lower natural gas prices, and reduced revenues; and
•	A deliberate corruption of REP’s financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties.

All of the above could negatively impact REP’s operational and financial results. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve, REP may be required to expend significant additional resources to continue to modify or enhance REP’s protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

Critical Accounting Policies and Estimates

The discussion and analysis of REP’s financial condition and results of operations are based upon REP’s consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of financial statements requires REP to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The consolidated financial statements are based on a number of significant estimates, including estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable and accrued operating expenses, the fair value determination of acquired assets and liabilities, certain tax accrual and the fair value of derivatives.

Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of REP’s consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.

The preparation of REP’s financial statements requires REP to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. REP evaluates its estimates and assumptions on a regular basis. REP bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties; (3) depreciation, depletion, amortization and accretion, or DD&A; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accounts receivable; (7) valuation of commodity derivative instruments; (8) accrued liabilities; and (9) deferred income tax liabilities. Actual results may differ from these estimates and assumptions used in preparation of REP’s consolidated and unaudited pro forma condensed consolidated and combined financial statements. See Note 3 of the notes to the audited financial statements for the years ended September 30, 2020, 2019 and 2018, respectively, included in our Form 8-K filed with the SEC on March 4, 2021 for an expanded discussion of REP’s significant accounting policies and estimates by REP’s management.

Successful Efforts Method of Accounting

REP’s oil and natural gas exploration and developments costs are accounted for using the successful efforts method. Under the successful efforts method, all costs incurred related to the acquisition of oil and natural gas properties and the costs of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed if and when the well is determined not to have found reserves in commercial quantities. Other items charged to expenses generally include geological and geophysical costs, delay rentals and lease and well operating costs.

Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement obligations, are depleted or amortized based on proved developed reserves on a field basis.

Proved Oil and Natural Gas Properties. Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement obligations, are depleted based on proved developed reserves on a field basis.

Unproved Properties. Unproved oil and natural gas properties consist of costs to acquire undeveloped leases and unproved reserves and are capitalized when incurred. When a successful well is drilled on undeveloped leasehold or reserves are otherwise attributable to a property, unproved property costs are transferred to proved properties.

Exploration Costs. Exploration costs consist of costs incurred to identify and evaluate areas that are prospective for oil and natural gas reserves. Exploration costs include geological and geophysical costs, delay rentals, expired leasehold and unsuccessful exploratory wells.

Exploratory Well Costs. Exploratory well costs are capitalized as incurred pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

Impairment of Oil and Natural Gas Properties

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. REP estimates the expected future cash flows of oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, REP will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, cash flow from commodity hedges, estimated future capital expenditures and a commensurate discount rate.

Unproved properties are periodically assessed for impairment on a property-by-property basis. REP evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage, and record impairment expense for any decline in value.

Oil and Natural Gas Reserve Quantities

REP engaged NSAI, its independent petroleum engineer, to prepare REP’s total estimated proved, probable and possible reserves. REP expects reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. REP evaluates and estimates its proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Derivative Instruments

REP utilizes commodity derivative instruments to manage REP’s exposure to commodity price volatility. All of REP’s commodity derivative instruments are utilized to manage price risk attributable to its expected production, and REP does not enter into such instruments for speculative trading purposes. REP does not designate any derivative instruments as cash flow hedges for financial reporting purposes. REP records all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. REP records gains and losses from the change in fair value of derivative instruments in current earnings as they occur.

Depreciation, Depletion and Amortization

REP’s rate of Depreciation, Depletion and Amortization, or rate of DD&A, is dependent upon REP’s estimates of total proved and proved developed reserves, which incorporate various assumptions and future projections. If REP’s estimates of total proved or proved developed reserves decline, the rate at which REP records DD&A expense increases, which in turn reduces REP’s net income. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and REP is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of REP’s exploration and development program, as well as future economic conditions.

Asset Retirement Obligations

REP’s asset retirement obligations, or ARO, consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, REP must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense (recorded within DD&A). The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.

Income Taxes

Recently Issued Accounting Pronouncements

The accounting standard-setting organizations frequently issue new or revised accounting rules. REP regularly reviews new pronouncements to determine their impact, if any, on REP’s financial statements.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). The new standard will replace most existing revenue recognition guidance in U.S. GAAP. The core principle of ASU 2014-09 requires companies to reevaluate when revenue is recorded on a transaction based upon newly defined criteria, either at a point in time or over time as goods or services are delivered. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and estimates, and changes in those estimates. In early 2016, the FASB issued additional guidance: ASU No. 2016-10, 2016-11 and 2016-12 (and together with ASU 2014-09, “Revenue Recognition ASU”). These updates provide further guidance and clarification on specific items within the previously issued ASU 2014-09. REP adopted this standard effective October 1, 2018 using the modified retrospective approach. As a result, REP changed its accounting policy for revenue recognition. REP also implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the required disclosures under the standards.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which amends the accounting standards for leases. ASU 2016-02 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Certain aspects of lease accounting have been simplified and additional qualitative and quantitative disclosures are required along with specific quantitative disclosures required by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. REP adopted the standard on October 1, 2019 using the modified retrospective transition approach, which allows REP to apply the previous lease guidance and disclosure requirements under ASC Topic 840, Leases (“ASC”), in the comparative periods presented for the year of adoption. The adoption did not require an adjustment to beginning retained earnings for a cumulative effect adjustment.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses and amendments to ASU 2016-13 through subsequent ASU’s, which together amend the accounting standards for credit losses. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. Receivables arising from operating leases are not in scope of this subtopic, but rather Topic 842. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. REP does not believe the adoption of this standard will have a material impact on its consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement. The purpose of this amendment is to improve the effectiveness of disclosures in the notes of the financial statements. The amendments will be effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2019. The adoption of this guidance will not have a material impact on REP’s consolidated financial statements.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. Due to the Sixth Amendment to the REP credit agreement which included provisions in consideration of the phase out, REP applied the optional expedient pursuant to ASC 848-20-35-14, which allows reporting entities to not have to reassess the embedded derivatives under ASC 815-15.

