SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
For the fiscal year ended June 30 2019
For the transition period from to
Commission File Number 001-32942
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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Nevada | 41-1781991 | |
(State or other jurisdiction of incorporation or organization) | | (IRS Employer Identification No.) |
1155 Dairy Ashford Road, Suite 425, Houston, Texas77079
(Address of principal executive offices and zip code)
(713) 935-0122
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class | Trading Symbol(s) | Name of Each Exchange On Which Registered | ||
Common Stock, $0.001 par value | | EPM | | NYSE American |
Securities registered pursuant to Section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes:
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes:
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes:
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes:
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definition of "large accelerated filer", "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer | ☐ | Accelerated filer | ☐ | Non-accelerated filer | ☒ | Smaller reporting company | ☒ |
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| | | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes:
The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2018,2021, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $6.75$5.05 on the NYSE American was $158,319,105.
The number of shares outstanding of the registrant'sregistrant’s common stock, par value $0.001, as of September 6, 2019,9, 2022, was 33,064,797.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant's 2019registrant’s 2022 Annual Meeting of Stockholders to be filed within 120 days of the end of the fiscal year covered by this report are incorporated by reference into Part III of this report.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
2022 ANNUAL REPORT ON FORM 10-K
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We use the terms, "EPM," "Company," "we," "us"“EPM,” “Company,” “we,” “us,” and "our"“our” to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.
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This Form 10-K and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, except for statements of historical fact, that relate to the anticipated future activities, plans, strategies, objectives or expectations of the Company are forward-looking statements. The words “plan,” “expect,” “project,” “estimate,” “may,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements.statements, although not all forward-looking statements contain such identifying words or phrases. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. Forward-looking statements include statements regarding: expectations of plans, strategies and objectives of the Company, including anticipated development activity and capital spending; the Company’s capital allocation strategy, capital structure, anticipated sources of funding, growth in long-term shareholder value and ability to preserve balance sheet strength; the benefits of the Company’s multi-basin portfolio, including operational and commodity flexibility; the Company’s ability to maximize cash flow and the application of excess cash flows to reduce long-term debt and to pay dividends and repurchase shares pursuant to its Share Repurchase Program; oil, natural gas and NGLs production and commodity mix, GHG emissions and ESG performance; anticipated oil, natural gas and NGL prices; anticipated drilling and completions activity; estimates of the Company’s oil, NGLs and natural gas reserves and recoverable quantities; future interest expense; the Company’s ability to access credit facilities and other sources of liquidity to meet financial obligations throughout commodity price cycles; the Company’s ability to manage debt and financial ratios, finance growth and comply with financial covenants; the implementation and outcomes of risk management programs, including exposure to commodity price and interest rate fluctuations, the volume of oil, NGLs and natural gas production hedged, and the markets or physical sales locations hedged; the impact of changes in federal, state, provincial and local, rules and regulations; anticipated compliance with current or proposed environmental legislation, including the costs thereof; adequacy of provisions for abandonment and site reclamation costs; the Company’s operational and financial flexibility, discipline and ability to respond to evolving market conditions; the declaration and payment of future dividends and any anticipated repurchase the Company’s outstanding common shares; the adequacy of the Company’s provision for taxes and legal claims; the Company’s ability to manage cost inflation and expected cost structures, including expected operating, transportation, processing and labor expenses; the competitiveness of the Company against its peers, including with respect to capital, materials, people, assets and production; oil, NGL and natural gas inventories and global demand for oil, NGL and natural gas; the outlook of the oil and natural gas industry generally, including impacts from changes to the geopolitical environment; anticipated staffing levels; anticipated payments related to the Company’s commitments, obligations and contingencies, and the ability to satisfy the same; and the possible impact of accounting and tax pronouncements, rule changes and standards.
Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions and are subject to both known and unknown risks and uncertainties (many of which are beyond our control) that may cause such statements not to occur, or actual results to differ materially and/or adversely from those expressed or implied. These assumptions include: future commodity prices and basis differentials; the ability of the Company to access credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance; the availability of attractive commodity or financial hedges and the enforceability of risk management programs; expectations that counterparties will fulfill their obligations pursuant to gathering, processing, transportation and marketing agreements; access to adequate gathering, transportation, processing and storage facilities; assumed tax, royalty and regulatory regimes; expectations and projections made in light of, and generally consistent with, the Company’s historical experience and its perception of historical industry trends; and the other assumptions contained herein.
Readers are cautioned that the assumptions, risks and uncertainties referenced above, and in the other documents incorporated herein by reference (if any), are not exhaustive. Although the Company believes the expectations represented by its forward-looking statements are reasonable based on the information available to it as of the date such statements are made, forward-looking statements are only predictions and statements of our current beliefs and there can be no assurance that such expectations will prove to be correct.
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When considering any forward-looking statement, youthe reader should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in Part I, Item 1A, "Risk Factors"1A. Risk Factors and elsewhere in this report and as also may be described from time to time in our future reports we file with the Securities and Exchange Commission. YouReaders should readalso consider such information in conjunction with our consolidated condensed financial statements and related notes and "Management'sItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operations in this report. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.
Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. YouReaders are advised, however, to review any further disclosures we make on related subjects in our periodic filings with the Securities and Exchange Commission.
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GLOSSARY OF SELECTED PETROLEUM INDUSTRY TERMS
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Term | Definition | ||
Bbl | | One stock tank barrel, of 42 U.S. gallons of liquid volume, used herein in reference to oil or NGL. | |
BCF | | Billion cubic feet. | |
BFPD | | Barrels of fluid per day. | |
BOE | | Barrels of oil equivalent. BOE is calculated by converting six MCF of natural gas and 42 gallons of NGL to one Bbl of oil which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil. | |
BOEPD | | Barrels of oil equivalent per day. | |
BOPD | | Barrels of oil per day. | |
BTU | | British Thermal Unit: the standard unit of measure of energy equal to the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit. One Bbl of oil is typically 5.8 MMBTU, and one standard MCF is typically one MMBTU. | |
CO2 | | Carbon Dioxide; CO2 is a gas that can be found in naturally occurring reservoirs, is typically associated with ancient volcanoes, is a major byproduct from manufacturing and power production, and is also utilized in enhanced oil recovery through injection into an oil reservoir. | |
Developed Reserves | | Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by a means not involving a well. | |
EOR | | Enhanced Oil Recovery; projects that involve injection of heat, miscible or immiscible gas, or chemicals into oil reservoirs, typically following full primary and secondary waterflood recovery efforts, in order to gain incremental recovery of oil from the reservoir. | |
Field | | An area consisting of a single reservoir or multiple reservoirs all grouped within or related to the same geologic structural features and/or stratigraphic features.* | |
Farmout | | Sale or transfer of all or part of the operating rights from the working interest owner (the assignor or farmout party), to an assignee (the farm-in party) who assumes all or some of the burden of development, in return for an interest in the property. The assignor may retain an overriding royalty or any other type of interest. For Federal tax purposes, a farmout may be structured as a sale or lease, depending on the specific rights and carved out interests retained by the assignor. | |
Gross Acres or Gross Wells | | The total acres or number of wells participated in, regardless of the amount of working interest owned. | |
Horizontal Drilling | | Involves drilling horizontally out from a vertical well-bore, thereby potentially increasing the area and reach of the well-bore that is in contact with the reservoir. | |
Hydraulic Fracturing | | Involves pumping a fluid with or without particulates into a formation at high pressure, thereby creating fractures in the rock and leaving the particulates in the fractures to ensure that the fractures remain open which potentially increases the ability of the reservoir to produce oil or natural gas. | |
LOE | | Lease Operating Expense(s); a current period expense incurred to operate a well. | |
MBBL | | One thousand barrels. | |
MMBBBL | | One million barrels. | |
MBOE | | One thousand barrels of oil equivalent. | |
MMBOE | | One million barrels of oil equivalent. | |
MMBOEPD | | One million barrels of oil equivalent per day. | |
MCF | | One thousand cubic feet of natural gas at standard conditions, being approximately sea level pressure and 60 degrees Fahrenheit temperature. | |
MMCF | | One million cubic feet of natural gas at standard conditions, being approximately sea level pressure and 60 degrees Fahrenheit temperature. | |
MMBTU | | One million British Thermal Units. | |
Mineral Royalty Interest | | A royalty interest that is retained by the owner of the minerals underlying a lease. See “Royalty Interest.” | |
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Net Acres or Net Wells | | The sum of the fractional working interests owned in gross acres or gross wells. | |
NGL | | Natural Gas Liquids; the combination of ethane, propane, butane and natural gasoline that can be removed from natural gas through processing, typically through refrigeration plants that utilize low temperatures, or through plants that utilize compression, temperature reduction and expansion to a lower pressure. | |
Non-operated Interest | | An interest in an oil and/or natural gas property but does not participate in or have any responsibility for actual operation of the property. | |
Non-operated Working Interest | | An interest in an oil and/or natural gas property but does not participate in or have any responsibility for actual operation of the property, but is burdened with the cost of development and operation of the property. | |
NYMEX | | New York Mercantile Exchange. | |
OOIP | | Original Oil in Place; an estimate of the barrels originally contained in a reservoir before any production therefrom. | |
Operator | | An oil and natural gas joint venture participant that manages the joint venture, pays venture costs and bills the venture’s non-operators for their share of venture costs. The operator is also responsible to market all oil and natural gas production, except for those non-operators who take their production in-kind. | |
Overriding Royalty Interest or ORRI | | A royalty interest that is created out of the operating or working interest. Unlike a royalty interest, an overriding royalty interest terminates with the operating interest from which it was created or carved out of. See “Royalty Interest.” | |
Permeability | | The measure of ease with which a fluid can move through a reservoir. The unit of measure is a darcy (d), or any metric derivation thereof, such as a millidarcy (md), where one darcy equals 1,000 millidarcy. Extremely low permeability of 10 millidarcy, or less, are often associated with source rocks, such as shale. Extraction of hydrocarbons from a source rock is more difficult than a sandstone reservoir where permeability typically ranges one to two darcy or more. | |
Porosity | | The relative volume of the pore space (or open area) compared to the total bulk volume of the reservoir, stated in percent. Higher porosity rocks provide more storage space for hydrocarbon accumulations than lower porosity rocks in a given cubic volume of reservoir. | |
Primary Recovery Method | | The extraction of oil and natural gas from reservoirs using natural or initial reservoir pressure combined with artificial lift techniques such as pumps. | |
Producing Reserves | | Any category of reserves that have been developed and production has been initiated.* | |
Producing Well | | Any well that has been developed and production has been initiated.* | |
Proved Developed Reserves | | Proved Reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by a means not involving a well. | |
Proved Developed Nonproducing Reserves | | Proved Reserves that have been developed and no material amount of capital expenditures are required to bring on production, but production has not yet been initiated due to timing, markets, or lack of third party completed connection to a natural gas sales pipeline.* | |
Proved Developed Producing Reserves (“PDP”) | | Proved Reserves that have been developed and production has been initiated.* | |
Proved Reserves | | Estimated quantities of oil, natural gas, and NGLs which geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.* | |
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Proved Undeveloped Reserves (“PUD”) | | Proved 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.* (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty. | |
Present Value | | When used with respect to oil and natural gas reserves, present value means the estimated future net revenues computed by applying current prices of oil and natural gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and natural gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs to be incurred in developing and producing the proved reserves) computed using a discount factor and assuming continuation of existing economic conditions. | |
Productive Well | | A well that is producing oil or natural gas or that is capable of production. | |
PV-10 | | Means the present value, discounted at 10% per annum, of future net revenues (estimated future gross revenues less estimated future costs of production, development, and asset retirement costs) associated with reserves and is not necessarily the same as market value. PV-10 does not include estimated future income taxes. Unless otherwise noted, PV-10 is calculated using the pricing scheme as required by the Securities and Exchange Commission (“SEC”). PV-10 of proved reserves is calculated the same as the standardized measure of discounted future net cash flows, except that the standardized measure of discounted future net cash flows includes future estimated income taxes discounted at 10% per annum. See the definition of standardized measure of discounted future net cash flows. | |
Reservoir | | A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. | |
Royalty or Royalty Interest | | The mineral owner’s share of oil or natural gas production (typically between 1/8 and ¼), free of costs, but subject to severance taxes unless the lessor is a government. In certain circumstances, the royalty owner bears a proportionate share of the costs of making the natural gas saleable, such as processing, compression, and gathering. | |
Secondary Recovery Method | | The extraction of oil and natural gas from reservoirs utilizing water injection (waterflooding) in order to maintain or increase reservoir pressure and direct the displacement of oil into producing wells. | |
Shut-in Well | | A well that is not on production, but has not been plugged and abandoned. Wells may be shut-in in anticipation of future utility as a producing well, plugging and abandonment or other use. | |
Standardized Measure | | The standardized measure of discounted future net cash flows. The Standardized Measure is an estimate of future net cash flows associated with proved reserves, discounted at 10% per annum. Future net cash flows are calculated by reducing future net revenues by estimated future income tax expenses and discounting at 10% per annum. The Standardized Measure and the PV-10 of proved reserves are calculated in the same exact fashion, except that the Standardized Measure includes future estimated income taxes discounted at 10% per annum. The Standardized Measure is in accordance with accounting standards generally accepted in the United States of America (“GAAP”). | |
Tertiary Recovery Method | | The extraction of oil and natural gas from reservoirs which employs injection of gas, heat, or chemicals into the reservoir in order to change the physical properties of the oil and aid in its extraction, also known as Enhanced Oil Recovery (EOR). | |
Undeveloped Reserves | | Reserves of any category 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.* | |
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Water Injection Well | | A well which is used to inject water under high pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves. | |
Working Interest | | The interest in the oil and natural gas in place which is burdened with the cost of development and operation of the property. Also called the operating interest. | |
Workover | | A remedial operation on a completed well to restore, maintain, or improve the well’s production. | |
* | This definition may be an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X. |
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PART I
Item 1. Business
Note:
See Glossary of Selected Petroleum Industry Terms starting on pageGeneral
Evolution Petroleum Corporation is an oil and gasindependent energy company focused on delivering a sustainable dividend yieldmaximizing total returns to its shareholders through the ownership managementof and development of producinginvestment in onshore oil and natural gas properties. The Company'sproperties in the United States. Our long-term goal is to buildmaximize total shareholder return from a diversified portfolio of long-life oil and natural gas assets primarilyproperties built through acquisition while seeking opportunities to maintain and increase production through selective development, production enhancement, and other exploitation efforts on itsour oil and natural gas properties.
Recent Developments
Dividend Declaration and Share Repurchase Program
On September 12, 2022, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2022. This represents a 20% increase over the last three$0.10 per common share dividend paid in the fourth quarter of fiscal years consistedyear 2022. Also, on September 8, 2022, our Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of our common shares, the market price of our common stock, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice.
Jonah Field Acquisition
On April 1, 2022, we acquired non-operated working interests in the
Jonah Field in Sublette County, Wyoming (the “Jonah Field Acquisition”). After taking into account the deposit on the acquisition, customary closing adjustments and an effective date of February 1, 2022, cash consideration was $26.4 million. The acquired properties include an average net working interest of approximately 20% and an average net revenue interest of approximately 15% in 595 producing wells and approximately 950 net acres. The properties are operated by Jonah Energy (“Jonah”), an established operator in the geographic region.Williston Basin Acquisition
On January 14, 2022, we acquired non-operated working interests in 73 producing wells in the Williston Basin with an average net working interest of approximately 39% and average net revenue interest of approximately 33% located on approximately 45,000 net acres (approximately 90% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota (the “Williston Basin Acquisition”). After taking into account customary closing adjustments and an effective date of June 1, 2021, cash consideration was $25.2 million which includes cash expenses related to the acquisition. The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region.
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Business Strategy
Our business strategy is to maximize total shareholder return based on our assessment of the operating environment and marketplace, subject to our obligations to other stakeholders. The key elements of our strategy to accomplish our goal of maximizing shareholder return are:
| ● | Maintaining a strong balance sheet and conservative financial management; |
| ● | Growing the asset base through investment in our existing properties, direct acquisitions of new low decline oil and natural gas properties, or accretive acquisitions of similar companies; and |
| ● | Returning cash to shareholders by sustaining and growing our dividend payout over time or repurchases of our shares in the open market. |
Properties
Our oil and natural gas properties consist of non-operated interests in the Delhi Holt-Bryant Unit in the Delhi field (the "Unit")Field in Northeast Louisiana, a CO2 enhanced oil recovery project,Louisiana; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Barnett Shale located in North Texas; the Williston Basin in North Dakota; the Jonah Field in Sublette County, Wyoming; and a de minimis overriding royalty interest retained in a past divestiture. We have a combined net revenue interest in the Unit of 26.2% comprised of 7.2% ofsmall overriding royalty interests that are in effect forfour onshore central Texas wells.
Delhi Field – Enhanced Oil Recovery CO2 Flood – Onshore Louisiana
Our interests in the lifeDelhi Field, a CO2-EOR project, consist of the Unit and mineral royalty interests and a 23.9%approximately 24% average net working interest, with an associated 19.0%19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest.
For the year ended June 30, 2019 were 9.0 MMBOE, a 4% decrease2022, our average net daily production from the previous year. The Standardized Measure for proved reserves increased 7% to $127 million, reflecting a rise in realized commodity price from $54.71 to $58.50 per BOE. Our proved reserves consist of 85% crude oil and 15% natural gas liquids.
| Reserves as of June 30, 2019 | |||||||||
| Proved | Probable** | Possible** | |||||||
| Reserves MBOE | 8,981 | 4,783 | 4,321 | ||||||
| % Developed | 82 | % | 87 | % | 91 | % | |||
| Liquids % | 100 | % | 100 | % | 100 | % | |||
| Standardized Measure ($MM) | $ | 127 | |||||||
| PV-10* ($MM) | $ | 157 | |||||||
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field are the Tuscaloosa and Paluxy formations. Produced oil from the field is priced off of Louisiana
Hamilton Dome –Hot Springs County, Wyoming
Our working and royalty interests in the Delhi field are currently our primary producing assets. The Unit is approximately 13,636 acres in size and has hadHamilton Dome Field, a prolific production history totaling approximately 195 million bbls of oil through primary and limited secondary recovery operations since its discovery infield utilizing water injection wells to pressurize the mid-1940s. Atreservoir, consists of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), a private oil and natural gas company, who owns the time of our purchasevast majority of the field in 2003, the Unit had minimal production. We conveyed ourremaining working interest in the field to a subsidiary of Denbury Resources, Inc. in May 2006 for $50 million for the purpose of installing an enhanced oil recovery ("EOR") projectHamilton Dome Field. The Hamilton Dome Field is located in the field. We retained a 23.9% reversionary working interest upon payoutsouthwest region of the project, as definedBig Horn Basin in northwest Wyoming.
For the purchase and sale agreements. Since EOR production began in March 2010, the Unit has produced over 20 million bbls of oil.
Barnett Shale - North Texas
On May 7, 2021, we acquired non-operated working interests in the previously redeveloped western sideBarnett Shale (the “Barnett Shale Acquisition”), a natural gas producing shale reservoir consisting of approximately 21,000 net acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant), in the field basedBarnett Shale. The acreage consists of an average net working interest of approximately 17% and associated average net revenue interest of approximately 14% (inclusive of small overriding royalty interests). The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by seven other operators.
For the year ended June 30, 2022, our average net daily production from the Barnett Shale properties was 3.5 MBOEPD consisting of 79% natural gas, 20% NGLs, and 1% oil. The producing reservoir is the Barnett Shale, which is also the source rock. Hydrocarbons produced from our Barnett Shale properties are sold to Gulf Coast markets.
Williston Basin – Williston, North Dakota
On January 14, 2022, we acquired non-operated working interests in 73 producing wells in the Williston Basin with an average net working interest of approximately 39% and average net revenue interest of approximately 33% located on approximately 45,000 net acres (approximately 90% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation, an established operator in the geographic region.