Internal Controls and Procedures

As of September 30, 2020, REP was not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and was therefore not required to make a formal assessment of the effectiveness of REP’s internal control over financial reporting for that purpose. REP maintains a consistent level of effectiveness, including maintaining its day-to-day operations, of its financial reporting systems and its internal controls over financial reporting.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on REP’s results of operations for the years ended September 30, 2020 and 2019. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and REP tends to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in REP’s areas of operations.

Off Balance Sheet Arrangements

REP has no off-balance sheet arrangements as of September 30, 2020.

EXECUTIVE COMPENSATION OF REP

Director Compensation

No obligations with respect to compensation for board members were accrued or paid by REP during fiscal years 2017, 2018 or 2019 or as of September 30, 2020.

Going forward, we believe that attracting and retaining qualified non-employee directors will be critical to the future growth and governance of the combined company, and we may develop a non-employee director compensation program to attract and retain such non-employee directors. We also believe that a significant portion of the total compensation package for our non-employee directors should be equity-based to align the interests of directors with the combined company’s shareholders.

Each of Messrs. Arriaga and Nordberg executed an independent director agreement upon completion of the merger, the form of which is filed as an exhibit to our Form 8-K filed with the SEC on March 4, 2021. Pursuant to the independent director agreement each of Messrs. Arriaga and Nordberg are expected to receive an annual cash retainer of $65,000, a cash payment of $1,500 for each board meeting attended and $10,000 for each committee meeting attended, and as soon as practicable following the effectiveness of the merger, and on each anniversary thereafter during their term, an annual equity grant pursuant to the combined company’s LTIP of $50,000 that will vest on the one-year anniversary of the grant date. In addition, the chairperson of the audit committee and the chairperson of the nominating and corporate governance committee is expected to each receive an additional cash retainer of $15,000.

Directors who are also employees of the combined company will not receive any additional compensation for their service on the board of directors.

Executive Officer Employment Agreement

Mr. Rugen entered into an employment agreement with the combined company in connection with the closing of the merger in substantially the same form as the current employment agreements of the executive officers of REP.

Indemnification

The combined company’s amended and restated certificate of incorporation and amended and restated bylaws provide indemnification rights to the fullest extent permitted by Delaware law to the members of our board of directors and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. After the merger is effective, the combined company will evaluate its existing director and officer liability insurance coverage and make such adjustments as we deem appropriate. Additionally, upon the effectiveness of the merger, the combined company entered into separate indemnification agreements with each of its directors and executive officers. These agreements provide that the combined company will indemnify and hold harmless each indemnitee for certain losses and expenses (including attorneys’ fees) to the fullest extent permitted by its amended and restated certificate of incorporation, amended and restated bylaws, the DGCL and other applicable law. See “Certain Relationships and Related Party Transactions—Limitation of Liability and Indemnification Matters.”

REP Executive Compensation

The following compensation discussion and analysis contains statements regarding REP’s future performance goals and measures. These goals and measures are disclosed in the limited context of REP’s executive compensation program and are not statements of management’s expectations or estimates of results or other guidance. REP specifically cautions investors not to apply these statements to other contexts.

Overview and Objectives

REP believes its success depends on the continued contributions of its named executive officers. As a private company, REP established its executive compensation program to attract, motivate, and retain REP’s key employees in order to enable REP to maximize its profitability and value over the long term. REP’s policies are also intended to support the achievement of REP’s strategic objectives by aligning the interests of its executive officers with those of its unitholders through operational and financial performance goals and equity-based compensation. Following the merger, REP expects that the compensation committee of TGC’s board of directors may recommend changes to REP’s executive compensation program. Nonetheless, REP expects that its compensation program will continue to be focused on building long-term shareholder value by attracting, motivating and retaining talented, experienced executives and other key employees.

Named Executive Officers

REP’s named executive officers, consisting of its principal executive officer, principal financial officer, and its next three highly compensated executive officers, at the end of the last completed fiscal year are:

Name		Principal Position
Bobby D. Riley		Chairman of the Board and CEO
Kevin Riley		President and Interim Chief Financial Officer
Jeffrey M. Gutman⁽¹⁾		Former Executive Vice President, Chief Financial Officer and Treasurer
Corey Riley		Executive Vice President Business Intelligence
Michael Palmer		Executive Vice President Corporate Land

(1)	Mr. Gutman resigned from his position with REP on October 5, 2020.

Summary Compensation Table

The following table summarizes the total compensation awarded to, earned by or paid to REP’s named executive officers, Bobby D. Riley, Kevin M. Riley, Jeffrey M. Gutman, Corey Riley and Michael Palmer, for services performed in the years ended September 30, 2020, 2019 and 2018 (unless otherwise noted in the footnotes below).

Year		Salary ($)		Non-Equity Incentive Plan⁽¹⁾ ($)		Unit Awards⁽²⁾⁽³⁾ ($)		All Other Compensation⁽⁴⁾ ($)		Total ($)
Bobby D. Riley Chairman of the Board & CEO	2020	$	500,870	$	125,982	$	410,513	$	43,874	$	1,081,239
	2019	$	485,672	$	247,073	$	2,785,193	$	43,522	$	3,561,459
	2018	$	388,863	$	475,000	$	—	$	31,036	$	894,899

Kevin M. Riley President and Interim Chief Financial Officer	2020	$	347,973	$	87,524	$	285,255	$	38,341	$	759,093
	2019	$	337,414	$	171,650	$	1,714,943	$	36,290	$	2,260,298
	2018	$	323,109	$	330,000	$	—	$	28,781		681,890

Jeffrey M. Gutman⁽⁵⁾ Former Executive Vice President, Chief Financial Officer and Treasurer	2020	$	332,156	$	83,546	$	272,266	$	32,224	$	720,191
	2019	$	322,077	$	163,849	$	621,726	$	31,583	$	1,139,236
	2018	$	118,125	$	315,000	$	—	$	9,086	$	442,211