Average net daily production results and new geological mapping that includedfrom the resultsdate of seismic data acquired overacquisition through June 30, 2022 was 0.5 MBOEPD. For the last few years. Gross fieldyear ended June 30, 2022, our average net daily production increased to more than 7,500 gross barrels of oil per day.
Jonah Field – Sublette County, Wyoming
On April 1, 2022, we acquired non-operated working interests in the southwest part of the field, the operator suspended CO
Average net daily production from the date of the field that were not being swept effectively by the CO
Refer to “Production volumes, average sales price and average production costs” table below for further information regarding our properties and their fiscal year results.
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Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues
The SECSecurities and Exchange Commission (“SEC”) sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and natural gas proved reserves by significant geographic area, using the trailing 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.
There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.
Summary of Oil & Gas Reserves for Fiscal Year Ended
Our proved probable and possible reserves atas of June 30, 2019,2022, denominated in equivalentthousands of barrels using six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio,equivalent (MBOE), were estimated by our independent petroleum engineer,reservoir engineers, DeGolyer and MacNaughton ("(“D&M"&M”) and Netherland, Sewell & Associates, Inc. (“NSAI”), both worldwide petroleum consultants.
D&M evaluated the reserves for our Barnett Shale, Hamilton Dome, and Delhi Field properties. D&M, which was formed in 1936, employs over 180 petroleum engineers, geologists and other technical personnel, and operates domestically and around the world. D&M was selected to estimate reserves for our interestshas completed more than 23,000 projects in the Delhi field due to their expertise in CO
NSAI evaluated the reserves for our Williston Basin and Jonah Field properties. NSAI, which was founded in 1961, began evaluating these properties when we acquired each of them during the fiscal year ended June 30, 2022. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.2 to this Annual Report on Form 10-K.
The following table sets forth our estimated proved probable and possible reserves as of June 30, 2019.2022. For additional reserve information, see
4
Reserves as of June 30, 2019
| Reserve Category | Oil (MBbls) | NGLs (MBbls) | Total Reserves (MBOE)* | |||||
| PROVED | ||||||||
| Developed Producing (82% of Proved) | 6,274 | 1,124 | 7,398 | |||||
| Undeveloped (18% of Proved) | 1,342 | 241 | 1,583 | |||||
| TOTAL PROVED | 7,616 | 1,365 | 8,981 | |||||
| Product Mix | 85 | % | 15 | % | 100 | % | ||
| PROBABLE | ||||||||
| Developed Producing (87% of Probable) | 3,516 | 630 | 4,146 | |||||
| Undeveloped (13% of Probable) | 540 | 97 | 637 | |||||
| TOTAL PROBABLE | 4,056 | 727 | 4,783 | |||||
| Product Mix | 85 | % | 15 | % | 100 | % | ||
| POSSIBLE | ||||||||
| Developed Producing (91% of Possible) | 3,323 | 596 | 3,919 | |||||
| Undeveloped (9% of Possible) | 341 | 61 | 402 | |||||
| TOTAL POSSIBLE | 3,664 | 657 | 4,321 | |||||
| Product Mix | 85 | % | 15 | % | 100 | % | ||
| | | | | | | | | | | |
| | Oil | | Natural Gas | | NGLs | | Total Reserves | | Percent of | |
Reserve Category |
| (MBbls) |
| (MMcf) |
| (MBbls) |
| (MBOE)(1) |
| Total Proved | |
Proved: | | | | | | | | | | | |
Developed Producing | | 8,705 | | 104,723 | | 6,299 | | 32,458 | | 89.6 | % |
Developed Non-Producing | | 157 | | 71 | | 19 | | 188 | | 0.5 | % |
Undeveloped | | 2,608 | | 2,197 | | 623 | | 3,597 | | 9.9 | % |
Total Proved | | 11,470 | | 106,991 | | 6,941 | | 36,243 | | 100.0 | % |
Product Mix | | 32% | | 49% | | 19% | | 100% | | | |
| | | | | | | | | | | |
Total Proved by Property: | | | | | | | | | | | |
Delhi Field | | 4,159 | | — | | 1,797 | | 5,956 | | 16.4 | % |
Hamilton Dome Field | | 2,374 | | — | | — | | 2,374 | | 6.6 | % |
Barnett Shale | | 96 | | 65,619 | | 3,649 | | 14,682 | | 40.5 | % |
Williston Basin | | 4,472 | | 3,709 | | 1,012 | | 6,102 | | 16.8 | % |
Jonah Field | | 369 | | 37,663 | | 483 | | 7,129 | | 19.7 | % |
Total Proved | | 11,470 | | 106,991 | | 6,941 | | 36,243 | | 100.0 | % |
| (1) | ||
42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil. | ||
| As of June 30, | |||||||
| 2019 | 2018 | ||||||
| Estimated future net revenues | $ | 297,102,269 | $ | 270,842,377 | |||
| 10% annual discount for estimated timing of future cash flows | 140,489,586 | 124,798,505 | |||||
| Estimated future net revenues discounted at 10% (PV-10) | 156,612,683 | 146,043,872 | |||||
| Estimated future income tax expenses discounted at 10% | (29,880,641 | ) | (27,085,458 | ) | |||
| Standardized Measure | $ | 126,732,042 | $ | 118,958,414 | |||
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company'sCompany’s Overall Reserve Estimation Process
Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our Chairmaninternal reserve engineering team, which includes third-party consultants. Our internal reserve engineering team and third-party consultants have a combined experience of over 80 years in Petroleum Engineering. The person responsible for overseeing the Board and interim Chief Executive Officer and Senior Vice Presidentpreparation of Engineering and Business Development, a professional petroleum engineer. Suchour reserves estimates are to behas a Bachelor of Science Degree in compliancePetroleum Engineering from Texas A&M University, is a registered Professional Engineer in the State of Texas, has over 40 years of oil and natural gas experience including large independents and financial firm services for projects and acquisitions. Our Board of Directors also has oversight of our reserve estimation process and contains an independent director who is a Registered Professional Engineer with experience in energy company reserve evaluations. Such reserve estimates comply with generally accepted petroleum engineering and evaluation principles, and definitions, and guidelines as established by the SEC.
The reserves information in this filing is based on estimates prepared by DeGolyerD&M and MacNaughton, our independent petroleum engineering firm, which was formed in 1936, employs over 180 petroleum engineers, geologists and other technical personnel, and operates domestically and around the world.NSAI. The person responsible for preparing the reservespreparation of the reserve report withat D&M is Dilhan Ilk, Senior Vice President and Division Manager of North America. Dr. Ilk received a RegisteredBachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 10 years of experience in oil and natural gas reservoir studies and evaluations. The person responsible for the preparation of the reserve report at NSAI is Steven W. Jansen, P.E., Vice President. Mr. Jansen, a Licensed Professional Engineer in the State of Texas (No. 112973), has been practicing consulting petroleum engineering at NSAI since 2011 and a Senior Vice Presidenthas over four years of the firm.prior industry experience. He receivedgraduated from Kansas State University in 2007 with a Bachelor of Science degreeDegree in petroleum engineering from the University of Texas in 1984, has over 35 years of experience in the energy industry and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
We provide our independent petroleum engineering firmD&M and NSAI with our property interests, production, current operating costs, current production prices, estimated abandonment costs and other information.information in order for them to prepare the reserve estimates. This information is reviewed by our Senior Vice President of Engineeringsenior management team, designated operations personnel, and Business Development and other members of managementthird-party consultants to ensure accuracy and completeness of the data prior to submission to this firm.the reserve engineers. The scope and results of our independent petroleum engineering firm'sD&M’s and NSAI’s procedures, as well as their professional qualifications, are summarized in the letterletters included as exhibitExhibit 99.1 and Exhibit 99.2, respectively, to this Annual Report on Form 10-K.
5
Proved Undeveloped Reserves
During the year ended June 30, 2022 our proved undeveloped (“PUD”) reserves changed as follows:
| | | | | | | | |
| | Oil | | Natural Gas | | NGLs | | Total Reserves |
Proved undeveloped reserves: |
| (MBbls) |
| (MMcf) |
| (MBbls) |
| (MBOE)(1) |
June 30, 2021 | | 1,605 | | — | | 208 | | 1,813 |
Revisions of previous estimates | | (1,605) | | — | | (208) | | (1,813) |
Improved recovery, extensions and discoveries | | 2,608 | | 2,197 | | 623 | | 3,597 |
June 30, 2022 | | 2,608 | | 2,197 | | 623 | | 3,597 |
| (1) | Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil. |
Our Proved undevelopedPUD reserves were 1,583 MBOE at3.6 MMBOE as of June 30, 2019,2022, with associatedrelated future development costs of approximately $8.6$61.7 million, which are associated with the PhaseWilliston Basin properties. At June 30, 2021, our PUD reserves were 1.8 MMBOE, which were associated with Test Site V developmentat our Delhi Field. PUD reserves associated with Test Site V were removed in the eastern portion of Delhi field.
Oil (MBbls) | NGLs (MBbls) | Total Reserves (MBOE) | |||||||||
| June 30, 2018 | 1,798 | 284 | 2,082 | ||||||||
| Revisions to previous estimates | 7 | 30 | 37 | ||||||||
| Conversion to proved developed reserves | (463 | ) | (73 | ) | (536 | ) | |||||
| June 30, 2019 | 1,342 | 241 | 1,583 | ||||||||
Drilling and Present Activities
Currently, none of our oil and natural gas properties are operated by us. We therefore rely on information from our operators regarding near-term drilling programs. As certain of our properties are considered fully developed, there are no plans to drill wells in fiscal year 2023 in the Hamilton Dome Field, the Delhi Field and the Jonah Field. At this time, operators of our Delhi Field, Hamilton Dome Field, Barnett Shale, Williston Basin, and Jonah Field properties are running workover rigs focusing on projects to return previously shut-in wells to production.
During fiscal year 2022, we participated in the drilling of two gross wells in Barnett Shale which were brought online during the fourth quarter of the CO
In the latter half of fiscal year 2022, our management team and third-party consulting engineers performed a technical review of drilling locations on our Williston Basin properties. Currently, there are 20 PUD drilling locations in the Pronghorn and Three Forks formations attributed to these properties. Pursuant to agreements we have with the operator, Foundation, we can propose drilling wells, in which the operator may participate. In the event the operator does not participate in our proposed drilling well, we have the right to undertake all necessary activities to drill, complete and install related facilities for the well. Ongoing operations of any well we elect to drill will be turned over to the remaining undeveloped eastern portionoperator of the field commenced subsequentproperty upon completion.
Our operator, Foundation, has also identified four PUD sidetrack locations in the Williston Basin targeting the Birdbear formation. Our management team and third-party consulting engineers have reviewed Foundation’s plans and technical justification and plan to reversionparticipate in the drilling of our working interest in late
| Year Ended June 30, 2019 | Year Ended June 30, 2018 | Year Ended June 30, 2017 | |||||||||||||||||||||
| Product | Volume | Price | Volume | Price | Volume | Price | |||||||||||||||||
| Crude oil (Bbls) | 626,879 | $ | 65.05 | 651,931 | $ | 58.52 | 724,523 | $ | 46.31 | ||||||||||||||
| Natural gas liquids (Bbls) | 112,013 | $ | 21.87 | 93,366 | $ | 28.06 | 43,907 | $ | 16.01 | ||||||||||||||
| Natural gas (Mcf) | 459 | $ | 2.64 | — | $ | — | 16 | $ | (0.25 | ) | |||||||||||||
| Average price per BOE* | 738,968 | $ | 58.50 | 745,297 | $ | 54.71 | 768,433 | $ | 44.58 | ||||||||||||||
| Production costs | Amount | per BOE | Amount | per BOE | Amount | per BOE | |||||||||||||||||
| Production costs, excluding ad valorem and production taxes | $ | 14,027,461 | $ | 18.98 | $ | 11,497,759 | $ | 15.43 | $ | 10,390,041 | $ | 13.52 | |||||||||||
| Total production costs, including ad valorem and production taxes | $ | 14,266,784 | $ | 19.31 | $ | 11,685,817 | $ | 15.68 | $ | 10,604,594 | $ | 13.80 | |||||||||||
For further discussion, see
6
Production volumes, average sales price and average production costs
The following table summarizes our crude oil, natural gas, and natural gas liquids production volumes, average sales price per unit, average daily production on an equivalent basis, production costs, and production costs per unit for the periods indicated:
| | | | | | | | | | | | | | | | | | |
| | Years Ended June 30, | ||||||||||||||||
| | 2022 | | 2021 | | 2020 | ||||||||||||
|
| Volume |
| Price |
| Volume |
| Price |
| Volume |
| Price | ||||||
Production: | | | | | | | | | | | | | | | | | | |
Crude oil (MBBL) | | | | | | | | | | | | | | | | | | |
Delhi Field | | | 358 | | $ | 86.57 | | | 410 | | $ | 49.43 | | | 540 | | $ | 47.63 |
Hamilton Dome Field | | | 150 | | | 76.03 | | | 143 | | | 42.23 | | | 98 | | | 29.18 |
Barnett Shale | | | 9 | | | 82.56 | | | 2 | | | 52.50 | | | — | | | — |
Williston Basin | | | 71 | | | 101.25 | | | — | | | — | | | — | | | — |
Jonah Field | | | 10 | | | 112.50 | | | — | | | — | | | — | | | — |
Other | | | 21 | | | 58.57 | | | — | | | — | | | — | | | — |
Total | | | 619 | | $ | 85.11 | | | 555 | | $ | 47.59 | | | 638 | | $ | 44.79 |
Natural gas (MMCF) | | | | | | | | | | | | | | | | | | |
Barnett Shale | | | 6,087 | | $ | 5.11 | | | 963 | | | 2.73 | | | — | | | — |
Williston Basin | | | 40 | | | 6.30 | | | — | | | — | | | — | | | — |
Jonah Field | | | 1,000 | | | 7.80 | | | — | | | — | | | — | | | — |
Other | | | 14 | | | 1.21 | | | — | | | — | | | 1 | | | 2.00 |
Total | | | 7,141 | | $ | 5.49 | | | 963 | | $ | 2.73 | | | 1 | | $ | 2.00 |
Natural gas liquids (MBBL) | | | | | | | | | | | | | | | | | | |
Delhi Field | | | 83 | | $ | 48.02 | | | 93 | | $ | 18.95 | | | 106 | | $ | 9.60 |
Barnett Shale | | | 256 | | | 46.91 | | | 78 | | | 24.37 | | | — | | | — |
Williston Basin | | | 10 | | | 38.50 | | | — | | | — | | | — | | | — |
Jonah Field | | | 12 | | | 52.92 | | | — | | | — | | | — | | | — |
Other | | | 3 | | | 18.33 | | | — | | | — | | | — | | | — |
Total | | | 364 | | $ | 46.89 | | | 171 | | $ | 21.42 | | | 106 | | $ | 9.60 |
| | | | | | | | | | | | | | | | | | |
Equivalent (MBOE) (1) | | | | | | | | | | | | | | | | | | |
Delhi Field | | | 441 | | $ | 79.32 | | | 503 | | $ | 43.80 | | | 646 | | $ | 41.39 |
Hamilton Dome Field | | | 150 | | | 76.03 | | | 143 | | | 42.23 | | | 98 | | | 29.18 |
Barnett Shale | | | 1,280 | | | 34.27 | | | 241 | | | 19.23 | | | — | | | — |
Williston Basin(2) | | | 88 | | | 88.93 | | | — | | | — | | | — | | | — |
Jonah Field(2) | | | 189 | | | 50.57 | | | — | | | — | | | — | | | — |
Other | | | 25 | | | 52.08 | | | — | | | — | | | — | | | — |
Total | | | 2,173 | | $ | 50.13 | | | 887 | | $ | 36.87 | | | 744 | | $ | 39.78 |
| | | | | | | | | | | | | | | | | | |
Average daily production (BOEPD) (1) | | | | | | | | | | | | | | | | | | |
Delhi Field | | | 1,208 | | | | | | 1,378 | | | | | | 1,765 | | | |
Hamilton Dome Field | | | 411 | | | | | | 392 | | | | | | 268 | | | |
Barnett Shale | | | 3,507 | | | | | | 660 | | | | | | — | | | |
Williston Basin | | | 241 | | | | | | — | | | | | | — | | | |
Jonah Field | | | 518 | | | | | | — | | | | | | — | | | |
Other | | | 68 | | | | | | — | | | | | | — | | | |
Total | | | 5,953 | | | | | | 2,430 | | | | | | 2,033 | | | |
| | | | | | | | | | | | | | | | | | |
Production costs (in thousands, except per BOE) | | | | | | | | | | | | | | | | | | |
Lease operating costs | | Amount | | per BOE |
| Amount | | per BOE |
| Amount | | per BOE | ||||||
Delhi Field | | $ | 14,933 | | $ | 33.86 | | $ | 9,463 | | $ | 18.81 | | $ | 10,659 | | $ | 16.50 |
Hamilton Dome Field | | | 5,480 | | | 36.53 | | | 4,080 | | | 28.53 | | | 2,835 | | | 28.93 |
Barnett Shale | | | 22,825 | | | 17.83 | | | 3,028 | | | 12.56 | | | — | | | — |
Williston Basin | | | 2,419 | | | 27.49 | | | — | | | — | | | — | | | — |
Jonah Field | | | 2,990 | | | 15.82 | | | — | | | — | | | — | | | — |
Other | | | 10 | | | 0.40 | | | 16 | | | — | | | 12 | | | — |
Total | | $ | 48,657 | | $ | 22.39 | | $ | 16,587 | | $ | 18.69 | | $ | 13,506 | | $ | 18.15 |
| (1) | Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil. |
| (2) | Average daily production presented in the table above represents our fiscal year production divided by 365 days in the year. At Williston and Jonah, our average daily production since their respective acquisition dates of January 14, 2022 and April 1, 2022 through June 30, 2022, was 0.5 MBOEPD and 2.1 MBOEPD, respectively. |
7
Productive Wells
The following table sets forth the number of productive oil and natural gas wells in which we ownedown a working interest as of June 30, 2019.
| Company Operated | Non-Operated | Total | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Crude oil | — | — | 119 | 28.4 | 119 | 28.4 | |||||||||||
| Natural gas | — | — | — | — | — | — | |||||||||||
| Total | — | — | 119 | 28.4 | 119 | 28.4 | |||||||||||
| | | | | | | | | | | | |
| | Company Operated | | Non-Operated | | Total | ||||||
|
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
Oil | | — | | — | | 344 | | 83.4 | | 344 | | 83.4 |
Natural gas | | — | | — | | 1,455 | | 209.7 | | 1,455 | | 209.7 |
Total | | — | | — | | 1,799 | | 293.1 | | 1,799 | | 293.1 |
Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2019.2022. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would permitallow production of oil and natural gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.
| | | | | | | | | | | | |
| | Developed Acreage | | Undeveloped Acreage | | Total | ||||||
Field(1) |
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
Delhi Field, Louisiana | | 9,126 | | 2,180 | | 4,510 | | 1,077 | | 13,636 | | 3,257 |
Hamilton Dome Field, Wyoming | | 5,908 | | 1,389 | | — | | — | | 5,908 | | 1,389 |
Barnett Shale, Texas | | 123,777 | | 20,918 | | — | | — | | 123,777 | | 20,918 |
Williston Basin, North Dakota | | 124,800 | | 37,306 | | 23,680 | | 7,389 | | 148,480 | | 44,695 |
Jonah Field, Wyoming | | 5,280 | | 956 | | — | | — | | 5,280 | | 956 |
Total(2) | | 268,891 | | 62,749 | | 28,190 | | 8,466 | | 297,081 | | 71,215 |
| Field | Developed Acreage | Undeveloped Acreage | Total | ||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Delhi Field, Louisiana* | 9,126 | 2,180 | 4,510 | 1,077 | 13,636 | 3,257 | |||||||||||
| (1) | Except for our undeveloped acreage in Williston Basin, North Dakota (see expiration table below), all acreage, including any undeveloped, nonproductive or undrilled acreage, is held by existing production as long as continuous production is maintained in the unit. |
| (2) | This table excludes acreage attributable to small overriding royalty interests retained in various formations in the Texas Giddings Field area. Except for de minimis production that began on two leases during late fiscal year 2019, none of such acreage is currently producing and our interests are subject to expiration if leases are not maintained by others or commercial production is not established. It does not currently appear likely that we will obtain any significant value from these interests and no reserves have been assigned to any of the Giddings’ interests. |
We acquired the Williston Basin properties on January 14, 2022. The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2022 that will expire each year if we do not establish production in paying quantities on the units in which such acreage is currently producing and our interests are subjectincluded to expiration if leases are not maintained by others or commercial production is not established. It does not currently appear likely that we will obtain any significant value from these interests and no reserves have been assigned to any ofmaintain the Giddings interests.lease:
| | |
| | Net Acreage |
Fiscal Year | | Expiration(1) |
2023 | | 1,369 |
2024 | | 440 |
2025 | | 1,664 |
2026 | | 860 |
2027 & beyond | | 309 |
| | 4,642 |
| (1) | Excluded 2,747 net acres held by existing production as long as continuous production is maintained in the unit. |
Markets and Customers
Our production is marketed to third parties in a manner consistent with industry practices. In the U.S.United States market where we operate,our properties are operated, crude oil, and natural gas, liquidsand NGLs are readily transportable and marketable. In the
8
Jonah Field, we take our natural gas and NGL working interest production in-kind and market separately to purchasers on six-month contracts for natural gas and to Enterprise Products Partners L.P. for NGLs. We do not currently market our share of crude oil, natural gas, or NGLs production from the Delhi Field, the Hamilton Dome Field, the Barnett Shale or the Williston Basin separately from the operator's shareoperators’ shares of production. Although we have the right to take our working interest production in-kind, we are currently selling our oil underproduction through the Delhi operator's agreement with Plains Marketing L.P.field operators pursuant to the delivery and pricing terms thereunder. The oil from Delhi is currently transported fromof their sales contracts. Under such arrangements, we typically do not know the field by pipeline, which results in better net pricing thanidentity of the alternative of transportation by truck. Delhi crude oil production sells at Louisiana Light Sweet ("LLS") pricing which generally trades atbuyers.
As a premium to West Texas Intermediate ("WTI") crude oil pricing. The positive LLS Gulf Coast average price differential over WTI, as quoted dailynon-operator, we are highly dependent on the New York Mercantile Exchange ("NYMEX"), was approximately $6.89 per barrel duringsuccess of our fiscal yearthird-party operators and the decisions made in connection with their operations. The third-party operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to us. In the years ended June 30, 2019. The differential has increased from the prior year2022 and we expect that a positive LLS price differential will continue, at least in the near future. Our overall average net realized oil price, including the LLS premium and after all adjustments for transportation, marketing and other price differentials, was $4.11 per barrel more than the average WTI NYMEX price for fiscal 2019.
| Year Ended June 30, | |||||
| Customer | 2019 | 2018 | |||
| Plains Marketing L.P. (Oil sales from Delhi) | 94 | % | 92 | % | |
| American Midstream Gas Solutions. L.P. (NGL sales from Delhi) | 6 | % | 8 | % | |
| All others | — | % | — | % | |
| Total | 100 | % | 100 | % | |
As the acquisition of the Williston Basin and Jonah Field properties occurred in the second half of fiscal year 2022, we expect purchases of our crude oil, natural gas, and NGL production from these properties to represent a larger percentage of total sales in fiscal year 2023 and beyond. The loss of a purchaser at the Delhi fieldany of our five major producing properties or disruption to pipeline transportation from the fieldthese fields could adversely affect our net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be expected to have a material adverse effect on our operations.
Market Conditions
Prices we receive for crude oil, natural gas, and natural gas liquids and the prices we receiveNGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, market prices, government regulation, weather, and actions of major foreign producers.
Oil prices over the past 30few years crude oil price fluctuations have fluctuated widely and been extremely volatile, with crudevolatile. For example, average daily prices for WTI oil prices varyingranged from less than $10a high of $123.64 per barrel to a low of $35.64 per barrel over $140 per barrel. More recently, theour last two fiscal years. The price of oil per barrel dropped dramatically, startingsubstantially in fiscal 2020 as a result of the impact of the novel coronavirus (“COVID-19”) pandemic and geopolitical factors but recovered to an average of $108.83 per barrel during the fiscal fourth quarter of 20142022. The severe drop in oil price during the pandemic and continuing into 2017 before recovering somewhatmarket share competition between OPEC+ members in late calendar 2018the spring of 2020 substantially and then weakening againadversely impacted oil, natural gas, and NGL prices during the balance of 2020, and thus impacted the trailing 12-month commodity prices required for reserves and ceiling tests for asset carrying value which in 2019.turn led to substantial impairments during our first and second quarters of fiscal 2021. Worldwide factors such as global health pandemics, geopolitical, international trade disruptions and tariffs, macroeconomic,macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, influence prices for crude oil.oil, natural gas, and NGLs. Local factors also influence prices for crude oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, and transportation issues unique to certain producing regions and reservoirs.
Competition
The oil and natural gas industry is highly competitive for prospects, acreage, and capital. Our competitors include major integrated crude oil and natural gas companies, and numerous independent crude oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffsstaff and greater capital resources than ours.resources. Competitors are national, regional, or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical and geological areas and geologic systems and the abilitiesability to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves, and obtain capital at rates whichthat allow economic investments.
Risk Management
We are exposed to certain risks relating to our ongoing business operations, including commodity price risk. In accordance with our company policies and the covenants under the Senior Secured Credit Facility, derivative
9
instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We do not enter into derivative contracts for speculative trading purposes.
While there are many different types of derivative instruments available, we typically use costless collars and fixed-price swaps to attempt to manage price risk. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor. The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We will continue to evaluate the benefit of employing derivatives in the future. Our hedge policies and objectives may change as our operational profile changes. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 8, “Derivatives” to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data for additional information.
Government Regulation
As an oil and natural gas exploration and production company, our interests are subject to numerous legal requirements.
Regulation of Oil and Natural Gas Production
Federal, state, tribal and local authorities have promulgated extensive rules covering oil and natural gas exploration, production and related operations. Those regulations require our operating partners to obtain permits, post bonds and submit reports. They also may address conservation, including unitization or pooling of oil and natural gas properties, well locations, the method of drilling and casing wells, surface use and restoration of properties where wells are drilled, sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce and to limit the number of wells or the locations at which we can produce. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any applicable legal requirements may result in substantial penalties. Because such regulations are frequently amended or reinterpreted, we are unable to predict future compliance costs or impacts. Significant expenditures may be required to comply with governmental laws and regulations, however, and may have a material adverse effect on our financial condition and results of operations.
Regulation of Transportation of Oil and Natural Gas
The prices for crude oil, condensate and natural gas liquids and natural gas are negotiated and not currently regulated. But Congress, which has been active in oil and natural gas regulation, could impose price controls in the future.
Our sales of crude oil and natural gas are affected by the availability, terms and cost of transportation. The Federal Energy Regulatory Commission (“FERC”) primarily regulates interstate oil and natural gas transportation rates. In some circumstances, FERC regulations also may affect intrastate pipelines. In addition, states may impose on intrastate pipelines various obligations relating to such matters as safety, environmental protection, nondiscriminatory take and rates. The basis for intrastate oil and natural gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to such matters, vary from state to state. To the extent effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas transportation rates will not affect our business in any way that is of material difference from those of our competitors who are similarly situated.
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Environmental Matters
Our properties are subject to extensive and changing federal, state and local laws and regulations relating to protection of the environment, worker safety and human health. Such requirements may address:
| ● | the generation, storage, handling, emission, transportation and disposal of materials; |
| ● | reclamation or remediation of sites, including former operating areas; |
| ● | the acquisition of a permit or other authorization; |
| ● | air emissions; |
| ● | protection of water supplies; |
| ● | limits on construction, drilling and other activities in wilderness or other environmentally sensitive areas; and |
| ● | assessment of environmental impacts. |
Failure to comply with such requirements may result in a variety of sanctions, including, fines, administrative orders and injunctions. In addition, issuing authorities may revoke, adversely modify or deny permits necessary for our operations. In the opinion of management, our properties are in substantial compliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general. Significant environmental requirements that may affect our operations are described below.
The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for neighboring landowners or other third parties to also file claims for personal injury and property damage allegedly caused by any hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” our operations do entail handling other chemicals that may be subject to the statute. In addition, state laws affecting our properties may impose cleanup liability relating to petroleum and petroleum related products. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste.” Violations may result in substantial fines. Although RCRA currently classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous, thereby subjecting our operations to more stringent handling and disposal requirements. In some circumstances, moreover, RCRA authorizes both the federal government and private persons to seek injunctions requiring the cleanup of wastes, whether hazardous or non-hazardous.
The Endangered Species Act (“ESA”) protects fish, wildlife and plants that are listed as threatened or endangered. Under the ESA, exploration and production operations may not significantly impair or jeopardize a protected species or its habitat. The ESA provides for criminal penalties for willful violations. Our operations also may be subject to other statutes that protect animals and plants such as the Migratory Bird Treaty Act. Although we believe that our properties are in compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our operating partners) to significant expenses to modify operations, could force discontinuation of certain operations altogether and could limit the locations our operating partners may utilize in the future.
The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions. Oil and natural gas production and natural gas processing operations are among the many source categories subject to the CAA. Regulated emissions from oil and natural gas operations include sulfur dioxide, volatile organic compounds (“VOCs”) and hazardous air pollutants such as benzene, among others.
In particular, the Environmental Protection Agency (“EPA”) proposed in November 2021 to impose new CAA rules restricting methane (a greenhouse gas) and VOC emissions from new, existing and modified facilities in the oil and gas industry, including environmental lawssector. Among other things, EPA’s proposed new rule would require states to implement plans that meet or exceed established emission reduction guidelines for oil and regulations.natural gas facilities. These regulations and proposals and any other
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new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.
The Clean Water Act (the “CWA”) is the primary federal law controlling the discharge of produced waters and other pollutants into waters of the United States. Permits must be obtained for such discharges and to conduct construction activities in waters and wetlands. Some states also require permits for discharges or operations that may impact groundwater.
The CAA, CWA and comparable state statutes authorize civil, criminal and administrative penalties for violations. Further, the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface waters.
Pursuant to the Safe Drinking Water Act, EPA (or an authorized state) regulates the construction, operation, permitting, and closure of injection wells used to place oil and natural gas wastes and other fluids underground for storage or disposal. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Underground injection associated with oil and gas operations, particularly the disposal of produced water, has been linked in some cases to localized earthquakes. This in turn has led to new legislative and regulatory initiatives, which have the potential to restrict injection in certain wells or limit operations in certain areas.
Substantially all of the oil and natural gas production in which we have an interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection into the formation of water, sand and chemicals under pressure to stimulate production. From time to time, legislation has been proposed in the United States Congress to repeal the Safe Drinking Water Act’s exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting of hydraulic fracturing. If ever enacted, such legislation would add to our production costs.
Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have enacted bans on hydraulic fracturing. We cannot predict whether any other legislation restricting hydraulic fracturing will be enacted and if so, what its provisions would be. If additional levels of regulation and permits were to be required through the adoption of new laws and regulations at the federal, state, tribal or local level, it could lead to delays, increased operating costs and process prohibitions that could materially adversely affect our revenue and results of operations.
The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to making decisions. Among the broad range of actions covered by NEPA are often changed in responsedecisions on permit applications and federal land management. Many of the activities of our third-party operating partners involve federal decisions subject to NEPA. Such federal actions may trigger robust NEPA review, which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations. In 2022, moreover, the Biden Administration reversed changes to NEPA rules enacted under the Trump Administration that had been intended to streamline NEPA review. The revised regulations lay the foundation for additional scrutiny of impacts on climate change, which could affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.
Climate Change
Climate change has become a major public concern and policy issue in the politicalUnited States and around the world. Much of the debate has focused on greenhouse gas (“GHG”) emissions from oil and natural gas, particularly carbon dioxide and methane.
In the United States, there is no comprehensive federal regulatory statute addressing climate change, although Congress does periodically consider such measures. At the federal level, the United States therefore has primarily addressed climate change through executive actions and regulatory initiatives pursuant to existing statutes. These include rejoining
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the Paris Agreement on climate change, the Biden Administration’s commitment to cut greenhouse gas emissions by 2030 to 50-52 percent of 2005 levels, various executive orders, limiting land available for oil and gas leasing, the United States Methane Emissions Reduction Action Plan, and Clean Air Act rules (such as the November 2021 proposal to regulate methane from the oil and gas sector). In addition, several states have already implemented or economic environment. Compliance with this evolving regulatory burden is often difficultare considering programs to reduce GHG emissions. These include cap and costly,trade programs, promotion of alternative forms of energy, transportation standards and substantial penaltiesrestrictions on particular GHGs. To the extent that new climate change measures are adopted, and our third-party operating partners must further control GHG emissions, our business may be incurredadversely impacted.
In addition, recent court decisions have left open the question of whether tort claims alleging property damage may proceed against sources of GHG emissions under state common law. Thus there is some litigation risk for noncompliance.such claims.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the bestextent that our products are competing with higher GHG emitting energy sources, for example, our products would become more desirable in the market with more stringent limitations on GHG emissions. But in 2022, the United States enacted the Inflation Reduction Act that, among other things, creates a series of financial incentives intended to discourage use of oil and natural gas (including imposing a fee on methane emissions) and to promote alternative sources of energy. To the extent that our knowledge,products are competing with lower GHG emitting energy sources such as solar and wind, our products may become less desirable in the market with such government intervention. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Various studies on climate change indicate that extreme weather conditions and other risks may occur in the future in the areas where we are in compliance with all laws and regulations applicableoperate. Although we have not experienced any material impact from such extreme conditions to our operations and we believedate, no assurance can be given that continued compliance with existing requirementsthey will not have a material adverse impact on us. The future annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable. However, we do not currently anticipate that future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.
See "Governmentdiscussion captioned “Government regulation and liability for oil and natural gas operations and environmental matters that may adversely affect our business and results of operations" underoperations” in Item 1A. Risk Factors of this Form 10-K, for additional information regarding government regulation.
Insurance
We maintain insurance on our oil and natural gas properties and operations for risks and in amounts customary in the industry. Such insurance includes, but is not limited to, general liability, excess liability, control of well, operators extra expense, casualty, fraud, and directors & officer'sand officer’s liability coverage. Not all losses are insured, and we retain certain risks of loss through deductibles, limits, and self-retentions. We do not carry business interruption or lost profits coveragecoverage.
Human Capital, Sustainability, and we do not have coverage for consequential damages.
Employees
As of June 30, 2019,2022, we had foureight full-time employees, not including contract personnel and outsourced service providers. None of the Company’s employees are currently represented by a union, and the Company believesWe believe that it has excellentwe have positive relations with itsour employees. Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative, and other non-core functions. AsFor our full-time employees, our benefits package, as determined by our Board of Directors, includes medical, dental, and vision insurance, 401(k) contributions based on a resultportion of the retirementemployee’s base salary, short and long-term performance-based and service-based incentive pay (i.e., annual bonuses and stock awards), and paid time off.
Our workforce is provided with annual training and is expected to sign an acknowledgement regarding our policies and disclosures which include, but are not limited to, the Corporate Sustainability Report (“CSR”), employee handbook, human rights, code of Randy Keys, Presidentethics, health and Chief Executive Officersafety, emergency procedures, conflicts of interest, insider trading, bribery, kickbacks, discrimination, diversity, equality, and inclusion.
Sustainability and ESG
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In fiscal year 2021, we formed an Environmental Social Governance (“ESG”) Task Force. Under the supervision of our Board of Directors, the Nominating and Corporate Governance committee, and senior management, the ESG task force is responsible for the creation and implementation of our CSR and ESG initiatives. Evolution’s inaugural CSR was published in November 2021. This report is accessible on May 31, 2018,our website at www.evolutionpetroleum.com.
The ESG Task Force has formalized our existing ESG programs, proposed and implemented new ESG initiatives, monitored adherence to ESG standards, and provided public disclosures for our stakeholders. In fiscal year 2022, the ESG Task Force continued to disclose, enhance, implement, and provide training for a number of new and existing policies and procedures. These include, but are not limited to: formalizing and implementing charitable donation program and employee volunteer initiative, completing our first annual company-wide ESG training program for both the Board of Directors named Robert Herlinand our workforce, implementation of safety inspections and health and safety coordinators, and incorporating ESG considerations into our compensation structure.
We are committed to acthigh standards of conduct and ethics in order to contribute to the sustainability of our business. Our core values are the base to support our strategy and long-term success. We believe integrity is paramount and we are committed to develop and produce energy resources in environmentally, socially, and ethically respectful and responsible ways. Our people are critical to our success and as Interim Chief Executive Officersuch we promote and maintain a safe and inclusive work environment. We strategically plan for the long-term and strive to commencemaintain capital discipline and stakeholder transparency and continuous focus on returning capital to shareholders. We work with third-party operators that share our desire to operate and work responsibly, particularly for the natural environments in which they operate.
As a searchnon-operator of our current properties, we do not have direct control over environmental initiatives at a property-level. However, we believe it is important to partner with third-party operators that share our core values and are committed to being environmental stewards as they responsibly produce energy resources. We recognize that the expectations, requirements, and responsibilities of operators regarding safeguarding the environment and environmental stewardship continue to evolve. We are, and will continue to be, committed to supporting our third-party operators as they respond to these expectations, requirements, and responsibilities.
At present, we do not report or collect data regarding emissions, water use, waste generation, spills, or other similar measurements on behalf of our operating partners. We host regular operations meetings with our operating partners in which we discuss asset level operations, expenses, any environmental issues and compliance, as well as ESG and health and safety related topics.
We do not report Scope 1 GHG, or direct, emissions to the EPA as we are not the operator of our properties, nor do we have financial control over our oil and natural gas properties and operations. We prefer to partner with third-party operators that work to reduce their Scope 1 GHG emissions, and we encourage them to accelerate their efforts as appropriate in this regard. As a non-operator, the Company reports in its CSR the estimated Scope 2 GHG emissions for a permanent Chief Executive Officer. A special Transition Services Committeeits corporate office located in Houston, Texas. Scope 2 GHG emissions are based on indirect emissions representing purchased electricity. We are one of many tenants leasing space in our corporate office building and do not know the actual amount of electricity used in our space. As such, we estimate our consumption by multiplying the electricity purchased for the entire building by the percentage of the board was created with one member, William Dozier,floor area that we occupy. Water use is also reported in the CSR and is calculated in a similar fashion.
We maintain a hotline which operates 24/7/365 and allows anonymous and confidential reporting for employees, consultants, partners, and contractors, including the ability to provide additional operational oversight toreport concerns or violations of our policies through the Company during the transition to a new Chief Executive Officer. On July 10, 2019, Mr. Jason Brown was appointed by the Board of Directors to serve as President and Chief Executive Officer of the Company. Robert Herlin, remained as Chairman of the Board.
Additional Information
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports with the Securities and Exchange Commission ("SEC") .SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or calling
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(713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
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Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider to be immaterial also may adversely affect us.