Corey Riley⁽⁶⁾ Executive Vice President Business Intelligence	2020	$	360,062	$	54,075	$	125,863	$	36,997	$	576,997
	2019	$	145,833	$	136,752	$	—	$	14,731	$	297,316
	2018	$	—			$	—	$	—	$	—

Michael Palmer Executive Vice President Corporate Land	2020	$	243,928	$	36,634	$	125,863	$	33,086	$	439,510
	2019	$	237,111	$	70,000	$	—	$	31,119	$	338,230
	2018	$	225,176	$	124,937	$	—	$	25,272	$	375,384

(1)	For a description of annual bonuses for the applicable year, see “-Additional Narrative Disclosures-Cash Bonuses” section below.
(2)	Amounts in this column reflect the grant date fair value of stock awards.
(3)	For unit awards, the disclosed amount is the dollar amount recognized for such individual for the fiscal year of the actual grant date (as opposed to any prior periods of service for which the grant was received).
(4)	Amounts in this column reflect (a) matching contributions to the 401(k) Plan (as defined below) made on behalf of REP’s named executive officers and (b) health and welfare premiums paid for the benefit of REP’s named executives. See “-Additional Narrative Disclosures-Other Benefits and Pension Benefits” below for more information on health and welfare premiums and matching contributions to the 401(k) Plan.
(5)	Mr. Gutman served as REP’s acting Chief Financial Officer since January 2018 and joined REP as Executive Vice President, Chief Financial Officer and Treasurer as of May 2018. Mr. Gutman resigned from his position with REP on October 5, 2020.
(6)	Mr. Corey Riley, Executive Vice President Business Intelligence became employed by the company on April 23, 2019. The compensation for that period reflects the partial year of service.

Grants of Plan-Based Awards

The following table reflects information regarding grants of plan based awards to certain of REP’s named executive officers as of September 30, 2020. As of September 30, 2020, there were no non-equity incentive plan awards or option awards held by any of REP’s named executive officers. The amounts shown in the following table for stock awards represent unit awards granted to certain of REP’s named executive officers pursuant to the 2018 LTIP.

	Grant Date	All Other Stock Awards: Number of Shares of Stock or Units (#)		Grant Date Fair Value of Stock and Option Awards⁽²⁾
Bobby D. Riley Chairman of the Board & CEO	02/01/20		4,077.00		410,513.13
Kevin M. Riley President	02/01/20		2,833.00		285,254.77
Jeffrey M. Gutman⁽¹⁾ Former Executive Vice President, Chief Financial Officer and Treasurer	02/01/20		2,704.00		272,265.76

	Grant Date	All Other Stock Awards: Number of Shares of Stock or Units (#)		Grant Date Fair Value of Stock and Option Awards⁽²⁾
Corey Riley Executive Vice President Business Intelligence	02/01/20		1,250.00		125,862.50
Michael Palmer Executive Vice President Corporate Land	02/01/20		1,250.00		125,862.50

(1)	Mr. Gutman served as REP’s acting Chief Financial Officer since January 2018 and joined REP as Executive Vice President, Chief Financial Officer and Treasurer as of May 2018. Mr. Gutman resigned from his position with REP on October 5, 2020.
(2)	Grant date fair value of Awards is $100.69 per unit for awards made on for 2/01/20 and 2/02/20.

Outstanding Equity Awards at September 30, 2020

The following table reflects information regarding outstanding equity-based awards held by certain of REP’s named executive officers as of September 30, 2020. As of September 30, 2020, there were no option awards held by any of REP’s named executive officers. The amounts shown in the following table for stock awards represent unit awards granted to certain of REP’s named executive officers pursuant to the 2018 LTIP. These unit awards represent equity-based interests in REP, which converted into shares of TGC’s common stock at or prior to the closing of the merger.

Stock Awards

	Number of Shares or Units of Stock That Have Not Vested (#)			Market Value of Shares or Units of Stock That Have Not Vested (2) ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Bobby D. Riley Chairman of the Board & CEO		2,726.67	⁽³⁾	$	274,548.40		—		—
Bobby D. Riley Chairman of the Board & CEO		4,077	⁽⁴⁾	$	410,513.13

Kevin M. Riley President		1,894	⁽³⁾	$	190,706.86		—		—
Kevin M. Riley President		2,833	⁽⁴⁾	$	285,254.77

Jeffrey M. Gutman⁽¹⁾ Former Executive Vice President, Chief Financial Officer and Treasurer		3,161.33	⁽⁵⁾	$	318,314.32		—		—

Corey Riley Executive Vice President Business Intelligence		1,250.00	⁽⁴⁾	$	125,862.50		—		—

Michael Palmer Executive Vice President Corporate Land		1,250.00	⁽⁴⁾	$	125,862.50		—		—

(1)	Mr. Gutman served as REP’s acting Chief Financial Officer since January 2018 and joined REP as Executive Vice President, Chief Financial Officer and Treasurer as of May 2018. Mr. Gutman resigned from his position with REP on October 5, 2020.
(2)	Market Value of Shares or Units of Stock That Have Not Vested based on the valuation of REP units on September 30, 2020 of $100.69.
(3)	These awards have vesting dates of February 1, 2021 and February 1, 2022.
(4)	These awards have vesting dates of February 1, 2021, February 1, 2022 and February 1, 2023.
(5)	This award has a vesting date of February 1, 2021.

Option Exercises and Stock Vested

The following table reflects information regarding stock awards held by certain of REP’s named executive officers that vested during the fiscal year ended September 30, 2020. There were no option awards held by any of REP’s named executive officers. The amounts shown in the following table for stock awards represent unit awards granted to certain of REP’s named executive officers pursuant to the 2018 LTIP. These unit awards represent equity-based interests in REP, which converted into shares of TGC’s common stock at or prior to the closing of the merger.

	Stock Awards
	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting⁽²⁾ ($)
Bobby D. Riley Chairman of the Board & CEO		14,093.33		1,419,057.40

Kevin M. Riley President and Interim Chief Financial Officer		7,559.41		761,156.99

Jeffrey M. Gutman⁽¹⁾ Former Executive Vice President, Chief Financial Officer and Treasurer		1,397.36		140,700.18

Corey Riley⁽⁵⁾ Executive Vice President Business Intelligence		—		—

Michael Palmer Executive Vice President Corporate Land		—		—

(1)	Mr. Gutman served as REP’s acting Chief Financial Officer since January 2018 and joined REP as Executive Vice President, Chief Financial Officer and Treasurer as of May 2018. Mr. Gutman resigned from his position with REP on October 5, 2020.
(2)	Value Realized on Shares or Units of Stock That Have Vested based on the valuation of REP units on September 30, 2020 of $100.69.

Compensation Plans Under Which Equity Securities are Authorized for Issuance as of September 30, 2020

The following table reflects information regarding compensation plans under which equity securities were authorized for issuance by REP as of September 30, 2020.

Plan Category	Number of Securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column a)
	(a)		(b)		(c)
Equity compensation plans approved by security holders		0		0		135,680
Equity compensation plans not approved by security holders		0		0		0
Total		0		0		135,680

Additional Narrative Disclosures

Elements of Compensation

Historically, REP has compensated its named executive officers with annual base salaries, annual cash incentive bonuses and employee benefits. Additionally, following the merger, REP’s named executive officers may be awarded long-term equity incentives in the form of restricted stock awards and stock options. Following the consummation of this merger, REP expects that these elements will continue to constitute the primary elements of its compensation program, although the relative proportions of each element, and the specific plan and award designs, will likely evolve. REP does not have any pension benefits or nonqualified deferred compensation, and no REP named executive officers received any golden parachute compensation pursuant to the merger.

Employment, Severance or Change in Control Agreements

On April 1, 2019, REP entered into employment agreements with Mr. Bobby D. Riley, Mr. Kevin M. Riley and Mr. Jeffrey M. Gutman. The employment agreements set forth the material terms of employment for each of REP’s named executive officers. The following description is intended as a summary of the employment agreements. The initial term of the employment agreements is three years, each with automatic annual renewals thereafter. Each of these employment agreements sets forth the initial terms and conditions of employment of each named executive officer, including base salary, target annual cash bonus opportunity, target annual equity award opportunity, standard employee benefit plan participation, severance and change in control benefits. Each employment agreement also includes certain restrictive covenants that generally prohibit REP’s named executive officers from (i) competing against REP, (ii) disclosing information that is confidential to REP and its subsidiaries and (iii) from soliciting or hiring REP’s employees and those of its subsidiaries or soliciting REP’s customers. The employment agreements may be assigned to an affiliate of REP and were assigned to RPOC in June 2019. Effective October 1, 2020, the employment agreement for Bobby Riley was amended to reduce his annual base salary for a period of three years, increase the target percentage for his annual equity award, increase his separation payment upon the occurrence of certain events and to grant him a special equity award.

In connection with Mr. Jeffrey M. Gutman’s resignation from his position with REP on October 5, 2020, he entered into a confidential separation and release of claims agreement. Pursuant to this agreement, Mr. Gutman received a cash bonus for the fiscal year ended on September 30, 2020 in an amount of $83,500. Further, the portion of his restricted units scheduled to vest on February 1, 2021 will continue to vest as scheduled, subject to compliance with the confidential separation and release of claims agreement. REP will pay him any retained distributions on the units that are scheduled to vest on February 1, 2021. The remaining portion of his restricted units scheduled to vest on February 1, 2022 and February 1, 2023 were forfeited as of the separation date. In consideration of the separation benefits, Mr. Jeffrey M. Gutman released REP and certain of its affiliates from claims and remains subject to confidentiality restrictions pursuant to the terms and conditions of the separation agreement.

Base Salary

Base salary is the fixed annual compensation REP pays to each of its named executive officers for carrying out their specific job responsibilities. Base salaries are a major component of the total annual cash compensation paid to REP’s named executive officers. Base salaries are determined after taking into account many factors, including (a) the responsibilities of the officer, the level of experience and expertise required for the position and the strategic impact of the position; (b) the need to recognize each officer’s unique value and demonstrated individual contribution, as well as future contributions; (c) the performance of REP and each officer; and (d) salaries paid for comparable positions in similarly-situated companies.

For the amounts of base salary that REP’s named executive officers received in fiscal 2018, 2019 and 2020, see “Executive Compensation of REP—Summary Compensation Table.”

REP’s board of managers reviews the base salaries for each named executive officer periodically as well as at the time of any promotion or significant change in job responsibilities and, in connection with each review, REP’s board of managers considers individual and company performance over the course of the relevant time period. REP’s board of managers has historically made adjustments to base salaries for named executive officers upon consideration of any factors that it deems relevant, including but not limited to: (a) any increase or decrease in the named executive officer’s responsibilities, (b) the named executive officer’s job performance, and (c) the level of compensation paid to senior executives of other companies with whom REP competes for executive talent, as estimated based on publicly available information and the experience of members of REP’s board of managers.

Annual Cash Bonuses

REP’s employment agreements provide that the annual cash bonuses will be based on criteria determined in the discretion of REP’s board of managers or a committee thereof, with a target bonus payment at planned or targeted levels of performance equal to up to 50% of each such named executive officer’s annual base salary. Following the close of a fiscal year, a final determination of annual bonus payments will be made by REP’s board of managers or a committee thereof after careful review of REP’s performance over the course of the preceding fiscal year. Annual cash bonuses for named executive officers who do not have employment agreements are made at the discretion of the REP board of managers.

For the fiscal year ended September 30, 2020, REP’s named executive officers received annual cash bonuses of an aggregate amount of $386,761, representing 50% of the targeted level.