Risks relatedRelated to the oil and gas industry and our Company
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil and natural gas significantly influences our revenue, profitability, access to capital, capital spending, and future rate of growth. At June 30, 2022, approximately 32% of our proved reserves were oil reserves, 49% were natural gas and 19% were NGLs. Oil, is a commoditynatural gas and its price isNGLs are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, over our last two fiscal years average daily prices for WTI crude oil ranged from a high of $74$123.64 per barrel to a low of $27a $35.64 per barrel, over the past four fiscal years ending June 30, 2019.and Henry Hub natural gas prices ranged from a high of $23.86 to a low of $1.33 per MMBTU. Historically, the markets for oil, and natural gas, liquidsand NGLs have been volatile and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to the following:
Substantially all of our production is sold to purchasers under short-term (less than twelve-month)12-month) contracts at market-based prices. A decline in oil, and natural gas, liquidsand NGL prices will reduce our cash flows, borrowing ability, the present value of our reserves, and our ability to develop future reserves. We may be unable to obtain needed capital or financing on satisfactory terms. Low oil, and natural gas, liquidsand NGL prices may also reduce the amount of oil, and natural gas, liquidsand NGL that we can produce economically, which could lead to a decline in our oil, natural gas and NGL reserves. Generally, we hedge substantially less than all of our anticipated oil and natural gas liquids reserves. Because approximately 85%production and typically only with the requirements of our proved reserves at June 30, 2019 are crude oil reserves and 15% are natural gas liquids reserves, we are heavily impacted by movements in crude oil prices, which also influence natural gas liquids prices.Senior Secured Credit Facility. To the extent that we have not hedged our production, with derivative contracts or fixed-price contracts, any significant and extended decline in oil, and natural gas, liquidsand NGL prices may adversely affect our financial position.
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Our revenues are concentrated in one asset and related declines in production or other events beyond our control could have a material adverse effect on our results of operations and financial results.
The volume of production from crude oil and natural gas properties declinedeclines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we acquire additional properties containing proved reserves or conduct successful development activities, or both, our proved reserves will decline. Our production is heavily dependent on our interests in EOR production that began during March 2010 in the Delhi field. Environmental orissues, operating problems, or lack of extended future investment at Delhi couldin any of our properties would cause our net production of oil, and natural gas, liquidsand NGLs to decline significantly over time, which could have a material adverse effect on our financial condition.
Our business plan focuses on the acquisition and development of known resources in partially depleted, naturally fractured, or low permeability reservoirs. Our Delhi Field and Hamilton Dome Field properties produce from relatively shallow reservoirs, while our Barnett Shale, Williston Basin and Jonah Field properties produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserves volumes in place. Deeper reservoirs have higher pressures and usually more reserves volumes in place, but capturing those reserves often comes at increased drilling and completion costs and risks and, generally, a higher rate of production decline. Low permeability reservoirs require more wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient un-depleted fractures to establish commercial production. Depleted reservoirs require successful application of newer, or more expensive, technologies to produce incremental reserves. Our approach on the development and application of technologies on these different types of reservoirs could have a material adverse effect on our results of operations.
The CO2-EOR project in the Delhi Field, operated by Denbury, requires significant amounts of CO2 reserves, development capital, and technical expertise, the sources of which to date have been committed by the operator. Although initial CO2 injection began at the Delhi Field in November 2009, initial oil production response began in March 2010. Additional capital remains to be invested to fully develop the EOR project and maximize the value of the properties. The operator’s failure to manage these and other technical, environmental, operational, strategic, financial, and logistical risks may ultimately cause enhanced recoveries from the planned CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material adverse effect on our results of operations and financial condition.
We have limited control over the activities on properties we do not operate.
All of our property interests are not operated by the Company and also involve other third-party working interest owners.owners, not by us. As a result, we have limited ability to influence or control the operationoperations or future development of such properties, including compliance with environmental, safety, and other regulations,standards, or the amount of capital expenditures that we will be required to fund with respect to such properties. Operators of these properties may act in ways that are not in our best interest. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production, and materially and adversely affect our financial conditionscondition and results of operations.
We will be subject to risks in connection with acquisitions.
We periodically evaluate acquisitions of reserves, properties, prospects, leaseholds, and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including, but not limited to:
| ● | recoverable reserves; |
| ● | future oil and natural gas prices and their appropriate differentials; |
| ● | development and operating costs; |
| ● | potential for future drilling and production; |
| ● | validity of the seller's title to properties, which may be less than expected at closing; and |
| ● | potential environmental issues, litigation, and other liabilities. |
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The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are materially dependent upon our operator with respectnot necessarily observable at the ground surface or otherwise when an inspection is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the successful operation of our principal asset, which consists of our interests the Delhi field. A materially negative change in our operator’s financial condition could negatively affect operations (or timing thereof)problems. Moreover, in the Delhi field,event of such an acquisition, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions and, consequentlyimportantly, that our income (or timing thereof) from the field as well as the value of our interests in the Delhi field.
We may encounter difficulties integrating the operations of newly acquired oil and financialnatural gas properties or businesses.
Increasing our reserve base through acquisitions has been an important part of our business strategy. We may encounter difficulties integrating newly acquired oil and natural gas properties or businesses. In particular, we may face significant challenges in consolidating functions and integrating procedures, personnel, and business operations in an effective manner. The failure to successfully integrate such properties or businesses into our Company may adversely affect our business and results (or timing thereof). We are notof operations. Any acquisition we make may involve numerous risks, including:
| ● | a significant increase in our indebtedness and working capital requirements; |
| ● | the inability to timely and effectively integrate the operations of recently acquired businesses or assets; |
| ● | the incurrence of substantial costs to address unforeseen environmental and other liabilities arising out of the acquired businesses or assets; |
| ● | liabilities arising from the operation of the acquired businesses or assets before our acquisition; |
| ● | our lack of drilling or operational history in the areas in which the acquired business operates; |
| ● | customer or key employee loss from the acquired business; |
| ● | increased administration of new personnel; |
| ● | additional costs due to increased scope and complexity of our business; |
| ● | potential disruption of our ongoing business; and |
| ● | assumptions made on estimated development by the operator may not be accurate or may change. |
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the Delhi field. It is operated by a subsidiary of Denbury Resources Inc. (“DNR”), an independent oilacquired properties, which may have substantially different operating and gas company specializinggeological characteristics or be in tertiary recovery with CO
Oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production, and drilling and completing new wells are speculative activities andwhich involve numerous risks and substantial uncertain costs.
Our growth will be materiallypartially dependent upon the success of our future development program.programs on our properties. Drilling for crude oil and extracting natural gas liquidsand extracting NGLs and re-working existing wells involve numerous risks, including the risk that no commercially productive crude oil or natural gas reservoirs will be encountered.risks. The cost of drilling, completing, and operating wells is substantial and uncertain, anduncertain; drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including, but not limited to:
| ● | unexpected drilling conditions; |
| ● | pressure fluctuations or irregularities in reservoir formations; |
| ● | equipment failures or accidents; |
| ● | well blowouts and other releases of hazardous materials; |
| ● | inability to obtain or maintain leases on economic terms, where applicable; |
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| ● | the cost and availability of goods and services, such as drilling rigs, fracture stimulation services, and tubulars; |
| ● | adverse weather conditions; |
| ● | compliance with governmental requirements; and |
| ● | shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. |
Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion and production techniques, such as horizontal drillingHorizontal Drilling or CO
We may also identify and develop prospects through a number of methods, some of which may include horizontal drillingHorizontal Drilling or tertiary injectants, and some of which may be unproven. The drilling and results for these prospects may be particularly uncertain. We cannot assure youensure that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive crude oil or natural gas.
Our crude oil and natural gas reserves are only estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. Our reserves are only estimates that may prove to be inaccurate because of these inherent uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot always be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors. These factors such asinclude historical production from the area compared with production from other comparable producing areas, and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas product prices, future operating costs, severance and excise taxes, development costs, and work-overworkover costs, and remedial costs. Some or all of these assumptions utilized in estimating reserve volumes may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties,reserves, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared byfrom reserves may vary substantially depending on the timing and different engineers or by the same engineers but at different times, may vary substantially.
Accordingly, reserve estimates may be subject to downward or upward adjustment.adjustments. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates, andestimates; such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interestfactor. Interest rates in effect vary from time to time andbased on risks associated with us or the crude oil and natural gas industry in general. The Standardized Measure and PV-10 dodoes not necessarily correspond to market value.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
On a periodic basis, we review the carrying value of our crude oil and natural gas properties under the applicable rules of the various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this "ceiling"“ceiling” test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write downwrite-down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when crude oil and natural gas prices are depressed or unusually volatile. Whether we will be required to
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take such a charge will depend in part on the prices for crudeof oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period. If a write downwrite-down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating activities. A large write-down could adversely affect our compliance with the current financial covenants under our credit facility, and could limit our access to future borrowings under that facility, or require repayment of any amounts that might be outstanding at the time.
Our derivative activities could result in financial losses or could reduce our income.
We are required under the terms of our Senior Secured Credit Facility to reducehedge a certain portion of our exposure to adverse fluctuations in the prices ofanticipated oil and natural gas liquids,production for future periods. We may also elect to hedge additional production volumes from time to time based upon our view of the attractiveness of commodity futures and the risks that downward price fluctuations might pose to our business plans. When we have, and mayengage in the future, enter into derivative arrangements for a portion of our oil and natural gas liquids production, includinghedging transactions, we typically utilize costless collars and fixed-price swaps.or fixed price swaps to cost-effectively provide us with some protection against price changes. We have not historically designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our future derivative instruments. Derivative arrangements may also expose us to the risk of financial loss in some circumstances, including, but not limited to, if:
| ● | actual production is less than the volume covered by the derivative instruments; |
| ● | the counterparty to the derivative instrument defaults on its contract obligations; or |
| ● | there is a change in the expected differential between the underlying price in the derivative instrument and actual price received. |
In addition, some of these types ofin a rising commodity price environment, derivative arrangements will limit the benefitextent to which we would receivemight benefit from increases in the prices forof oil and natural gas liquids and may expose us to cash margin requirements.
Our operations may require significant amounts of capital and additional financing may be necessary in order for us to continue our exploitation activities, including meeting potential future drilling obligations.
Cash flow from our reservesproduction may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and natural gas acquisitions, exploitation, and development activities. Certain of our undeveloped leasehold acreage may be subject to leases that will expire unless production is established. If our revenues from our reserves decrease as a result of decreases in production, lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or be available to us on favorable terms.
Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations.
Oil and natural gas operations are subject to extensive federal, state, and local government regulations, which may be changedchange from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas from wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are federal, state, and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation, and disposal of crude oil and natural gas, by-products thereof, the emission of CO
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operate, even if we did not cause or contribute to the release. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations, could have a material adverse effect on us, such as diminishing the demand for our products through legislative enactment of proposedby imposing new emission controls, penalties, fines and/or fees, taxes and tariffs on carbon that could have the effect of raising prices to the end user.user and thereby reducing the demand for our products.
The risks arising out of the threat of climate change, including transition risks and physical risks, may adversely affect our business and results of operations.
The threat of climate change poses both transition risks and physical risks that could have a material adverse effect on us. Transition risks may arise from political and regulatory, legal, technological or financial changes as society tries to safeguard the climate, while physical risks may result from extreme weather events or other shifts in the natural world.
We have been facing increased political and regulatory risks as federal, state and local governments have adopted new measures to restrict sources of greenhouse gas emissions and promote energy alternatives. Many such measures have been proposed, and still more can be expected. From time to time, there are proposals to ban Hydraulic Fracturing of oil and natural gas wells and to remove more lands, both onshore and offshore, from new hydrocarbon production. Many other actions could be pursued such as more rigorous requirements for drilling and construction permits, stricter greenhouse gas emissions standards for both new and existing sources, further limits on construction of new pipelines, reinstatement of the ban on oil exports, enhanced reporting obligations, taxing carbon emissions and creating further incentives for use of alternative energy sources. These actions may cause operational delays or restrictions, increased operating costs and additional regulatory burdens.
Litigation risks are also increasing for oil and natural gas companies. A number of suits alleging, among other things, that oil and natural gas companies created public nuisances by producing fuels that contributed to climate change have been brought in state or federal court.
Technological changes may drive market demand for products other than oil and natural gas. Wider adoption of hybrid engines and electric cars, for example, would reduce demand for our products. At the same time, our capital and operating costs may increase if we need to add new emission reduction technologies.
There are also financial risks for the petroleum industry. It may become more difficult for us to access the capital markets if the threat of climate change discourages new investment. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices, and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for the energy industry could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The threat of climate change also may subject our operations and business to severe weather or other natural hazards, such as flooding, drought, wildfires, and extreme temperatures. Any such event could halt production or exploration activities, disrupt transportation and reduce consumer demand.
Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.
During the last few years, concerns over inflation, energy costs, volatile oil and natural gas prices, geopolitical issues, the availability and cost of credit, the United States mortgage market, uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on domestic and international financial markets and commodity prices. If uncertain or poor economic, business, or industry conditions in the United States or abroad remain prolonged, demand for petroleum products could diminish or stagnate, and production costs could increase. These situations could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors', suppliers', and customers' ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition.
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Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the ongoing global outbreak of a novel strain of the coronavirus (“COVID-19”), may materially adversely affect our business.
We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition. In December 2019, COVID-19 was identified in Wuhan, China and rapidly spread around the world. This virus and its variants, and governmental actions to contain it, continue to have a material impact globally. These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, and lead to disruptions in our permitting activities and critical business relationships. Additionally, governmental restrictions intended to contain COVID-19 or future pandemics have in the past, and may in the future, significantly impact economic activity and markets and dramatically reduce actual or anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of any such events are uncertain and difficult to predict, as is the extent that such events may have on our business.
Our business could be negatively affected by security threats. A cyber attackcyber-attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation, and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third partythird-party partners. Our technologies, systems, networks, seismic data, reserves information, or other proprietary information, and those of our operator,operators, vendors, suppliers, customers, and other business partners may become the target of cyber attackscyber-attacks or information security breaches. Cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyber attacksCyber-attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation, or potential liability. Also, computers control nearly all of the oil and natural gas distribution systems in the United States and abroad, whichabroad. Computers are necessary to transport our oil and natural gas production to market. A cyber attackcyber-attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S.United States government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyber attackscyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber attacks.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas, or well fluids, fires, formations with abnormal pressures, hurricanes and storms, flooding, pollution, releases of toxic gas, and other environmental hazards and risks, which can result in (i)(1) damage to or destruction of wells and/or production facilities, (ii)(2) damage to or destruction of formations, (iii)(3) injury to persons, (iv)(4) loss of life, or (v)(5) damage to property, the environment or natural resources. While we carry general liability, control of well, and operator'soperator’s extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our business. Environmental events similarShould we experience any losses, the costs of our premiums may rise, which could in turn reduce the amount of insurance we are able to that experienced in the Delhi field in June 2013 could defer revenue, increase operating costs and/or increase maintenance and repair capital expenditures.carry.
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The loss of key personnel could adversely affect us.
We depend to a large extent on the services of certain key management personnel, including our executive officers, theofficers. The loss of any of whomone or more key personnel could have a material adverse effect on our operations. In particular, our future success is dependent upon
Oilfield service and materials'materials prices may increase, and the availability of such services and materials may be inadequate to meet our needs.
Our business plan to develop or redevelop crude oil and natural gas resources requires third partythird-party oilfield service vendors and various material providers, which we do not control. We also rely on third-party carriers for the transportation and distribution of our oil and natural gas production. As our production increases, so does our need for such services and materials. Generally, we do not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our crude oil and natural gas fieldsproviding services for any reason or we may not be able to source the services or materials we need. Any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems, with a resulting in loss of revenue to us. In addition, if costs for such services and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelopredevelopment plans.
We may assume risks and financial responsibility for drilling and completing wells on our Williston Basin properties if our operating partner declines to drill wells and it or other joint interest owners elect not to participate.
As discussed elsewhere in this report, pursuant to agreements related to our interests in the Williston Basin properties, we have the ability to propose to the operator a drilling plan for certain wells, which the operator may accept or reject. In the event the operator rejects our proposed drilling plan, we have the right to undertake all necessary activities to drill and complete the wells and related facilities in accordance with our proposed drilling plan. In the event we undertake to do so, and the operator and other joint interest owners elect not to participate, we will bear the entire liability and expense associated with drilling and completing the wells and related facilities, subject only to our right to recoup costs incurred on behalf of non-participating joint interest owners to the extent a well generates sufficient revenues to do so. Ongoing operations of any wells we elect to drill, will be turned over to the operator of the property upon completion. If we elect to proceed to drill and complete wells we have proposed and the operator has rejected, certain of the risks highlighted elsewhere in this report, including, without limitation, the risks associated with drilling oil and natural gas wells and in addition to bearing the liability and costs associated with any wells we elect to drill and complete, many of the risks highlighted elsewhere herein will be exacerbated, including, without limitation, the risks of developing economic reserves; the risks associated with the drilling and completion of oil and natural gas wells, including potential environmental and other operating liabilities, inadequate insurance to cover the expenses and liabilities associated with such risks, price increases and delivery delays for required drilling and completion equipment, products and services; and financing risks, as we may be required to bear a share of such expenses to an extent that is disproportionate to our economic interest in the property.
We cannot market the crude oil and natural gas that we produce without the assistance of third parties.
The marketability of the crude oil and natural gas that we produce depends upon the proximity of our reserves and production to, and the capacity of, facilities and third-party services, including crude oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in, or delay, or discontinuance could adversely affect our financial condition.
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We face strong competition from larger oil and natural gas companies.
Our competitors include major integrated crude oil and natural gas companies, and numerous larger independent crude oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours.resources. We may not be able to successfully conduct our operations, evaluate and select suitable properties, andor consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive crude oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment, and acquiring the existing and changing technologies that we believe are, and will be, increasingly important to attaining success in our industry.
We have been, and in the future may become, involved in legal proceedings related to our Delhi interest or other properties or operations and, as a result, may incur substantial costs in connection with those proceedings.
From time to time we may be a defendant or plaintiff in various lawsuits. The nature of our operations exposes us to further possible litigation claims in the future. There is risk that any matter in litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow. Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition. Adverse litigation decisions or rulings may damage our business reputation.
Ownership of our oil, natural gas, and mineral production depends on good title to our property.
Good and clear title to our oil, natural gas, and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, natural gas, and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim whichclaim. This could result in a reduction or elimination of the revenue received by us from such properties.
We are subject to tax by U.S. federal, state, and local tax authorities. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:
| ● | changes in the valuation of our deferred tax assets and liabilities; |
| ● | expected timing and amount of the release of any tax valuation allowances; |
| ● | tax effects of stock-based compensation; |
| ● | costs related to intercompany restructurings; or |
| ● | changes in tax laws, regulations, or interpretations thereof. |
For example, in previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and natural gas exploration and production companies. Such proposed changes have included: (1) a repeal of the percentage depletion allowance for oil and natural gas properties; (2) the elimination of deductions for intangible drilling and exploration and development costs; (3) the elimination of the deduction for certain production activities; and (4) an extension of the amortization period for certain geological and geophysical expenditures. With President Biden taking office in 2021 and the shift in the control of Congress, there is an increased risk of the enactment of legislation that alters, eliminates, or defers these or other tax deductions utilized within the industry, which could adversely affect our business, or industry conditionsfinancial condition, results of operations, and cash flows.
In addition, we may be subject to audits of its income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities. Outcomes from these audits could have a materialan adverse effect on our financial condition and results of operations, liquidity, and financial condition.operations.
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Risks Associated with Ourour Common Stock
Our stock price has been and may continue to be volatile.
Our common stock has a relatively low trading volume and the market price has been, and is likely to continue to be, volatile. For example, during the fiscal year ending June 30, 2019, our stock price as traded on the NYSE American ranged from $5.99 to $12.32. The variance in our stock price makes it difficult to forecast with certainty the stock price at which an investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:
| ● | actual or anticipated variations in our results of operations; |
| ● | changes or fluctuations in the commodity prices of oil and natural gas; |
| ● | general conditions and trends in the oil and natural gas industry; |
| ● | redemption demands on institutional funds that hold our stock; and |
| ● | general economic, political, and market conditions. |
Significant ownership of our common stock and stock price manipulation;
As of June 30, 20192022, our executive officers and directors, in the aggregate, beneficially owned approximately 2.52,554,184 million shares, or approximately 7.4% of our beneficial common stock base. Blackrock Fund Advisors, et al controlled approximately 3.5 million shares or approximately 10.6 % of our outstanding common stock, Renaissance Technologies, LLC controlled approximately 2.2 million shares or approximately 6.7%7.6% of our outstanding common stock and, JVL Advisors, LLC controlled approximately 2.1 millionbased on recent filings with the SEC, we believe two large unaffiliated fund complexes each owned in excess of 6% of the outstanding shares or approximately 6.5%.of our common stock. As a result, anya significant percentage of these holdersour common stock is concentrated in the hands of relatively few shareholders. These shareholders could potentially exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring, or preventing any matter that requires shareholder approval, including a change in control of our company, impede a merger, consolidation, takeover, or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.