Annual Equity Awards

REP’s employment agreements provide that the annual equity awards will be based on criteria determined in the discretion of REP’s board of managers or a committee thereof, with a target annual equity award at planned or targeted levels of performance equal to up to 100% of each name executive officer’s annual base salary. Following the close of a fiscal year, a final determination of annual equity awards will be made by REP’s board of managers or a committee thereof after careful review of REP’s performance over the course of the preceding fiscal year.

For the fiscal year ended September 30, 2020, each of REP’s named executive officers is eligible to receive a target annual equity-based award equal to up to 100% of annual base salary.

Other Benefits

REP offers participation in broad-based retirement, health and welfare plans to all of its employees.

Impact of Financial Reporting and Tax Accounting Rules

Unit-based compensation costs under REP’s Long Term Incentive Plan have been accounted for in accordance with ASC 718 which required REP to obtain an independent third-party valuation firm to value its common units.

Going forward, share-based compensation costs will be based on the closing price of TGC common stock as reported by the NYSE American, as of the grant date.

On and after the merger, Section 162(m) of the Code generally limits the deductibility of certain compensation expenses attributable to our named executive officer in excess of $1,000,000 to any one individual in any fiscal year.

Pension Benefits

REP has not maintained and do not currently maintain a defined benefit pension plan or a supplemental executive retirement plan. Instead, REP’s employees, including its named executive officers, may participate in a retirement plan intended to provide benefits under section 401(k) of the Code (the “401(k) Plan”) pursuant to which employees are allowed to contribute a portion of their base compensation to a tax-qualified retirement account. REP provides matching contributions equal to 100% of the first 5% of employees’ eligible compensation contributed to the 401(k) Plan.

Non-Qualified Defined Contribution and Other Non-Qualified Deferred Compensation Plans

REP has not had and does not currently have any defined contribution or other plan that provides for the deferral of compensation on a basis that is not tax-qualified.

2018 Long Term Incentive Plan

On December 31, 2018, REP adopted an equity incentive plan, the Riley Exploration – Permian, LLC 2018 Long Term Incentive Plan, or the 2018 LLC LTIP, for the employees, consultants and the directors of REP and its affiliates who perform services for REP. REP reserved 200,128 common units for issuance pursuant to REP’s 2018 LLC LTIP, which includes 64,448 units, inclusive of any surrendered or repurchased shares, that were issued prior to the merger. For the fiscal year ended September 30, 2018, certain of REP’s named executive officers were awarded an aggregate of 40,000 common units under the 2018 LLC LTIP as an incentive grant consisting of 27,460 common units that were issued after the surrender of 12,540 common units to satisfy an aggregate of $1.46 million of tax withholding obligations paid by REP to or on behalf of the executive officers. The common units that were issued for the incentive grant converted into shares of TGC’s common stock as part of the merger. On April 25, 2019, an aggregate of 14,766 restricted units were issued consisting of 12,054 restricted units issued to REP’s named executive officers for the annual equity awards and an additional 2,712 restricted units issued to Jeffrey M. Gutman as an initial grant. The restricted unit awards represent equity-based interests in REP, which converted into restricted shares of TGC common stock as part of the merger. On February 1, 2020, an aggregate of 14,517 restricted units were issued to REP’s named executive officers for the annual equity awards. The restricted unit awards represent equity-based interests in REP, which converted into restricted shares of TGC common stock as part of the merger. On October 1, 2020, an aggregate of 13,309 restricted units were issued to REP’s named executive officers for the annual equity awards. The restricted unit awards represent equity-based interests in REP, which converted into restricted shares of TGC common stock as part of the merger. In connection with completion of the merger, the 2018 LLC LTIP was terminated and replaced with the LTIP. See “2021 Long Term Incentive Plan” below.

2021 Long Term Incentive Plan

In connection with the merger, TGC adopted an omnibus equity incentive plan, the Riley Exploration Permian, Inc. 2021 Long Term Incentive Plan, (the “2021 equity incentive plan” or the “LTIP”), for the employees, consultants and the directors of the combined company and its affiliates who perform services for the combined company.

RELATED PARTY TRANSACTIONS OF DIRECTORS AND EXECUTIVE OFFICERS OF THE COMBINED COMPANY

In addition to the compensation and indemnification arrangements with directors and executive officers described elsewhere in this document and in our other filings with the SEC, including our Form 10-K, described below are any transactions occurring since January 1, 2020 and any currently proposed transactions in which:

•	the amounts involved exceeded or will exceed $120,000; and
•	any Related Person had, has or will have a direct or indirect material interest.

A “Related Person” means:

1)	any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;
2)	any person who is known by us to be the beneficial owner of more than 5% of our common stock;
3)	any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and
4)	any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

REP Transactions

Historical Transactions with Affiliates

Contribution Transactions—Our Company History

REP was formed on June 13, 2016 by REG, as its wholly-owned subsidiary, and REG, through another one of its wholly-owned subsidiaries operated the acreage comprising the Champions Assets. In a series of contribution transactions, REP acquired the Champions Assets, in exchange for REP’s common units, from the working interest owners of the Champions Assets, including REG. Upon issuance of REP’s common units in exchange for those assets, the working interest owners became members. REP’s wholly-owned subsidiary also acquired the operations of the Champions Assets. See “REP Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview” for more information.

In connection with the acquisition of the Champions Assets, REG entered into a joint operating agreement, for the operation of the Champions Assets, by a subsidiary of REG. Pursuant to the joint operating agreement, this subsidiary served as the operator of record of the Champions Assets until operatorship was transferred to REP’s wholly-owned subsidiary, RPOC, effective as of June 1, 2017. In connection with the transfer of operator of record to RPOC, the joint operating agreement relating to the operations of the Champions Assets was terminated effective June 1, 2017.

REP’s board of managers has been composed of representatives from REG, Yorktown, Boomer and Bluescape. See “REP Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview” for more information on the contribution.