The market for our common stock is limited and may not provide adequate liquidity.
Our common stock trades on the NYSE American. Our trading volumes increased in fiscal 2019 compared to fiscal 2018. Trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30, 2019, the daily trading volume in our common stock ranged from a low of 45,600 shares to a high of 1,079,500 shares, with average daily trading volume of 180,353 shares compared to average daily volume of 112,015 in fiscal 2018. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that time relative to the quantity of shares to be sold.
If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge, there are three independentonly two research analysts thatactively cover our company. The limited number of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.
Payment of dividends on our common stock has been in the past, and could be impacted.
Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have declared and paid quarterly cash dividends since that time. However, there is no certainty that dividends will be declared by theour Board of Directors in the future. Any payment of cash dividends on our common stock in the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition, andour business plan,
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restrictions contained in current or future debt instruments, contractual covenants or arrangements we may enter into, our anticipated capital requirements, and other factors that our boardBoard of directorsDirectors may think are relevant. Accordingly,Although it is our intent to maintain a steady dividend for our shareholders, there is no guarantee that we will be able to do so.
There may be future sales or choose to continue to pay cash dividends onissuances of our common stock, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock.
We may in the future issue additional shares of common stock, including securities that are convertible into or exchangeable for, or that represent the right to receive, common stock or substantially similar securities, which may result in dilution to our stockholders. In addition, our stockholders may be further diluted by future issuances under our equity incentive plans. The market price of our common stock could decline as a result of sales or issuances of a large number of shares of our common stock or similar securities in the market after this offering or the perception that such sales or issuances could occur.
Non-U.S. holders may be subject to U.S. income tax and withholding tax with respect to gain on disposition of the Company’s common stock.
We believe we are a U.S. real property holding corporation. As a result, Non-U.S. holders that own (or are treated as owning under constructive ownership rules) more than a specified amount of our common stock during a specified time period may be subject to U.S. federal income tax and withholding on a sale, exchange or other disposition of such common stock, and may be required to file a U.S. federal income tax return.
Investor sentiment towards climate change, fossil fuels, sustainability, and other ESG matters could adversely affect our business and our stock price.
There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities, and other groups, to promote the divestment of shares of fossil fuel companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with fossil fuel companies. As a result, some financial intermediaries, investors, and other capital markets participants have reduced or ceased lending to, or investing in, companies that operate in industries with higher perceived environmental exposure, such as the oil and natural gas industry. For example, in December 2020, the State of New York announced that it will be divesting the state’s Common Retirement Fund from fossil fuels. If this or similar divestment efforts are continued, the price of our common stock or debt securities, and our ability to access capital markets or to otherwise obtain new investment or financing, may be negatively impacted.
Members of the investment community are also increasing their focus on ESG practices and disclosures, including practices and disclosures related to greenhouse gases and climate change in the energy industry in particular, and diversity and inclusion initiatives and governance standards among companies more generally. As a result, we may face increasing pressure regarding our ESG practices and disclosures. Additionally, members of the investment community may screen companies such as ours for ESG performance before investing in our common stock or debt securities or lending to us. Over the past few years there has also been an acceleration in investor demand for ESG investing opportunities, and many large institutional investors have committed to increasing the percentage of their portfolios that are allocated towards ESG-focused investments. As a result, there has been a proliferation of ESG-focused investment funds seeking ESG-oriented investment products.
If we are unable to meet the ESG standards or investment or lending criteria set by these investors and funds, we may lose investors, investors may allocate a portion of their capital away from us, our cost of capital may increase, the price of our common stock may be negatively impacted, and our reputation may also be negatively affected.
Item 1B. Unresolved Staff Comments
None.
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Item 2. Properties
Information regarding our properties is included in “ItemItem 1. Business”Business above and in “Note 6. Note 5, “Property and Equipment” of the Notes to our Consolidated Financial Statements includedconsolidated financial statements in “ItemItem 8.Consolidated Financial Statements and Supplementary Data”, which information is incorporated herein by reference.
Item 3. Legal Proceedings
See Note 16 – 11, “Commitments and Contingencies under
Item 4. Mine Safety Disclosures
Not Applicable.
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PART II
Item 5. Market for Registrant'sRegistrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Our common stock is currently traded on the NYSE American stock exchange under the ticker symbol "EPM"“EPM”. The following table shows, for each quarter of the fiscal years ended June 30, 2019 and 2018, the high and low sales prices for EPM as reported by the NYSE American.
| 2019: | High | Low | |||||
| Fourth quarter ended June 30, 2019 | $ | 7.40 | $ | 5.99 | |||
| Third quarter ended March 31, 2019 | $ | 8.11 | $ | 6.44 | |||
| Second quarter ended December 31, 2018 | $ | 12.83 | $ | 6.17 | |||
| First quarter ended September 30, 2018 | $ | 12.00 | $ | 9.60 | |||
| 2018: | High | Low | |||||
| Fourth quarter ended June 30, 2018 | $ | 10.50 | $ | 7.75 | |||
| Third quarter ended March 31, 2018 | $ | 8.30 | $ | 6.70 | |||
| Second quarter ended December 31, 2017 | $ | 7.63 | $ | 6.35 | |||
| First quarter ended September 30, 2017 | $ | 8.70 | $ | 6.35 | |||
Shares Outstanding and Holders
As of June 30, 2019,2022, there were 33,183,73033,470,710 shares of common stock issued and outstanding, held byoutstanding. As of September 1, 2022, there were approximately 250 holders219 registered shareholders of record. We estimate there are approximately 2,000 individuals and institutions that hold our stock through nominees.
Dividends
We began paying cash quarterly dividends on our common stock in December 2013. Over the last two fiscal years, the Companywe made the following cash dividends per share:
| Years Ended June 30, | |||
| 2019 | 2018 | ||
| Fourth quarter ended June 30, | $0.100 | $0.100 | |
| Third quarter ended March 31, | $0.100 | $0.100 | |
| Second quarter ended December 31, | $0.100 | $0.075 | |
| First quarter ended September 30, | $0.100 | $0.075 | |
| | | | | | |
| | Fiscal Year | ||||
|
| 2022 |
| 2021 | ||
Fourth quarter ended June 30, | | $ | 0.100 | | $ | 0.050 |
Third quarter ended March 31, | | $ | 0.100 | | $ | 0.030 |
Second quarter ended December 31, | | $ | 0.075 | | $ | 0.025 |
First quarter ended September 30, | | $ | 0.075 | | $ | 0.025 |
As of June 30, 2019,2022, we hadhave paid twenty-three35 consecutive quarterly dividends on our common stock. In August 2019,September 2022, the Company declared a $0.10$0.12 per share dividend payable on September 30, 2019.2022. Any future determination with regard to the payment of dividends will be at the discretion of the Board of Directors and will be dependent upon our future earnings, financial condition, results of operations, applicable dividend restrictions, and capital requirements, and other factors deemed relevant by the Board of Directors. Under our current revolving credit facility, our ability to continue to pay common stock dividends is dependent on compliance with certain financial covenants related to debt service coverage, as defined in the agreement.
Securities Authorized For Issuance Under Equity Compensation Plans
| | | | | | | |
| | Number of | | | | | Number of securities |
| | securities to | | | | | remaining |
| | be issued | | Weighted-average | | available for future | |
| | upon exercise | | exercise | | issuance under | |
| | of outstanding | | price of | | equity compensation | |
| | options, | | outstanding | | plans (excluding | |
| | warrants and | | Options, warrants | | securities reflected | |
Plan category |
| rights (a) |
| and rights (b) |
| in column (a))(1) | |
| | | | | | | |
Equity compensation plans approved by security holders: | | | | | | | |
Outstanding options | | — | | $ | — | | |
Outstanding contingent rights to shares | | 50,062 | (1) | | — | | |
Total | | 50,062 | | | — | | 1,804,275 |
Equity compensation plans not approved by security holders | | — | | | — | | — |
Total | | 50,062 | | $ | — | | 1,804,275 |
| Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | Weighted-average exercise price of outstanding Options, warrants and rights (b) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(1) | ||||||||
| Equity compensation plans approved by security holders: | |||||||||||
| Outstanding options | — | (1) | $ | — | |||||||
| Outstanding contingent rights to shares | 10,156 | (1) | — | ||||||||
| Total | 10,156 | $ | — | 852,111 | |||||||
| Equity compensation plans not approved by security holders | — | — | — | ||||||||
| Total | 10,156 | $ | — | 852,111 | |||||||
| (1) | In December 2016, we adopted the Equity Incentive Plan (the “2016 Plan”), which authorized the issuance of 1.1 million shares of common stock. On December 9, 2020, an amendment to the 2016 Plan was approved by our stockholders that increased the number of shares available for issuance by 2.5 million shares to a maximum of 3.6 million shares. As of June 30, |
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Issuer Purchases of Equity Securities
| Period | (a) Total Number of Shares (or Units) Purchased (1) (2) | (b) Average Price Paid per Share (or Units) | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs | |||
| April 1, 2019 to April 30, 2019 | None | Not applicable | Not applicable | $3.4 million | |||
| May 1, 2019 to May 31, 2019 | None | Not applicable | Not applicable | $3.4 million | |||
| June 1, 2019 to June 30, 2019 | 2,935 | $6.19 | 266,192 | $3.4 million | |||
During the fourth quarter ended June 30, 2019,2022, we did not purchase any common stock in the Company receivedopen market under the previously announced share repurchase program and no shares of common stock from certain of its employees which were surrendered in exchange forby our employees to pay their share of payroll tax liabilitiestaxes arising from vestingsvesting of restricted stock and contingent restricted stock. The acquisition cost per share reflects the weighted-average market price of the Company's shares on the dates vested.
Item 6. Reserved
29
| June 30, | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||
| Income Statement Data | |||||||||||||||||||
| Revenues | $ | 43,229,621 | $ | 40,773,527 | $ | 34,253,681 | $ | 26,349,502 | $ | 27,841,265 | |||||||||
| Cost of revenues | 14,266,784 | 11,685,817 | 10,604,594 | 9,133,111 | 9,355,613 | ||||||||||||||
| Depreciation, depletion, and amortization | 6,253,083 | 6,102,288 | 5,779,069 | 5,214,174 | 3,650,603 | ||||||||||||||
| General and administrative expense | 5,072,931 | 6,773,781 | 4,985,408 | 9,079,597 | 6,256,783 | ||||||||||||||
| Restructuring charges | — | — | 4,488 | 1,257,433 | (5,431 | ) | |||||||||||||
| Income from operations | 17,636,823 | 16,211,641 | 12,880,122 | 1,665,187 | 8,583,697 | ||||||||||||||
| Other income (expense) | 1,222,604 | (25,126 | ) | 4,855 | 32,565,954 | (147,619 | ) | ||||||||||||
| Income tax provision (benefit) | 3,482,361 | (3,431,969 | ) | 4,840,664 | 9,570,779 | 3,444,221 | |||||||||||||
| Net income attributable to the Company | $ | 15,377,066 | $ | 19,618,484 | $ | 8,044,313 | $ | 24,660,362 | $ | 4,991,857 | |||||||||
| Dividends on preferred stock | — | — | 250,990 | 674,302 | 674,302 | ||||||||||||||
| Deemed dividend on preferred shares called for redemption | — | — | 1,002,440 | — | — | ||||||||||||||
| Net income attributable to common shareholders | $ | 15,377,066 | $ | 19,618,484 | $ | 6,790,883 | $ | 23,986,060 | $ | 4,317,555 | |||||||||
| Earnings per common share: | |||||||||||||||||||
| Basic | $ | 0.46 | $ | 0.59 | $ | 0.21 | $ | 0.73 | $ | 0.13 | |||||||||
| Diluted | $ | 0.46 | $ | 0.59 | $ | 0.21 | $ | 0.73 | $ | 0.13 | |||||||||
| June 30, 2019 | June 30, 2018 | June 30, 2017 | June 30, 2016 | June 30, 2015 | |||||||||||||||
| Balance Sheet Data | |||||||||||||||||||
| Total current assets | $ | 35,178,927 | $ | 32,147,556 | $ | 26,142,527 | $ | 37,086,450 | $ | 23,693,048 | |||||||||
| Total assets | 95,761,844 | 93,662,544 | 88,268,668 | 97,451,051 | 69,882,727 | ||||||||||||||
| Total current liabilities | 2,752,694 | 4,430,214 | 2,718,894 | 8,528,908 | 9,329,257 | ||||||||||||||
| Total liabilities | 15,635,986 | 16,373,065 | 19,798,813 | 21,129,901 | 21,306,150 | ||||||||||||||
| Stockholders' equity | 80,125,858 | 77,289,479 | 68,469,855 | 76,321,150 | 48,576,577 | ||||||||||||||
| Number of common shares outstanding | 33,183,730 | 33,080,543 | 33,087,308 | 32,907,863 | 32,845,205 | ||||||||||||||
| Working capital, net | 32,426,233 | 27,717,342 | 23,423,633 | 28,557,542 | 14,363,791 | ||||||||||||||
| Cash dividends to common stockholders | 13,272,058 | 11,594,541 | 8,432,435 | 6,565,823 | 9,833,642 | ||||||||||||||
Item 7. Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
General
Evolution Petroleum Corporation is an oil and gasindependent energy company focused on delivering a sustainable dividend yieldmaximizing total returns to its stockholdersshareholders through the ownership managementof and development ofinvestment in onshore oil and natural gas properties. The Company'sproperties in the United States. In support of that objective, our long-term goal is to buildmaximize total shareholder return from a diversified portfolio of long-life oil and natural gas assets primarilyproperties built through acquisitions while seeking opportunities to maintain and increase production through selective development opportunities, production enhancementenhancements, and other exploitation efforts on itsour oil and natural gas properties.
Our producing assetsoil and natural gas properties consist of ournon-operated interests in the
Our non-operated interests in the Delhi Field, a past divestiture.
Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consists of approximately 24% average net working interest, with our stockholders.
Our non-operated interests in the Barnett Shale, a natural gas producing shale reservoir, consists of approximately 17% average net working interest with an associated 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties. The oil and previous CEO,natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by seven other operators.
On January 14, 2022, we acquired non-operated working interests in 73 producing wells in the Williston Basin with an average net working interest of approximately 39% and average net revenue interest of approximately 33% located on approximately 45,000 net acres (approximately 90% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota (the “Williston Basin Acquisition”). After taking into account customary closing adjustments and an effective date of June 1, 2021, cash consideration was appointed by the board$25.2 million which includes $0.3 million of transaction costs related to the positionacquisition. The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region.
30
On April 1, 2022, we acquired non-operated working interests in the Jonah Field in Sublette County, Wyoming (the “Jonah Field Acquisition”). After taking into account the deposit on the acquisition, customary closing adjustments and an effective date of February 1, 2022, cash consideration at closing was $26.4 million (including $0.2 million of transaction costs). The acquired properties include an average net working interest of approximately 20% and an average net revenue interest of approximately 15% in 595 producing wells and 950 net acres. The properties are operated by Jonah (“Jonah”), an established operator in the board was created with one member, William Dozier, to provide additional operational oversight togeographic region.
Recent Developments
Dividend Declaration and Share Repurchase Program
On September 12, 2022, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2022. This represents a 20% increase over the Company during$0.10 per common share dividend paid in the transition to a new CEO. On July 10, 2019, Mr. Jason Brown, age 42, was appointed byfourth quarter of fiscal year 2022. Also, on September 8, 2022, the Board of Directors authorized a share repurchase program, under which we are approved to serverepurchase up to $25 million of our common stock through December 31, 2024. We intend to fund repurchases from available working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as Presidentwell as the number and Chief Executive Officervalue of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the Company. Robert Herlin, remained as Chairmanintrinsic value of our shares, the Board.
Highlights for our 2019 Fiscal Year
| ● | Generated revenue of $108.9 million and net income of $32.6 million. |
● | Production averaged 5,953 net BOEPD. |
| ● | Returned to shareholders $11.8 million in cash dividends. We |
| ● | Funded all operations, development capital |
| ● | Closed the Jonah Field Acquisition on April 1, 2022 and the Williston Basin Acquisition on January 14, 2022, which included total proved reserves of 7.1 MMBOE and 6.1 MMBOE, respectively, as of June 30, |
| ● | Increased proved reserves 55% since prior year-end primarily due to the acquisitions of the Jonah Field properties in April 2022 and Williston Basin properties in January 2022. |
| ● | Maintained a strong financial position with |
Proved Reserves (based on SEC average NYMEX WTI oil price of $61.62 per barrel at June 30, 2019)
Proved oil equivalent reserves atas of June 30, 20192022 were 9.036.2 MMBOE,
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properties in realized commoditythe Williston Basin and Jonah Field and an increase in the SEC mandated trailing 12-month average first day of the month prices for oil and natural gas. Prices increased from $54.71$49.72 per barrel of oil, $2.46 per MMBtu of natural gas and $19.81 per barrel of NGLs at June 30, 2021 to $58.50$85.82 per BOE.barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs at June 30, 2022. Our proved reserves are 85% crudeconsist of 32% oil, and 15%49% natural gas, liquids, and of these proved reserves, 82%19% NGLs; 90% are classified as proved developed and producing and 18%10% are proved undeveloped.
The following table is a summary of our proved probable and possible reserves as of June 30, 20192022 and 2018:
| Proved | Probable | Possible | ||||||||||||||||||||||||||
| 2019 | 2018 | Change | 2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||||
| Reserves MMBOE | 9.0 | 9.4 | (4 | )% | 4.8 | 4.5 | 7 | % | 4.3 | 4.6 | (7 | )% | ||||||||||||||||
| % Developed | 82 | % | 78 | % | 5 | % | 87 | % | 80 | % | 9 | % | 91 | % | 88 | % | 3 | % | ||||||||||
| Liquids % | 100 | % | 100 | % | — | % | 100 | % | 100 | % | — | % | 100 | % | 100 | % | — | % | ||||||||||
| Standardized Measure ($MM) | $ | 127 | $ | 119 | 7 | % | ||||||||||||||||||||||
| PV-10* ($MM) | $ | 157 | $ | 146 | 8 | % | ||||||||||||||||||||||
| | | | | | | | | | | |
| | | | | | | | | | | |
| | Proved Reserves | | | | | |||||
|
| 2022 |
| | 2021 |
| | Change | |||
Reserves MMBOE | | | 36.2 | | | | 23.4 | | | 55 | % |
% Developed | | | 90 | % | | | 92 | % | | (2) | % |
Liquids % | | | 51 | % | | | 65 | % | | (14) | % |
Standardized Measure ($MM) | | $ | 314.8 | | | $ | 87.6 | | | 259 | % |
Additional property and project information is included under
Item 1. Business and in Note 5, “Property and Equipment” and our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial StatementsAt June 30, 2022, we had total net proved reserves of 36.2 MMBOE, a 12.8 MMBOE increase from the previous year of 23.4 MMBOE. The net increase in total proved reserves was the result of acquisitions of 9.3 MMBOE, additions and extensions of 3.6 MMBOE and net positive revisions of 2.1 MMBOE, partially offset by production of 2.2 MMBOE. Net positive revisions of 2.1 MMBOE increased primarily due to improvement in SEC trailing 12-month pricing partially offset by the removal of 1.8 MMBOE of PUDs related to Test Site V and 0.7 MMBOE of PDP at our Delhi Field
Impact of the COVID-19 Pandemic and Geopolitical factors
The global economy has been deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020.
In 2021, the demand for oil and natural gas began to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. In addition, the recent special military operation of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which has further enhanced volatility in global commodity prices in the Delhi field consistfirst half of 2022. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist.
Currently, none of our oil and natural gas properties are operated by us. As a result, in the past we have had limited ability to influence or control the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and alter plans as appropriate to increase shareholder value.
Liquidity and Capital Resources
As of June 30, 2022, we had $8.3 million in cash and cash equivalents compared to $5.3 million at June 30, 2021. Our primary sources of liquidity and capital resources during the year ended June 30, 2022 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the year ended June 30, 2022 were acquisitions of oil and natural gas properties and cash dividend payments to our common stockholders. As of June 30, 2022, working capital was $6.1 million, a decrease of $5.4 million from working capital of $11.5 million as of June 30, 2021.
32
The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the lender based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $50.0 million, with $21.3 million drawn as of June 30, 2022. Since year-end, we have paid down another $9.0 million under our Senior Secured Credit Facility and as of August 31, 2022, we have $12.3 million outstanding. The Senior Secured Credit Facility is secured by substantially all of our reserves associated with our oil and natural gas properties and matures on April 9, 2024.
Any future borrowings bear interest, at our option, at either the London Interbank Offered Rate (“LIBOR”) plus 2.75% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. It also contains other customary affirmative and negative covenants and events of default. As of June 30, 2022, we were in compliance with all covenants under the Senior Secured Credit Facility.
We are currently working on our annual redetermination with MidFirst Bank. We expect that our borrowing base will remain at $50.0 million and the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, will be set at $125.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. Based on the current amount outstanding, the utilization percentage under the required hedging covenant is below the minimum utilization threshold of 25% and as a result we are not required to enter into additional hedges at this time. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.
On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected oil and natural gas production over that period.
On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must hedge a certain amount of our future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the Ninth Amendment, as discussed above.
On August 5, 2021, we entered into the Seventh Amendment of our Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.
We have historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders. We expect to manage near-future development activities for our properties with cash flows from operating activities and existing working capital.
We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.
The Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 35 consecutive quarterly dividends. Distribution of a 23.9% working interest (with associated 19.0% net revenue interest)substantial portion of free cash flow in excess of operating and separate overriding royaltycapital requirements through cash dividends remains a priority of our financial strategy, and mineral interestsit is our long-term goal to increase
33
dividends over time, as appropriate. During the industry downturn primarily due to COVID-19, effective in the quarter ended June 30, 2020, the Board of 26.2%.Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025 per share. The Delhi field is operated by Denbury Onshore, LLC (the "operator"), a subsidiary 100% owned by Denbury Resources Inc. .
Also, on September 8, 2022, our Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. Refer to Note 15, “Subsequent Events,” for a further discussion of our share repurchase program.
Capital Expenditures
For the year ended June 30, 2022, we incurred $2.6 million on development capital expenditures, $26.4 million for the Jonah Field Acquisition (net of customary purchase price adjustments, excluding $3.0 million in non-cash asset retirement obligations), and $25.2 million for the Williston Basin Acquisition (net of customary purchase price adjustments, excluding $2.4 million in non-cash asset retirement obligations) and less than $0.1 million at the Delhi Field and Hamilton Dome Field, for plugging and abandoning costs.
Based on discussions with our operators, we expect capital workover projects to continue in all the fields. At Delhi Field, we anticipate capital costs for a NGL plant heat exchanger project which is currently underway. Overall, for fiscal year 2023, we expect budgeted capital expenditures to be in the range of $6.5 million to $9.5 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include Foundation, the operator of our Williston Basin properties, drilling two sidetrack locations targeting the Birdbear formation. Our fiscal year 2023 budget does not include any capital expenditures for drilling at our Pronghorn and Three Forks locations.
As of June 30, 2022, our PUD reserves included 3.6 MMBOE of reserves and approximately $61.7 million of future development costs associated with the Williston Basin properties.
Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, as well as borrowings under our Senior Secured Credit Facility as needed for future acquisitions or development of PUD reserves at our Pronghorn and Three Forks locations.
Full Cost Pool Ceiling Test
As of June 30, 2022, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if commodity price levels were to substantially decline. Lower commodity prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of June 30, 2022 were $85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs. At December 31, 2020 and September 30, 2020, we recorded ceiling test impairment charges of $15.2 million and $9.6 million, respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average price for oil used in the ceiling test calculation. At June 30, 2022, a PV-10* value10% decrease in commodity
34
prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties.
| | | | | | | | | | | | | | | |
| | Twelve-Month Period Ended: | |||||||||||||
|
| 6/30/2021 |
| 9/30/2021 |
| 12/31/2021 |
| 3/31/2022 |
| 6/30/2022 | |||||
Crude Oil | | $ | 49.72 | | $ | 57.64 | | $ | 66.55 | | $ | 75.28 | | $ | 85.82 |
Natural Gas | | $ | 2.46 | | $ | 2.97 | | $ | 3.64 | | $ | 4.15 | | $ | 5.19 |
Overview of Cash Flow Activities
| | | | | | | | | |
| | Years Ended June 30, | | | | ||||
|
| 2022 |
| 2021 |
| Change | |||
Cash flows provided by operating activities | | $ | 52,460 | | $ | 4,733 | | $ | 47,727 |
Cash flows used in investing activities | | | (54,873) | | | (18,769) | | | (36,104) |
Cash flows provided by (used in) financing activities | | | 5,416 | | | (349) | | | 5,765 |
Net increase (decrease) in cash and cash equivalents | | $ | 3,003 | | $ | (14,385) | | $ | 17,388 |
Cash provided by operating activities increased $47.7 million during the fiscal year ended June 30, 2022 compared to fiscal year ended June 30, 2021 primarily due to an increased average daily production and an approximate $13.26 per BOE average realized price increase which both contributed to higher revenues in fiscal year 2022.
Cash used in investing activities increased $36.1 million primarily due to the acquisition of the Jonah Field properties in April 2022 totaling $26.4 million (net of customary purchase price adjustments) and Williston Basin properties in January 2022 totaling $25.8 million (net of customary purchase price adjustments), compared to the prior year's 9.4 MMBOE with a Standardized Measure of $119 million and a PV-10* value of $146 million. Improved performance of producing wells has led to a 0.152 MMBOE, or 2%, positive revision in proved oil reserves. Performance from the NGL plant was improved via capitalized modifications resulting in a 0.199 MMBOE, or 16%, positive revision to NGL reserves. Probable reserve volumes at Delhi were 4.8 MMBOE, an increase of 7% compared to 4.5 MMBOE in the prior year. Possible reserves volumes at Delhi were 4.3 MMBOE, a decrease of 7% compared to 4.6 MMBOE in the prior year. The reclassification to probable from possible are primarily the result of timing and recent performance.
Net cash flows provided by Evolution during the fourth quarter of fiscal 2019 was $64.77 compared to $59.12 during the previous quarter. The average NGL price realized by Evolution during the fourth quarter of fiscal 2019 was $15.27 per barrel compared to $16.37 during the previous quarter. Evolution continues to benefit from the premium that Delhi field oil receives selling under Louisiana Light Sweet ("LLS") pricing, as compared to the more widely known West Texas Intermediate ("WTI") price, and the oil is shipped to market directly by pipeline, the most efficient means of transportation from the field. Our received NGL price for royalty production is burdened by a capital recovery charge, which is mostly offset by our working interest share of such capital recovery that is reflected as a reduction in lease operating expense.
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Years Ended June 30, 20192022 and 2018
We reported net income of $32.6 million for the year ended June 30, 2022 compared to a net loss of $16.4 million for the the prior fiscal year fiscal 2019 revenues increased 6.0% due to 6.9% higher realized commodity prices partially offset by a very slight decrease in production volumes.ended June 30, 2021. The following table summarizes total production volumes, daily production volumes, average realized prices and revenues:
| | | | | | | | | | | | |
| | Years Ended June 30, | | | | | | | ||||
(in thousands, except per unit and per BOE amounts) |
| 2022 |
| 2021 |
| Variance |
| Variance % | ||||
Net income (loss) | | $ | 32,628 | | $ | (16,438) | | $ | 49,066 | | (298.5) | % |
Revenues: | | | | | | | | | | | | |
Crude oil | | | 52,683 | | | 26,411 | | | 26,272 | | 99.5 | % |
Natural gas | | | 39,174 | | | 2,629 | | | 36,545 | | 1,390.1 | % |
Natural gas liquids | | | 17,069 | | | 3,662 | | | 13,407 | | 366.1 | % |
Total Revenue | | | 108,926 | | | 32,702 | | | 76,224 | | 233.1 | % |
Operating costs: | | | | | | | | | | | | |
Lease operating costs: | | | | | | | | | | | | |
CO2 costs | | | 7,708 | | | 3,062 | | | 4,646 | | 151.7 | % |
Ad valorem and production taxes | | | 6,960 | | | 1,280 | | | 5,680 | | 443.8 | % |
Other lease operating costs | | | 33,989 | | | 12,245 | | | 21,744 | | 177.6 | % |
Depletion, depreciation, and amortization: | | | | | | | | | | | | |
Depletion of full cost proved oil and gas properties | | | 7,518 | | | 4,903 | | | 2,615 | | 53.3 | % |
Depreciation of other property and equipment | | | 4 | | | 7 | | | (3) | | (42.9) | % |
Amortization of intangibles | | | — | | | 47 | | | (47) | | (100.0) | % |
Accretion of asset retirement obligations | | | 531 | | | 210 | | | 321 | | 152.9 | % |
Impairment of proved property | | | — | | | 24,792 | | | (24,792) | | (100.0) | % |
Impairment of Well Lift Inc. - related assets | | | — | | | 146 | | | (146) | | (100.0) | % |
General and administrative: | | | | | | | | | | | | |
General and administrative | | | 6,710 | | | 5,496 | | | 1,214 | | 22.1 | % |
Stock-based compensation | | | 125 | | | 1,258 | | | (1,133) | | (90.1) | % |
Other Income (expenses): | | | | | | | | | | | | |
Net gain (loss) on derivative contracts | | | (3,763) | | | (615) | | | (3,148) | | 511.9 | % |
Interest and other income | | | 95 | | | 40 | | | 55 | | 137.5 | % |
Interest expense | | | (572) | | | (103) | | | (469) | | 455.3 | % |
Income tax (expense) benefit | | | (8,513) | | | 4,984 | | | (13,497) | | (270.8) | % |
| | | | | | | | | | | | |
Production: | | | | | | | | | | | | |
Crude oil (MBBL) | | | 619 | | | 555 | | | 64 | | 11.5 | % |
Natural gas (MMCF) | | | 7,141 | | | 963 | | | 6,178 | | 641.5 | % |
Natural gas liquids (MBBL) | | | 364 | | | 171 | | | 193 | | 112.9 | % |
Equivalent (MBOE)(1) | | | 2,173 | | | 887 | | | 1,286 | | 145.0 | % |
Average daily production (BOEPD)(1) | | | 5,953 | | | 2,430 | | | 3,523 | | 145.0 | % |
| | | | | | | | | | | | |
Average price per unit(2): | | | | | | | | | | | | |
Crude oil (BBL) | | $ | 85.11 | | $ | 47.59 | | $ | 37.52 | | 78.8 | % |
Natural gas (MCF) | | | 5.49 | | | 2.73 | | | 2.76 | | 101.1 | % |
NGL (BBL) | | | 46.89 | | | 21.42 | | | 25.47 | | 118.9 | % |
Equivalent (BOE)(1) | | | 50.13 | | | 36.87 | | | 13.26 | | 36.0 | % |
| | | | | | | | | | | | |
Average cost per unit: | | | | | | | | | | | | |
Operating costs: | | | | | | | | | | | | |
Lease operating costs: | | | | | | | | | | | | |
CO2 costs | | $ | 3.55 | | $ | 3.45 | | | 0.10 | | 2.9 | % |
Ad valorem and production taxes | | | 3.20 | | | 1.44 | | | 1.76 | | 122.2 | % |
Other lease operating costs | | | 15.64 | | | 13.80 | | | 1.84 | | 13.3 | % |
Depletion of full cost proved oil and gas properties | | | 3.46 | | | 5.53 | | | (2.07) | | (37.4) | % |
General and administrative: | | | | | | | | | | | | |
General and administrative | | | 3.09 | | | 6.20 | | | (3.11) | | (50.2) | % |
Stock-based compensation | | | 0.06 | | | 1.42 | | | (1.36) | | (95.8) | % |
| Years Ended June 30, | ||||||||||||||
| 2019 | 2018 | Variance | Variance % | |||||||||||
| Oil and gas production | ||||||||||||||
| Crude oil revenues | $ | 40,779,052 | $ | 38,153,417 | $ | 2,625,635 | 6.9 | % | ||||||
| NGL revenues | 2,449,359 | 2,620,110 | (170,751 | ) | (6.5 | )% | ||||||||
| Natural gas revenues | 1,210 | — | 1,210 | n.m. | ||||||||||
| Total revenues | $ | 43,229,621 | $ | 40,773,527 | $ | 2,456,094 | 6.0 | % | ||||||
| Crude oil volumes (Bbl) | 626,879 | 651,931 | (25,052 | ) | (3.8 | )% | ||||||||
| NGL volumes (Bbl) | 112,013 | 93,366 | 18,647 | 20.0 | % | |||||||||
| Natural gas volumes (Mcf) | 459 | — | 459 | n.m. | ||||||||||
| Equivalent volumes (BOE) | 738,968 | 745,297 | (6,329 | ) | (0.8 | )% | ||||||||
| Crude oil (BOPD, net) | 1,717 | 1,786 | (69 | ) | (3.9 | )% | ||||||||
| NGLs (BOEPD, net) | 307 | 256 | 51 | 19.9 | % | |||||||||
| Natural gas (BOEPD, net) | 1 | — | 1 | n.m | ||||||||||
| Equivalent volumes (BOEPD, net) | 2,025 | 2,042 | (17 | ) | (0.8 | )% | ||||||||
| Crude oil price per Bbl | $ | 65.05 | $ | 58.52 | $ | 6.53 | 11.2 | % | ||||||
| NGL price per Bbl | 21.87 | 28.06 | (6.19 | ) | (22.1 | )% | ||||||||
| Natural gas price per Mcf | 2.64 | — | 2.64 | — | % | |||||||||
| Equivalent price per BOE | $ | 58.50 | $ | 54.71 | $ | 3.79 | 6.9 | % | ||||||
| (1) | Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil. |
| (2) | Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting. |
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Revenues
Fiscal year ended June 30, 2022 revenues increased 233.1% to $108.9 million compared to $32.7 million for the fiscal year ended June 30, 2021. The $2.6 million increase in production costs wasrevenue is primarily due to a 41%145% increase in average daily equivalent production from 2,430 BOEPD to 5,953 BOEPD due the addition of the Jonah Field Acquisition in April 2022, Williston Basin Acquisition in January 2022, and Barnett Shale Acquisition in May 2021, which increased current fiscal year production by approximately 518 BOEPD, 241 BOEPD, and 2,847 BOEPD, respectively. In addition, our average realized commodity prices (excluding the impact of derivative contracts) increased approximately $13.26 per BOE, or 36%, for the fiscal year ended June 30, 2022 compared to June 30, 2021. Oil and natural gas prices are inherently volatile and began to stabilize in 2021 and continuing into 2022. Our average realized oil price was higher primarily due to the recovery of WTI pricing in 2022, as the demand for oil has begun to recover primarily as a result of the roll-out of the COVID -19 vaccines, lessening of pandemic related government restrictions on individuals and businesses, and sanctions affecting Russian oil and natural gas supplies.
Lease Operating Costs
The following table summarizes CO2 costs per Mcf and CO2 volumes for the years ended June 30, 2022 and 2021. CO2 purchase costs together with 9% higher other production costs.
| Years Ended June 30, | ||||||||||||||
| 2019 | 2018 | Variance | Variance % | |||||||||||
CO2 costs (a) | $ | 6,674,905 | $ | 4,729,506 | $ | 1,945,399 | 41.1 | % | ||||||
| Other production costs | 7,591,879 | 6,956,311 | 635,568 | 9.1 | % | |||||||||
| Total production costs | $ | 14,266,784 | $ | 11,685,817 | $ | 2,580,967 | 22.1 | % | ||||||
CO2 costs per BOE | $ | 9.03 | $ | 6.35 | $ | 2.68 | 42.2 | % | ||||||
| All other production costs per BOE | 10.28 | 9.33 | 0.95 | 10.2 | % | |||||||||
| Production costs per BOE | $ | 19.31 | $ | 15.68 | $ | 3.63 | 23.2 | % | ||||||
| Years Ended June 30, | ||||||||||||||
| 2019 | 2018 | Variance | Variance % | |||||||||||
CO2 costs per mcf | $ | 0.90 | $ | 0.83 | $ | 0.07 | 8.4 | % | ||||||
CO2 volumes (MMcf per day, gross) | 85.2 | 65.0 | 20.2 | 31.1 | % | |||||||||
| | | | | | | | | | | | |
| | Years Ended June 30, | | | | | | | ||||
|
| 2022 | | 2021 |
| Variance |
| Variance % | ||||
CO2 costs per MCF | | $ | 1.07 | | $ | 0.71 | | $ | 0.36 | | 50.7 | % |
CO2 volumes (MMCF per day, gross) | | | 82.6 | | | 49.1 | | | 33.5 | | 68.2 | % |
The $1.9$4.6 million increase in CO
Ad valorem and production costs primarily consisted of higher costs of $0.3taxes were $7.0 million and $1.3 million for fuelthe years ended June 30, 2022 and 2021, respectively. On a per unit basis, ad valorem and production taxes were $3.20 per BOE and $1.44 per BOE for the years ended June 30, 2022 and 2021, respectively. The increase in ad valorem and production taxes is primarily due to increases in oil and natural gas expense, $0.2 million for labor,prices and $0.1 million for chemicals.
Compared to fiscal year ended June 30, 2021, other lease operating costs increased 177.6% primarily due to the same year-ago period principallyJonah Field Acquisition in April 2022, Williston Basin Acquisition in January 2022 and Barnett Shale Acquisition in May 2021. Other lease operating costs per BOE for our Jonah Field, Williston Basin and Barnett Shale properties were approximately $10.69 per BOE, $21.86 per BOE and $14.70 per BOE, respectively, for the years ended June 30, 2022. Other lease operating costs for the Delhi and Hamilton Dome fields increased $0.8 million and $0.9 million, respectively, due to a 3.4% higher oillabor, electricity and gas DD&A rate as production volumes were virtually unchangedchemical expenses during the year ended June 30, 2022.
Depletion expense increased $2.6 million or 53.3% from fiscal 2018.
| Years Ended June 30, | ||||||||||||||
| 2019 | 2018 | Variance | Variance % | |||||||||||
| DD&A of proved oil and gas properties | $ | 6,122,515 | $ | 5,980,307 | $ | 142,208 | 2.4 | % | ||||||
| Depreciation of other property and equipment | 15,498 | 18,127 | (2,629 | ) | (14.5 | )% | ||||||||
| Amortization of intangibles | 13,564 | 13,564 | — | — | % | |||||||||
| Accretion of asset retirement obligations | 101,506 | 90,290 | 11,216 | 12.4 | % | |||||||||
| Total DD&A | $ | 6,253,083 | $ | 6,102,288 | $ | 150,795 | 2.5 | % | ||||||
| Oil and gas DD&A rate per BOE | $ | 8.29 | $ | 8.02 | $ | 0.27 | 3.4 | % | ||||||
| Years Ended June 30, | ||||||||||||||
| 2019 | 2018 | Variance | Variance % | |||||||||||
| Enduro transaction breakup fee | 1,100,000 | — | 1,100,000 | n.m. | ||||||||||
| Interest and other income | 239,150 | 85,654 | 153,496 | 179.2 | % | |||||||||
| Interest expense | (116,546 | ) | (110,780 | ) | (5,766 | ) | 5.2 | % | ||||||
| Total other income, net | $ | 1,222,604 | $ | (25,126 | ) | $ | 1,247,730 | n.m. | ||||||
37
Impairment of Proved Property
We utilize the prior year primarily due to a non-recurring prior year deferred tax creditfull cost method of $6.0 million, partially offset by a $2.7 million, or 17% increase, in income before income taxes. This fiscal 2018 deferred tax benefit resulted from the revaluation ofaccounting for our deferred income tax liabilities at December 31, 2017 to reflect the lower federal statutory rateoil and natural gas properties under the Tax Cut and Jobs Act.
| Years Ended June 30, | ||||||||||||||
| 2019 | 2018 | Variance | Variance % | |||||||||||
| Income before income taxes | 18,859,427 | 16,186,515 | 2,672,912 | 16.5 | % | |||||||||
| Income tax provision (benefit) | 3,482,361 | (3,431,969 | ) | 6,914,330 | (201.5 | )% | ||||||||
| Net income available to common stockholders | $ | 15,377,066 | $ | 19,618,484 | $ | (4,241,418 | ) | (22.0 | )% | |||||
| Income tax provision as a percentage of income before income taxes | 19 | % | (37 | )% | ||||||||||
Impairment of Well Lift Inc. - Related Expenses
Our royalty rights and investment in Well Lift, Inc. (“WLI”) resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated with the technology. We own approximately 18% of the common stock and 100% of the preferred stock of WLI and account for our investment in this private company at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer, if such were to occur. We evaluate the investment for impairment when we identify any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. As of March 31, 2021, we reviewed our investment in WLI for potential impairment and, as a result, recorded an impairment expense of $0.1 million. This impairment charge was recorded based on a variety of factors including the level of activity associated with this technology.