Other Affiliate Matters

Mr. Bobby Riley is the chairman of REP’s board of directors and Chief Executive Officer. Mr. Riley also serves as a member of the board of directors of REP’s unitholder REG. Given Mr. Riley’s roles with both REP and REG, a conflict of interest could arise which could adversely affect the interests of REP’s unitholders, including conflicts involving payment or performance under prior agreements with REG or agreements REP may enter into in the future with REG or its subsidiaries or affiliates.

From October 10, 2016 through June 2017, REP reimbursed REG for certain personnel and general and administrative expenses at cost. The expenses included payroll, general and administrative, software licensing fees and accounting and bookkeeping services. In addition, REP reimbursed REG for an overhead allocated including office space and utilities. As of the year ended September 30, 2017, the aggregate amount of such actual costs reimbursed by REP to REG was approximately, $1.6 million. In June 2017, REP terminated the expense reimbursement arrangement with REG and have thereafter operated independently.

Combo Resources

In May 2019, Polaris E&P, LLC (“Polaris”), a wholly-owned subsidiary of REG, and Oakspring Energy Holdings, LLC, a portfolio company of Yorktown Partners (“Oakspring”), each contributed certain assets and liabilities, including without limitation, working capital, working interests in certain oil and natural gas properties and related assets in Bastrop, Fayette and Lee Counties, Texas (referred to as the Viking Project), working interests in certain oil and natural gas properties and related assets in Yoakum, Gaines and Andrews Counties, Texas and Lea County, New Mexico (referred to as the Kachina Project), and working interests in Winkler County (referred to as the Keystone Project), to newly-formed Combo Resources, LLC (“Combo”), in exchange for membership interests in Combo. The contribution transaction is effective as of April 1, 2019.

Simultaneously with the contribution transaction, Combo entered into a management services agreement with RPOC, whereby RPOC will provide certain administrative services to Combo in exchange for payment of a fee equal to $250,000 per month and reimbursement of all expenses. On April 16, 2020, RPOC and Combo amended the management services agreement to reduce the monthly fee payable thereunder to $150,000 for the period between June 1, 2020 through July 31, 2020 and further reduced to $100,000 for the remainder of the term.

Employee Holding Company

Effective June 10, 2019, REP formed a wholly-owned subsidiary, Riley Employee Member, LLC (“REM”), and contributed 0.1% of its membership interest in RPOC to REM. Simultaneously, REP assigned the employment agreements of its named executive officers to RPOC and entered into an administrative services agreement with RPOC whereby RPOC provides personnel to Riley Permian in exchange for payment of an amount equal to the direct payroll expense associated with the wages and compensation expenses incurred by RPOC to provide personnel to REP and fee equal to 1% of such expenses. The named executive officers remain the named executive officers of REP.

Registration Rights Agreement

REP has entered into a second amended and restated registration rights agreement (the “Registration Rights Agreement”) with REG, Yorktown, Boomer, Bluescape, Bobby Riley, Kevin Riley and Corey Riley. The Registration Rights Agreement provides for customary rights for these parties to demand that REP (or certain successors by merger, which would include the Company) file a resale shelf registration statement and certain piggyback rights with respect to registrable securities held by such parties (which registrable securities would include the TGC common stock received in the merger). Pursuant to the terms of the Registration Rights Agreement, 16,721,922 shares of TGC common stock are registrable under the Registration Rights Agreement following the closing of the merger. In addition, the agreement will grant these parties customary rights to participate in certain underwritten offerings of TGC common stock that TGC may conduct.

Subject to certain limitations described below, REP has agreed no later than 60 days following the merger to prepare and file a registration statement registering the offer and sale of their registrable securities. Subject to certain limitations in the Registration Rights Agreement, parties to the agreement holding more than 15% of the then-currently registrable securities under the agreement can require REP to participate in a firm underwritten resale of the securities; provided that the combined company will not be obligated to participate in more than two such underwritten resales per year.

Subject to certain exceptions, if at any time the combined company proposes to register an offering of equity securities or conduct an underwritten offering, whether or not for its own account, then the combined company must notify the equity holders party to the Registration Rights Agreement of such proposal to allow them to include a specified number of their registrable securities in that registration statement or underwritten offering, as applicable.

These registration rights will be subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and the combined company’s right to suspend use of a prospectus under a registration statement under certain circumstances, including if the combined company is pursuing a bona fide material acquisition, merger, reorganization, disposition or other similar transaction and the combined company’s board of managers determines in good faith that the combined company’s ability to pursue or consummate such a transaction would be materially and adversely affected by any required disclosure of such transaction in the registration statement (and such disclosure is then-required therein by applicable law, rule or regulation to permit offers and sales thereunder), the combined company has experienced some other material non-public event the disclosure of which in the registration statement at such time, in the good faith judgment of the combined company’s board, would materially and adversely affect the combined company (and such disclosure therein is then-required by applicable law, rule or regulation to permit offers and sales thereunder), or the combined company’s board shall have determined in good faith, upon the advice of counsel, that it is required by law, rule or regulation to file a post-effective amendment to such registration statement to reflect certain updated information of the type described in the Registration Rights Agreement. The Registration Rights Agreement provides certain time limitations on how long such delays may be implemented. The combined company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective.

Limitation of Liability and Indemnification Matters

REP’s fourth amended and restated limited liability company agreement limits the liability of its managers for monetary damages for breach of their fiduciary duty as managers, except for liability that cannot be eliminated under the DLLCA. Delaware law provides that managers of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

•	for any breach of their duty of loyalty to REP or its unitholders;
•	for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;
•	for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 607 of the DLLCA; or
•	for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

REP’s fourth amended and restated limited liability company agreement also provides that REP will indemnify its directors and officers to the fullest extent permitted by Delaware law. REP’s fourth amended and restated limited liability company agreement also permits REP to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as REP’s officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. REP intends to enter into indemnification agreements with each of its current and future directors and executive officers. These agreements will require REP to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to REP, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. REP believes that the limitation of liability provision that is in REP’s fourth amended and restated limited liability company agreement and the indemnification agreements will facilitate REP’s ability to continue to attract and retain qualified individuals to serve as directors and officers.

On October 7, 2020, REP’s fourth amended and restated limited liability company agreement was amended to provide for certain tax allocations amongst REXG and certain of REP’s management members.

Familial Relationship

There is a family relationship between Mr. Bobby Riley and REP’s President and Interim Chief Financial Officer, Mr. Kevin Riley, and REP’s Executive Vice President Business Intelligence, Mr. Corey Riley, as father and sons. Mr. Kevin Riley and Mr. Corey Riley are brothers.

Combined Company Related Party Transaction Policy

The combined company’s board of directors will adopt a written related party transactions policy following the closing of the merger. Pursuant to this policy, TGC expects that the audit committee will review all material facts of all Related Party Transactions.

PRINCIPAL STOCKHOLDERS OF THE COMBINED COMPANY

The following table sets forth certain information with respect to the beneficial ownership of the combined company’s common stock immediately after the closing of the merger, by:

•	each person, or group of affiliated persons, expected by TGC and REP to become the beneficial owner of more than 5% of the outstanding common stock of the combined company;
•	each named executive officer and director of the combined company; and
•	all of the combined company’s executive officers and directors as a group.

The percentage of ownership is based on 17,821,805 shares of common stock outstanding upon the closing of the merger, adjusted as required by the rules promulgated by the SEC to determine beneficial ownership. Except for the merger, neither TGC nor REP know of any arrangements, including any pledge by any person of securities of the combined company, the operation of which may at a subsequent date result in a change of control of the combined company.

Unless otherwise indicated, the address of all listed stockholders is c/o Riley Exploration Permian, Inc., 29 E. Reno Avenue, Suite 500, Oklahoma City, Oklahoma 73104.

Owners⁽¹⁾	Number of Shares Beneficially Owned		Percentage of Class
5% Stockholders
Riley Exploration Group, LLC⁽²⁾		4,677,410		26.245	%
Yorktown Energy Partners XI, LP⁽³⁾		1,784,113		10.011	%
Boomer Petroleum LLC⁽⁴⁾		3,537,404		19.849	%
Bluescape Riley Exploration Acquisition LLC⁽⁵⁾		3,834,639		21.517	%
Bluescape Riley Exploration Holdings LLC⁽⁵⁾		2,021,800		11.345	%

Directors, Director Nominees and Named Executive Officers:
Bobby Riley⁽⁶⁾		222,946		1.251	%
Kevin Riley⁽⁶⁾		124,013		*
Michael J. Rugen		6,794		*
Corey Riley⁽⁶⁾		35,804		*
Michael Palmer⁽⁶⁾		20,392		*
Directors, Director Nominees and Executive Officers as a group		409,949		2.3%

*	Less than one percent
(1)	The amounts and percentages of common units beneficially owned are reported on the bases of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners will have, to TGC’s and REP’s knowledge, sole voting and investment power with respect to the indicated number of TGC common stock, except to the extent this power may be shared with a spouse
(2)	Certain investment funds managed by Yorktown Partners own an aggregate of approximately 94% of REG. The address of REG is 2008 North Council Avenue, Blanchard, OK 73010.
(3)	Yorktown XI Company LP is the sole general partner of Yorktown Energy Partners XI, L.P. Yorktown XI Associates LLC is the sole general partner of Yorktown XI Company LP. The managers of Yorktown XI Associates LLC, who act by majority approval, are Bryan H. Lawrence, one of REP’s managers, W. Howard Keenan, Jr., Peter A. Leidel, Tomás R. LaCosta, Robert A. Signorino, Bryan R. Lawrence and James C. Crain. As a result, Yorktown XI Associates LLC may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the REPX common stock owned by Yorktown Energy Partners XI, L.P. Yorktown XI Company LP and Yorktown XI Associates LLC disclaim beneficial ownership of the REPX common stock held by Yorktown Energy Partners XI, L.P. in excess of their pecuniary interest therein. The managers of Yorktown XI Associates LLC disclaim beneficial ownership of the REPX common stock held by Yorktown Energy Partners XI, L.P. The address of such funds is 410 Park Avenue, 19th Floor, New York, New York 10022.
(4)	Boomer Petroleum, LLC is a Delaware limited liability company that is owned 50% by Texel Resources Inc., a Canadian corporation, and 50% by Balmon California, Inc., a California corporation. The President of Boomer Petroleum, LLC is Alvin Libin, was one of REP’s managers prior to the merger. The address of Boomer Petroleum, LLC is 3200 255 5th Avenue SW, Calgary, Alberta, Canada T2P 3G6.
(5)	Bluescape Riley Exploration Acquisition LLC is a Delaware limited liability company and beneficially own REPX common stock. Bluescape Riley Exploration Holdings LLC is a Delaware limited liability company and beneficially owns REPX common stock. Bluescape Riley Exploration Acquisition LLC is a wholly owned subsidiary of Bluescape Riley Exploration Holdings LLC. Bluescape Energy Recapitalization and Restructuring Fund III LP has voting and dispositive power over REPX common stock held by Bluescape Riley Exploration Acquisition LLC and Bluescape Riley Exploration Holdings LLC and therefore may also be deemed to be the beneficial owner of these shares. Bluescape Energy Partners III GP LLC may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares by virtue of Bluescape Energy Partners III GP LLC being the sole general partner of Bluescape Energy Recapitalization and Restructuring Fund III LP. Bluescape Resources GP Holdings LLC may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares by virtue of Bluescape Resources GP Holdings LLC being the manager of Bluescape Energy Partners III GP LLC. Charles John Wilder, Jr. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares by virtue of Charles John Wilder, Jr. being the manager of Bluescape Resources GP Holdings LLC. Each of Bluescape Riley Exploration Acquisition LLC, Bluescape Riley Exploration Holdings LLC, Bluescape Energy Recapitalization and Restructuring Fund III LP, Bluescape Energy Partners III GP LLC, Bluescape Resources GP Holdings LLC, and Charles John Wilder, Jr. disclaims beneficial ownership of the shares reported as held by Bluescape Riley Exploration Holdings LLC in excess of its respective pecuniary interest in such shares. Philip Riley, currently the Company’s Executive Vice President - Strategy and formerly a director of REP, LLC, was also an investment manager for Bluescape Riley Exploration Acquisition, LLC and Bluescape Riley Exploration Holdings LLC. The address of Bluescape Riley Exploration Acquisition LLC and Bluescape Riley Exploration Holdings LLC and mailing address of each listed beneficial owner is 200 Crescent Court, Suite 1900, Dallas, Texas 75201.
(6)	Includes shares of restricted common stock issued pursuant to the Riley Exploration Permian, Inc. 2021 Long Term Incentive Plan that are subject to vesting and certain other restrictions.