General and Administrative Expenses
General and administrative expenses for the fiscal year ended June 30, 2022 increased $1.2 million, or 22.1%, to $6.7 million compared to $5.5 million for the fiscal year ended June 30, 2021. The increase is primarily due to approximately $0.2 million for salary and employee benefits due to additional personnel, $0.3 million in severance, $0.2 million for professional fees related to increased accounting services as a result of the Jonah Field Acquisition, the Williston Basin Acquisition and the Barnett Shale Acquisition, and $0.3 million for increased business development activity. On a per unit basis, general and administrative expenses decreased $3.11 per BOE to $3.09 per BOE for the year ended June 30, 2019,2022 from $6.20 per BOE for the prior year. The decrease in general and administrative expenses on a per unit basis are due to the increased production volumes described above.
Stock-based Compensation Expenses
Stock-based compensation decreased $1.1 million, or 90%, to $0.1 million for the year ended June 30, 2022 compared to $1.3 million the prior period due to a $1.2 million reduction in current period expense related to the forfeiture of unvested shares in connection with severance.
Net Gain (Loss) on Derivative Contracts
Periodically, we fundedutilize commodity derivative financial instruments to reduce our operations, capital expenditures and cash dividends with cash generated from operations resultingexposure to fluctuations in an increase of $3.9 million in cash. As of June 30, 2019, our working capital was $32.4 million, an increase of $4.7 million over working capital of $27.7 million at June 30, 2018.
38
remaining hedges. Certain of our hedges begin to expire in the eastern portionOctober 2022 with our final hedges expiring March 2023. As of the field, and $1.8 million for the infill drilling program.
| | | | | | | | | | | | |
| | Years Ended June 30, | | | | | | | ||||
(in thousands, except per unit and per BOE amounts) |
| 2022 |
| 2021 |
| Variance |
| Variance % | ||||
Realized gain (loss) on derivative contracts | | $ | (1,769) | | $ | (2,526) | | $ | 757 | | (30.0) | % |
Unrealized gain (loss) on derivative contracts | | | (1,994) | | | 1,911 | | | (3,905) | | (204.3) | % |
Total net gain (loss) on derivative contracts | | $ | (3,763) | | $ | (615) | | $ | (3,148) | | 511.9 | % |
| | | | | | | | | | | | |
Average realized crude oil price per Bbl | | $ | 85.11 | | $ | 47.59 | | $ | 37.52 | | 78.8 | % |
Cash effect of oil derivative contracts per Bbl | | | (1.24) | | | (4.55) | | | 3.31 | | (72.7) | % |
Crude oil price per Bbl (including impact of realized derivatives) | | $ | 83.87 | | $ | 43.04 | | $ | 40.83 | | 94.9 | % |
| | | | | | | | | | | | |
Average realized natural gas price per Mcf | | $ | 5.49 | | $ | 2.73 | | $ | 2.76 | | 101.1 | % |
Cash effect of natural gas derivative contracts per Mcf | | | (0.14) | | | — | | | (0.14) | | — | % |
Natural gas price per Mcf (including impact of realized derivatives) | | $ | 5.35 | | $ | 2.73 | | $ | 2.62 | | 96.0 | % |
Interest Expense
Interest expense increased $0.5 million during the eastern portion of the field. Such development requires participation by both the operator and Evolution, and the operator has not yet finalized its capital expenditure budget for 2020. Based our discussions with the operator, in fiscal 2020, we expect to spend about $0.6 million to complete the south water curtain in preparation for the Phase V development, which is expected to commence late in fiscal 2020. In our last three fiscal years we have incurred a total of $3.1 million on the water curtain program in advance of this development. The timing of Phase V is also dependent, in part, on the field operator's available funds and capital spending plans and priorities within its portfolio of properties.
| June 30, | |||||||||||
| Increases (Decreases) in Cash: | 2019 | 2018 | Difference | ||||||||
| (In Millions) | |||||||||||
| Net cash provided by operating activities | $ | 24.1 | $ | 20.5 | $ | 3.6 | |||||
| Net cash used in investing activities | (6.8 | ) | (3.7 | ) | (3.1 | ) | |||||
| Net cash used in financing activities | (13.4 | ) | (12.2 | ) | (1.2 | ) | |||||
| Change in cash, cash equivalents and restricted cash | $ | 3.9 | $ | 4.6 | $ | (0.7 | ) | ||||
Income tax (expense) provision
For the year increased $3.6ended June 30, 2022, we recognized income tax expense of $8.5 million on net income before income taxes of $41.1 million compared to the fiscal 2018 due to a $5.8 million increase in cash provided by non-cash expenses and $2.1 million increase in cash provided from current operating assets and liabilities partially offset by a $4.3 million decrease in cash provided by net income. Fiscal 2018 total non-cash expenses were impacted by the one-time $6.0 million deferredan income tax credit related to enactmentbenefit of $5.0 million on net loss before income taxes of $21.4 million for the Tax Cut and Jobs Act.
| Payments Due by Period | |||||||||||||||||||
| Total | Less than 1 Year | 1 - 3 Years | 3 - 5 Years | More than 5 Years | |||||||||||||||
| Contractual Obligations | |||||||||||||||||||
| Purchase commitments in connection with joint interest agreement | $ | 861,674 | $ | 861,674 | $ | — | $ | — | $ | — | |||||||||
| Operating lease | 182,208 | 34,322 | 147,886 | — | — | ||||||||||||||
| Other Obligations | |||||||||||||||||||
| Asset retirement obligations | 1,610,845 | 50,244 | — | — | 1,560,601 | ||||||||||||||
| Total Obligations | $ | 2,654,727 | $ | 946,240 | $ | 147,886 | $ | — | $ | 1,560,601 | |||||||||
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, and liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our consolidated financial statements. Our significant accounting policies are included in
Oil and Natural Gas Properties
. Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and natural gas industry. We apply the full cost accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful39
Estimates of Proved Reserves. The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis infor determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex requiringand requires significant decisions in the evaluation of all available geological,geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, includinginformation; this includes reservoir performance, additional development activity, new geologicalgeologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third-party independent engineers represent the most
On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and natural gas reserves. The rule allows consideration of new technologies in evaluating reserves, generally limits the designation of proved reserves to those projects forecastforecasted to be drilled five years from the initial recognition date of such reserves, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and natural gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the disclosure requirements for oil and natural gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.
Valuation of Deferred Tax Assets.
We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred taxManagement considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making the assessment of the ultimate realization of deferred tax assets. BasedThe Company has historically established a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods, based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible, asdeductible. At the time of end of the current fiscal year,this report, we believe that it is more likely thanhave not that the Company willrecorded a valuation allowance for our expected inability to realize the future benefits of its net deferred tax assets. If our estimatescertain federal and judgments change regarding our ability to utilize ourstate deferred tax assets our tax provision would increaseas further discussed in the period it is determined that recovery is not probable.
Stock-based Compensation
. The fair value, and for certain awards the expected vesting period, of40
group of other companies in our industry with comparable market capitalizations and, for certain awards, the Company'sour share price attaining a set target.
Recent Accounting Pronouncements
.Item 7A. Quantitative and Qualitative Disclosures About Market Risks
Derivative Instruments and Hedging Activity
We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices. We do not enter into derivative contracts for speculative trading purposes.
We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2022 and 2021, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 8, “Derivatives” to our consolidated financial statements for more details.
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either LIBOR plus 2.75%, subject to a minimum LIBOR of 0.25%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. LIBOR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
41
Item 8. Consolidated Financial Statements
Index to Consolidated Financial Statements
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| (PCAOB ID No. 659) | 43 | |
| 46 | |
| 47 | |
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42
To the Shareholders and the Board of Directors and Stockholders
Evolution Petroleum Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and Subsidiariessubsidiaries (the “Company”) as of June 30, 20192022 and 2018,2021, the related consolidated statements of operations, cash flows, and changes in stockholders’ equity for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of June 30, 20192022 and 2018,2021, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOBPublic Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditsaudit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Natural Gas Reserves on Depletion, Depreciation and Amortization (“DD&A”) and Full Cost Ceiling Test Impairment Calculation (“Ceiling Test”)
As described in Note 1, the Company follows the full cost method of accounting, pursuant to which oil and natural gas properties are amortized using the unit-of-production method over total proved reserves. The Company’s proved oil and natural gas properties are evaluated for impairment by the Ceiling Test, utilizing the Company’s proved oil and natural gas reserves in accordance with accounting principles generally accepted in the United States of America and SEC
43
guidelines. For the year ended June 30, 2022, the Company recorded DD&A related to its proved oil and natural gas properties of approximately $7.5 million, and there was no ceiling test impairment.
The Company engages two independent reservoir engineering firms, to serve as a management specialist and to assist with the estimation of proved oil and natural gas reserves. To estimate the volume of proved oil and natural gas reserves and associated future net cash flows, management and their specialists make significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties (“PUDs”). The estimation of proved oil and natural gas reserves is impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required. Changes in significant assumptions or engineering data could have a significant impact on the amount of DD&A and impairment recorded for the Company’s proved oil and natural gas properties.
We identified the impact of proved oil and natural gas reserves on DD&A and the Ceiling Test as a critical audit matter due to use of significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the significant assumptions used in developing those estimates of proved oil and natural gas reserves.
The primary procedures we performed to address this critical audit matter included:
| ● | Evaluating the knowledge, skill, and ability of the Company's third-party reservoir engineering specialists and their relationship to the Company, inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the proved reserve volumes, and reading the reserve report prepared by the reservoir engineering specialists. |
| ● | Evaluating significant assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserves, including pricing differentials, future operations costs, future production rates and capital expenditures. The procedures performed included tests of the data inputs used by specialists for completeness and accuracy and an evaluation of the specialist’s findings. The procedures performed included: |
| o | Testing the data inputs used by specialist for completeness and accuracy; |
| o | Testing the specialist’s findings for mathematical accuracy; and, |
| o | Performing analytical procedures on pricing, reserve quantities and cost estimates developed by management and its specialists. Those procedures entailed comparisons of: |
| ◾ | prices to historical benchmark prices, adjusted for pricing differentials, |
| ◾ | production forecasts to recent historical actual production, |
| ◾ | projections of lease operating costs to costs incurred by property during fiscal year ended June 30, 2022, and |
| ◾ | projected production taxes to recent historical taxes incurred and to statutory tax rates. |
| ● | Evaluating the accuracy of revenue and working interest percentages used in the reserve reports by comparing a sample of such interests to the land records. |
| ● | Performing retrospective review of historical estimates of proved oil and natural gas reserves to identify potential management bias in estimates. |
44
Testing the accuracy of the Company’s depletion and impairment calculations that included these proved reserves.
| |
/s/ Moss Adams LLP | |
| |
Houston, Texas | |
September 14, 2022 | |
We have served as the Company’s auditor since 2017.
45
EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and Subsidiaries
| June 30, 2019 | June 30, 2018 | ||||||
| Assets | |||||||
| Current assets | |||||||
| Cash and cash equivalents | $ | 31,552,533 | $ | 24,929,844 | |||
| Restricted cash | — | 2,751,289 | |||||
| Receivables | 3,168,116 | 3,941,916 | |||||
| Prepaid expenses and other current assets | 458,278 | 524,507 | |||||
| Total current assets | 35,178,927 | 32,147,556 | |||||
| Property and equipment, net of depreciation, depletion, and amortization | |||||||
| Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization | 60,346,466 | 61,239,746 | |||||
| Other property and equipment, net | 26,418 | 30,407 | |||||
| Total property and equipment, net | 60,372,884 | 61,270,153 | |||||
| Other assets, net | 210,033 | 244,835 | |||||
| Total assets | $ | 95,761,844 | $ | 93,662,544 | |||
| Liabilities and Stockholders' Equity | |||||||
| Current liabilities | |||||||
| Accounts payable | $ | 2,084,140 | $ | 3,432,568 | |||
| Accrued liabilities and other | 537,755 | 874,886 | |||||
| State and federal taxes payable | 130,799 | 122,760 | |||||
| Total current liabilities | 2,752,694 | 4,430,214 | |||||
| Long term liabilities | |||||||
| Deferred income taxes | 11,322,691 | 10,555,435 | |||||
| Asset retirement obligations | 1,560,601 | 1,387,416 | |||||
| Total liabilities | 15,635,986 | 16,373,065 | |||||
| Commitments and contingencies (Note 16) | |||||||
| Stockholders' equity | |||||||
| Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,183,730 and 33,080,543 shares as of June 30, 2019 and 2018, respectively | 33,183 | 33,080 | |||||
| Additional paid-in capital | 42,488,913 | 41,757,645 | |||||
| Retained earnings | 37,603,762 | 35,498,754 | |||||
| Total stockholders' equity | 80,125,858 | 77,289,479 | |||||
| Total liabilities and stockholders' equity | $ | 95,761,844 | $ | 93,662,544 | |||
| | | | | | |
|
| June 30, 2022 |
| June 30, 2021 | ||
Assets | | |
| | |
|
Current assets | | |
| | |
|
Cash and cash equivalents | | $ | 8,280 | | $ | 5,277 |
Receivables from crude oil, natural gas, and natural gas liquids sales | | | 24,080 | | | 8,687 |
Receivables for federal and state income tax refunds | | | — | | | 3,108 |
Derivative contract assets | | | 170 | | | — |
Prepaid expenses and other current assets | | | 3,838 | | | 1,036 |
Total current assets | | | 36,368 | | | 18,108 |
Property and equipment, net of depletion, depreciation, amortization, and impairment | | |
| | | |
Oil and natural gas properties, net—full-cost method of accounting, of | | | | | | |
which none were excluded from amortization | | | 110,508 | | | 58,516 |
Other property and equipment, net | | | — | | | 11 |
Total property and equipment, net | | | 110,508 | | | 58,527 |
Other assets, net | | | 1,171 | | | 71 |
Total assets | | $ | 148,047 | | $ | 76,706 |
Liabilities and Stockholders' Equity | | |
| | | |
Current liabilities | | |
| | | |
Accounts payable | | $ | 15,133 | | $ | 1,613 |
Accrued liabilities and other | | | 11,893 | | | 4,943 |
Derivative contract liabilities | | | 2,164 | | | — |
State and federal taxes payable | | | 1,095 | | | 38 |
Total current liabilities | | | 30,285 | | | 6,594 |
Long term liabilities | | |
| | | |
Senior secured credit facility | | | 21,250 | | | 4,000 |
Deferred income taxes | | | 7,099 | | | 5,957 |
Asset retirement obligations | | | 13,899 | | | 5,539 |
Operating lease liability | | | — | | | 21 |
Total liabilities | | | 72,533 | | | 22,111 |
Commitments and contingencies (Note 11) | | | | | | |
Stockholders' equity | | |
| | | |
Common stock; par value $0.001; 100,000,000 shares authorized: issued and | | | | | | |
outstanding 33,470,710 and 33,514,952 shares as of June 30, 2022 and 2021, | | | | | | |
respectively | | | 33 | | | 34 |
Additional paid-in capital | | | 42,629 | | | 42,541 |
Retained earnings | | | 32,852 | | | 12,020 |
Total stockholders' equity | | | 75,514 | | | 54,595 |
Total liabilities and stockholders' equity | | $ | 148,047 | | $ | 76,706 |
See accompanying notes to consolidated financial statements.
46
| Years Ended June 30, | |||||||
| 2019 | 2018 | ||||||
| Revenues | |||||||
| Crude oil | $ | 40,779,052 | $ | 38,153,417 | |||
| Natural gas liquids | 2,449,359 | 2,620,110 | |||||
| Natural gas | 1,210 | — | |||||
| Total revenues | 43,229,621 | 40,773,527 | |||||
| Operating costs | |||||||
| Production costs | 14,266,784 | 11,685,817 | |||||
| Depreciation, depletion and amortization | 6,253,083 | 6,102,288 | |||||
| General and administrative expenses* | 5,072,931 | 6,773,781 | |||||
| Total operating costs | 25,592,798 | 24,561,886 | |||||
| Income from operations | 17,636,823 | 16,211,641 | |||||
| Other | |||||||
| Enduro transaction breakup fee | 1,100,000 | — | |||||
| Interest and other income | 239,150 | 85,654 | |||||
| Interest (expense) | (116,546 | ) | (110,780 | ) | |||
| Income before income tax provision | 18,859,427 | 16,186,515 | |||||
| Income tax provision (benefit) | 3,482,361 | (3,431,969 | ) | ||||
| Net income attributable to common shareholders | $ | 15,377,066 | $ | 19,618,484 | |||
| Earnings per common share | |||||||
| Basic | $ | 0.46 | $ | 0.59 | |||
| Diluted | $ | 0.46 | $ | 0.59 | |||
| Weighted average number of common shares outstanding | |||||||
| Basic | 33,160,283 | 33,126,469 | |||||
| Diluted | 33,169,718 | 33,178,535 | |||||
EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
| | | | | | |
| | Years Ended June 30, | ||||
|
| 2022 |
| 2021 | ||
Revenues | | | | | | |
Crude oil | | $ | 52,683 | | $ | 26,411 |
Natural gas | | | 39,174 | | | 2,629 |
Natural gas liquids | | | 17,069 | | | 3,662 |
Total revenues | | | 108,926 | | | 32,702 |
Operating costs | | | | | |
|
Lease operating costs | | | 48,657 | | | 16,587 |
Depletion, depreciation, and amortization | | | 8,053 | | | 5,167 |
Impairment of proved property | | | — | | | 24,792 |
Impairment of Well Lift Inc. - related assets | | | — | | | 146 |
General and administrative expenses | | | 6,835 | | | 6,754 |
Total operating costs | | | 63,545 | | | 53,446 |
Income (loss) from operations | | | 45,381 | | | (20,744) |
Other income and expenses | | | | | |
|
Net gain (loss) on derivative contracts | | | (3,763) | | | (615) |
Interest and other income | | | 95 | | | 40 |
Interest expense | | | (572) | | | (103) |
Income (loss) before income taxes | | | 41,141 | | | (21,422) |
Income tax (expense) benefit | | | (8,513) | | | 4,984 |
Net income (loss) | | $ | 32,628 | | $ | (16,438) |
Earnings (loss) per common share: | | |
| | |
|
Basic | | $ | 0.97 | | $ | (0.50) |
Diluted | | $ | 0.96 | | $ | (0.50) |
Weighted average number of common shares outstanding | | |
| | |
|
Basic | | | 32,952 | | | 32,744 |
Diluted | | | 33,306 | | | 32,744 |
See accompanying notes to consolidated financial statements.