Dividends

Any determination to pay cash dividends will be at the discretion of the Company’s board of directors and will depend upon a number of factors, including the Company’s results of operations, financial condition, future prospects, contractual restrictions, restrictions imposed by applicable law and other factors the board of directors deems relevant.

Notwithstanding the foregoing, the Company expects to pay quarterly dividends on its common stock in amounts determined from time to time by its board of directors. The declaration and payment of any dividends by the Company will be at the sole discretion of its board of directors, which may change the Company’s dividend policy at any time. The board of directors will take into account:

•	general economic and business conditions;

•	the Company’s financial condition and operating results;

•	the Company’s free cash flow and current and anticipated cash needs;

•	the Company’s capital requirements;

•	legal, tax, regulatory and contractual (including under REP’s credit facility) restrictions and implications on the payment of dividends by the Company to its stockholders or by the Company’s subsidiaries to it; and

•	such other factors as the board of directors of the Company may deem relevant.

The Company does not have a legal obligation to pay dividends at any rate or at all, and there is no guarantee that it will declare or pay quarterly cash dividends to its common stockholders. If the Company does not have sufficient cash at the end of each quarter, it may, but is under no obligation to, borrow funds to pay the dividends established by its dividend policy to the common stockholders.

The operating and financial restrictions and covenants in REP’s credit facility restrict, and any future financing agreements likely will restrict, the Company’s ability to pay dividends, finance future operations or capital needs, or engage, expand or pursue its business activities. Specifically, the current REP credit facility restricts REP’s ability to make cash distributions (other than permitted tax distributions) to its members unless the net leverage ratio does not exceed 2.75 to 1.00, the total revolving credit exposures under REP’s credit facility are not greater than 80% of the total revolving commitments, and no default or event of default then exists or would exist upon the payment of the dividend. The Company’s ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond its control, such as a downturn in REP’s business or the economy in general or reduced oil, natural gas and NGL prices.

Furthermore, the amount of dividends the Company would be able to pay in any quarter may be limited by the DGCL, which provides that a Delaware corporation may pay dividends only (i) out of the corporation’s surplus, which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital, or (ii) if there is no surplus, out of the corporation’s net profit for the fiscal year in which the dividend is declared, or the preceding fiscal year.

Glossary of Oil and Gas Terms

The terms defined in this section are used with or without capitalization throughout this document:

“Bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

“Bbl/d” means Bbl per day.

“BOE” means barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

“BOE/d” means BOE per day.

“Btu” means one British thermal unit—a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

“Completion” means the installation of permanent equipment for the production of oil or natural gas.

“Developed acreage” means acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease.

“Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.

“Dry hole” means a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

“Exploratory well” means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil and gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those terms are defined in this section.

“Extension well” means a well drilled to extend the limits of a known reservoir.

“EUR” means estimated ultimate recovery based on an approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well.

“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks greatly by connecting pores together.

“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.

“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which the applicable company has a working interest.

“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases 1 permeability and porosity.

“Horizontal drilling” means a wellbore that is drilled laterally.

“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

“MBbl” One thousand barrels of oil, condensate or NGLs.

“MBoe” One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

“MBoe/d” means MBoe per day.

“Mcf” is an abbreviation for “1,000 cubic feet,” which is a unit of measurement of volume for natural gas.

“MMBbl” One million barrels of oil, condensate or NGLs.

“MMBO/Section” One million barrels of oil per Section.

“MMBtu” One million Btus.

“MMcf” is an abbreviation for “1,000,000 cubic feet,” which is a unit of measurement of volume for natural gas.

“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

“Net revenue interest” means all of the working interests less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.

“NGL” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“Overriding royalty” means an interest in the gross revenues or production over and above the landowner’s royalty carved out of the working interest and also unencumbered with any expenses of operation, development or maintenance.

“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

“P50” defined as 50% of estimates exceed the P50 estimate (and by definition, 50% of estimates are less than the P50 estimate).

“Play” or “play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight sand, shale and coal reservoirs.

“Possible Reserves” means reserves that are less certain to be recovered than probable reserves.

“Prospect” means a geological area which is believed to have the potential for oil and natural gas production.

“Productive well” means a well that is producing oil or gas or that is capable of production.

“Probable Reserves” means reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.

“PDNP” means proved developed non-producing wells.

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves” means the estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves” means 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.

“PV-10 value” means the present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the applicable company on a comparative basis to other companies and from period to period.

“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.

“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.

“SEC pricing” means the price per Bbl for oil or per MMBtu for natural gas as calculated from the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months, as adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

“Section” means 640 acres.

“Seismic Data” means an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.

“Service well” means a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Stratigraphic test well” means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

“Undeveloped leasehold acreage” means the leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains estimated net proved reserves.

“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.

“WTI” means the price of West Texas Intermediate oil on the NYMEX.

Riley Exploration Permian, Inc. - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - April 7, 2021

Attached files

Riley Exploration Permian, Inc. Reports