47
| Years Ended June 30, | |||||||
| 2019 | 2018 | ||||||
| Cash flows from operating activities | |||||||
| Net income attributable to the Company | $ | 15,377,066 | $ | 19,618,484 | |||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
| Depreciation, depletion and amortization | 6,268,239 | 6,158,555 | |||||
| Stock-based compensation | 888,162 | 1,366,764 | |||||
| Deferred income taxes | 767,256 | (5,270,856 | ) | ||||
| Changes in operating assets and liabilities: | |||||||
| Receivables | 773,800 | (1,215,214 | ) | ||||
| Prepaid expenses and other current assets | 66,229 | (136,835 | ) | ||||
| Accounts payable and accrued expenses | (90,891 | ) | (107,081 | ) | |||
| Income taxes payable | 8,039 | 122,760 | |||||
| Net cash provided by operating activities | 24,057,900 | 20,536,577 | |||||
| Cash flows from investing activities | |||||||
| Development of oil and natural gas properties | (6,746,142 | ) | (3,690,845 | ) | |||
| Capital expenditures for other property and equipment | (11,509 | ) | (7,846 | ) | |||
| Other assets | — | (19,282 | ) | ||||
| Net cash used by investing activities | (6,757,651 | ) | (3,717,973 | ) | |||
| Cash flows from financing activities | |||||||
| Common share repurchases, including shares surrendered for tax withholding | (156,791 | ) | (571,083 | ) | |||
| Common stock dividends paid | (13,272,058 | ) | (11,594,541 | ) | |||
| Net cash provided by (used in) financing activities | (13,428,849 | ) | (12,165,624 | ) | |||
| Net increase in cash, cash equivalents and restricted cash | 3,871,400 | 4,652,980 | |||||
| Cash, cash equivalents and restricted cash, beginning of year | 27,681,133 | 23,028,153 | |||||
| Cash, cash equivalents and restricted cash, end of year | $ | 31,552,533 | $ | 27,681,133 | |||
| Years Ended June 30, | |||||||
| 2019 | 2018 | ||||||
| Cash and cash equivalents | $ | 31,552,533 | $ | 24,929,844 | |||
| Restricted cash included in current assets | — | 2,751,289 | |||||
| Total cash, cash equivalents and restricted cash shown in the statements of cash flows | $ | 31,552,533 | $ | 27,681,133 | |||
EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| | | | | | |
| | Years Ended June 30, | ||||
|
| 2022 |
| 2021 | ||
Cash flows from operating activities: | | |
| | |
|
Net income (loss) | | $ | 32,628 | | $ | (16,438) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | |
| | | |
Depletion, depreciation, and amortization | | | 8,053 | | | 5,167 |
Impairment of proved property | | | — | | | 24,792 |
Impairment of Well Lift Inc. - related assets | | | — | | | 146 |
Stock-based compensation | | | 125 | | | 1,258 |
Settlement of asset retirement obligations | | | — | | | (101) |
Deferred income taxes | | | 1,142 | | | (5,104) |
Unrealized loss on derivative contracts | | | 1,994 | | | 615 |
Accrued settlements on derivative contracts | | | 919 | | | (2,791) |
Other | | | (10) | | | 10 |
Changes in operating assets and liabilities: | | |
| | | |
Receivables | | | (11,427) | | | (6,632) |
Prepaid expenses and other current assets | | | (538) | | | (546) |
Accounts payable and accrued expenses | | | 18,516 | | | 4,498 |
State and federal income taxes payable | | | 1,058 | | | (141) |
Net cash provided by operating activities | | | 52,460 | | | 4,733 |
Cash flows from investing activities: | | | | | | |
Acquisition of oil and natural gas properties | | | (53,342) | | | (18,297) |
Capital expenditures for oil and natural gas properties | | | (1,531) | | | (472) |
Net cash used in investing activities | | | (54,873) | | | (18,769) |
Cash flows from financing activities: | | |
| | |
|
Common stock dividends paid | | | (11,796) | | | (4,342) |
Common stock repurchases, including stock surrendered for tax withholding | | | (38) | | | (7) |
Borrowings under credit facility | | | 34,000 | | | 7,000 |
Repayments of credit facility | | | (16,750) | | | (3,000) |
Net cash provided by (used in) financing activities | | | 5,416 | | | (349) |
Net increase (decrease) in cash and cash equivalents | | | 3,003 | | | (14,385) |
Cash and cash equivalents, beginning of year | | | 5,277 | | | 19,662 |
Cash and cash equivalents, end of year | | $ | 8,280 | | $ | 5,277 |
| | | | | | |
Supplemental disclosures of cash flow information: | | | | | | |
Cash paid for interest on Senior secured credit facility | | $ | 523 | | $ | 86 |
Cash paid for income taxes | | | 6,294 | | | 758 |
Cash received from income tax refunds | | | 3,223 | | | 142 |
Non-cash investing and financing transactions: | | | | | | |
Increase (decrease) in accrued purchases of property and equipment | | | 1,094 | | | (80) |
Oil and natural gas property costs attributable to the recognition of asset retirement obligations | | | 7,807 | | | 2,883 |
See accompanying notes to consolidated financial statements.
48
| Common Stock | ||||||||||||||||||||||
Additional Paid-in Capital | Retained Earnings | Treasury Stock | Total Stockholders' Equity | |||||||||||||||||||
| Shares | Par Value | |||||||||||||||||||||
| Balance, June 30, 2017 | 33,087,308 | $ | 33,087 | $ | 40,961,957 | $ | 27,474,811 | $ | — | $ | 68,469,855 | |||||||||||
| Issuance of restricted common stock | 183,537 | 183 | (183 | ) | — | — | — | |||||||||||||||
| Forfeitures of restricted stock | (117,094 | ) | (117 | ) | 117 | — | — | — | ||||||||||||||
| Common share repurchases, including shares surrendered for tax withholding | (73,208 | ) | — | — | — | (571,083 | ) | (571,083 | ) | |||||||||||||
| Retirements of treasury stock | — | (73 | ) | (571,010 | ) | — | 571,083 | — | ||||||||||||||
| Stock-based compensation | — | — | 1,366,764 | — | — | 1,366,764 | ||||||||||||||||
| Net income attributable to the Company | — | — | — | 19,618,484 | — | 19,618,484 | ||||||||||||||||
| Common stock cash dividends | — | — | — | (11,594,541 | ) | — | (11,594,541 | ) | ||||||||||||||
| Balance, June 30, 2018 | 33,080,543 | 33,080 | 41,757,645 | 35,498,754 | — | 77,289,479 | ||||||||||||||||
| Issuance of restricted common stock | 121,611 | 122 | (122 | ) | — | — | — | |||||||||||||||
| Common share repurchases, including shares surrendered for tax withholding | (18,424 | ) | — | — | — | (156,791 | ) | (156,791 | ) | |||||||||||||
| Retirements of treasury stock | — | (19 | ) | (156,772 | ) | — | 156,791 | — | ||||||||||||||
| Stock-based compensation | — | — | 888,162 | — | — | 888,162 | ||||||||||||||||
| Net income attributable to the Company | — | — | — | 15,377,066 | — | 15,377,066 | ||||||||||||||||
| Common stock cash dividends | — | — | — | (13,272,058 | ) | — | (13,272,058 | ) | ||||||||||||||
| Balance, June 30, 2019 | 33,183,730 | $ | 33,183 | $ | 42,488,913 | $ | 37,603,762 | $ | — | $ | 80,125,858 | |||||||||||
EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(In thousands)
| | | | | | | | | | | | | | | | | |
| | | | | | | Additional | | |
| | |
| | Total | ||
| | Common Stock | | Paid-in | | Retained | | Treasury | | Stockholders' | |||||||
|
| Shares |
| Par Value |
| Capital |
| Earnings |
| Stock |
| Equity | |||||
Balances at June 30, 2020 | | 32,957 | | $ | 33 | | $ | 41,291 | | $ | 32,800 | | $ | — | | $ | 74,124 |
Issuance of restricted common stock | | 561 | | | 1 | | | (1) | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | (7) | | | (7) |
Retirements of treasury stock | | (3) | | | — | | | (7) | | | — | | | 7 | | | — |
Stock-based compensation | | — | | | — | | | 1,258 | | | — | | | — | | | 1,258 |
Net income (loss) | | — | | | — | | | — | | | (16,438) | | | — | | | (16,438) |
Common stock dividends paid | | — | | | — | | | — | | | (4,342) | | | — | | | (4,342) |
Balances at June 30, 2021 | | 33,515 | | | 34 | | | 42,541 | | | 12,020 | | | — | | | 54,595 |
Issuance of restricted common stock | | 336 | | | — | | | — | | | — | | | — | | | — |
Forfeitures of restricted stock | | (373) | | | (1) | | | 1 | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | (38) | | | (38) |
Retirements of treasury stock | | (7) | | | — | | | (38) | | | — | | | 38 | | | — |
Stock-based compensation | | — | | | — | | | 125 | | | — | | | — | | | 125 |
Net income (loss) | | — | | | — | | | — | | | 32,628 | | | — | | | 32,628 |
Common stock dividends paid | | — | | | — | | | — | | | (11,796) | | | — | | | (11,796) |
Balances at June 30, 2022 | | 33,471 | | $ | 33 | | $ | 42,629 | | $ | 32,852 | | $ | — | | $ | 75,514 |
See accompanying notes to consolidated financial statements.
49
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Organization1. Summary of Significant Events and Basis of Preparation
Nature of Operations.
Evolution Petroleum Corporation is anThe Company’s producing properties consist of non-operated interests in the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO
2 enhanced oil recoveryPrinciples of Consolidation and Reporting.
Risk and Uncertainties. None of the Company’s ownership interests are operated by the Company and involve other third-party working interest owners. As a result, the Company has a limited ability to influence or control the operation or future development of such properties. However, the Company is proactive with its third-party operators to review spending and alter plans as appropriate.
Use of Estimates.
The preparation of financial statements in conformity withCash and Cash Equivalents.
Accounts Receivable and Allowance for Doubtful Accounts.
Accounts receivable consist of accrued hydrocarbon revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items.50
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 20192022 and 2018,2021, no allowance for doubtful accounts was considered necessary.
Oil and Natural Gas Properties.
The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of depletion, estimated future development costs, and asset retirement costs (net of salvage values) not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves.
The capitalized costs of the Company’s oil and natural gas properties, net of accumulated amortization and related deferred income taxes are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. Any excess over the full cost ceiling limitation is charged to expense as an impairment and is reflected as additional accumulated depletion, depreciation, and amortization or as a credit to oil and natural gas properties.
Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costsdepletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologicalgeologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. We exclude theseThese costs are excluded until the project is evaluated and proved reserves are established or impairment is determined. ExcludedAs of June 30, 2022 and 2021, the Company did not have any costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized.
Other Property and Equipment.
Other property and equipment includes building leasehold improvements, data processing and telecommunications equipment, office furniture, and office equipment. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to sevenAsset Retirement Obligations.
An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is recognized as a liability in the periodFair Value of Financial Instruments.
51
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Senior Secured Credit Facility, as defined in Note 6, “Senior Secured Credit Facility,” are market interest rates. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and natural gas, discount rates, and volatility factors.
Concentrations of Credit Risk. The Company’s primary concentrations of credit risk are the fair valuerisks of stock-based compensation awards onuncollectible accounts receivable, and to a lesser extent, the grant date to providenon-performance by counterparties under the basis for future compensation expense. Service-basedCompany’s derivative contracts, and performance-based Restricted Stockcash and Contingent Restricted Stock awards are valued usingcash equivalent balances in excess of limits federally insured by the market price of our common stock on the grant date. Market-based awards are valued using a Monte Carlo simulation and geometric Brownian motion techniques applied to the historical volatilityFederal Deposit Insurance Corporation.
Substantially all of the Company's total stock return compared to the historical volatilitiesCompany’s accounts receivable as of other companies or indices to which we compare our performance. This Monte Carlo simulation also provides an expected vesting period. For service-based awards, stock-based compensationJune 30, 2022 is recognized ratably over the service period. For performance-based awards, stock based compensation is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be shorter than the remaining term. For market-based awards, stock-based compensation expense is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service.
Derivative Instruments. The Company follows Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging (“ASC 815”). From time to time, in accordance with the Company’s policy and the covenants under the Senior Secured Credit Facility, it may hedge a portion of its forecasted crude oil, natural gas, and NGL production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”); the agreement provides for net settlement over the term of DD&A,the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.
Estimates of Proved Reserves. The estimated future development costs and asset retirement costs (netquantities of salvage values) not included inproved oil and natural gas properties, less costs excluded from amortization.reserves have a significant impact on the underlying financial statements. The depreciable baseestimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by the Company’s third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties is amortized usingmake these estimates generally less precise than other estimates included in the unit-of-production method over totalCompany’s financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect the Company’s estimated future net cash flows of its proved reserves. Other property, consisting of leasehold building improvements, officeThese changes could affect the Company’s quarterly ceiling test calculation and computer equipment is depreciated as described above in Other Property and Equipment.
Income Taxes.
52
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assets will not be realizable. We recognizeThe Company recognizes a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination which is based on the technical merits of the position and will recordposition. The Company records the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense.
Earnings (Loss) Per Share.
Correction of Immaterial Error
The Company has identified an issue related to its historical process of calculating the Company’s EPS. The Company grants restricted stock awards which entitle the recipient to all of the rights of a shareholder of the Company adopted ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“including non-forfeitable rights to receive all dividends or other distributions paid with respect to such shares. Unvested restricted stock is forfeitable until earned and therefore not considered outstanding for basic EPS. Because restricted stock awards have the non-forfeitable right to share in dividends and earnings with common shareholders prior to vesting, the Company must apply the two-class method of allocating distributed and undistributed earnings to unvested restricted stock and outstanding common shares. Historically, it was identified by management that the Company had not been applying the two-class method of calculating basic and diluted EPS in accordance with ASC 606”) using260. Rather, the full retrospective method and has appliedCompany was considering all restricted stock grants as outstanding at the standardtime of issuance in the calculation of EPS.
At March 31, 2022, the Company determined that its unvested restricted stock awards are participating securities which contain non-forfeitable rights to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services.dividends. As a result, of adopting ASC 606, the Company didis required to adjust “Net income (loss) attributable to common stockholders” to allocate dividends paid to unvested shares as well as undistributed earnings. In addition, the Company determined that its basic and diluted weighted average shares outstanding were also not haveadjusted correctly to reflect these participating securities.
The Company concluded the adjustments were immaterial to its 2021 annual and interim financial statements and its 2022 interim financial statements in accordance with the guidance in Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (“SAB”) No. 99, Materiality and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in the Current Year Financial Statements. The correction resulted in a cumulative-effect adjustment in retained earnings. The comparative information presented thereindecrease of $0.01 per basic and diluted share for the year ended June 30, 2018 reflects the reclassification on our consolidated statement of operations of $507,685 from “Production Costs” to “Revenue - Natural Gas Liquids” in conformance with ASC 606. These changes to revenue and production costs resulted from the conclusion that the Company did not control the product throughout processing before transferring to the customer. Therefore, costs incurred after the transfer of control are treated as reductions of revenue. Additionally, adoption of ASC 606 did not impact net income2021. See Note 13, “Earnings (Loss) per Common Share” for more details.
53
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company noted the following adjustments to its Earnings (loss) per common stockholders, current assets, total assets, current liabilities, total liabilities or stockholders’ equity andshare presentation for the Company does not expect that it will do so in future periods.
| | | |
| | Year Ended June 30, | |
| 2021 | ||
As reported: | | | |
Net income (loss) for earnings per share calculation | | $ | (16,438) |
| | | |
Weighted average number of common shares outstanding — Basic | | | 33,264 |
Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share | | | 33,264 |
| | | |
Net earnings (loss) per common share — Basic | | $ | (0.49) |
Net earnings (loss) per common share — Diluted | | $ | (0.49) |
| | | |
Revised: | | | |
Net income (loss) for earnings per share calculation | | $ | (16,503) |
| | | |
Weighted average number of common shares outstanding — Basic | | | 32,744 |
Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share | | | 32,744 |
| | | |
Net earnings (loss) per common share — Basic | | $ | (0.50) |
Net earnings (loss) per common share — Diluted | | $ | (0.50) |
Recently Adopted Accounting Pronouncements
Income Taxes. In January 2016,December 2019, the FASBFinancial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement2019-12”) as part of Financial Assets and Financial Liabilities ("ASU 2016-01"). The pronouncement requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investees) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost. Effective July 1, 2018, the Company prospectively adopted ASU 2016-01 without impact to its consolidated financial position or results of operations. Because its investment in Well Lift Inc. does not have a readily determinable fair value, the Company elected to measure this investment at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer, if they were to occur.
Recently Issued Accounting Pronouncements
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and earlyEarly adoption is permitted. Entitiespermitted and entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. For smaller reporting companies, as provided by ASU 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842), ASU 2016-13 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2022. The adoptionCompany is currently evaluating the impact of ASU 2016-13 is currentlybut does not expect that it will have a material effect on the Company’s financial position, results of operations, cash flows or disclosures.
Other accounting pronouncements that have recently been issued by the FASB or other standards-setting bodies are not expected to have a material effectimpact on our consolidatedthe Company’s financial statements.position, results of operations, cash flows or disclosures.
54
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 3 – Enduro Purchase2. Leases
Operating leases are reflected as an operating lease right of use (“ROU”) asset included in “Other assets, net”, and Sale Agreementas a ROU liability in “Accrued liabilities and "Stalking Horse" Bid
As a non-operator and having adequate liquidity, the Company has generally not entered into lease transactions. The Company’s only operating lease is for corporate office space in Houston, Texas, effective May 1, 2019 and which expires November 30, 2022. The Company recordedhas no leases that meet the criteria for classification as a finance lease or a short-term lease.
The Company makes certain assumptions and judgments when evaluating a contract that meets the definition of a lease under ACS 842, Leases. At adoption, July 1, 2019, as the Company’s operating lease did not provide an implicit rate, an incremental borrowing rate was calculated using the prime-rate-based borrowing rate under the Company’s Senior Secured Credit Facility as the term facility was based on a similar lease term and is appropriately risk-adjusted. The lease term was determined by considering any option available to extend or to early terminate the lease which the Company believed was reasonably certain to be exercised.
The table below summarized the Company’s leases for the years ended June 30, 2022 and 2021 (in thousands, except years and discount rate):
| | | | | | | |
| | Years Ended June 30, | | ||||
|
| 2022 |
| 2021 | | ||
Statements of Operations: | | | | | | | |
Operating lease costs | | $ | 52 | | $ | 52 | |
| | | | | | | |
Statements of Cash Flow: | | | | | | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | | |
Operating cash flows from operating leases | | $ | 62 | | $ | 60 | |
| | | | | | | |
Balance Sheets: | | | | | | | |
Operating lease ROU asset (included in other assets) | | $ | 21 | | $ | 71 | |
Accrued liabilities and other - current | | | 26 | | | 64 | |
Operating lease liability - long-term | | | — | | | 21 | |
| | | | | | | |
Other: | | | | | | | |
Weighted average remaining lease term in years | | | 0.42 | | | 1.34 | |
Weighted average discount rate | | | 5.15 | % | | 5.15 | % |
55
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of June 30, 2022, the future minimum lease payments associated with the Company’s non-cancellable operating lease for office space are as follows (in thousands):
| | | |
Fiscal Year |
| June 30, 2022 | |
2023 | | $ | 26 |
Total operating lease payments | | | 26 |
Less: discount to present value | | | — |
Total operating lease liabilities | | | 26 |
Less: current operating lease liabilities | | | 26 |
Non current operating lease liabilities | | $ | — |
The Company applied the following practical expedients as provided in the standards update which provide elections to not reassess:
| ● | Not to apply the recognition requirements in the lease standard to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise). |
| ● | Whether an expired or existing pre-adoption date contracts contained leases. |
| ● | Lease classification of any expired or existing leases. |
| ● | Initial direct costs for any expired or existing leases. |
| ● | Not to separate lease components from non-lease components in a contract and accounting for the combination as a lease (reflected by asset class). |
Note 3. Revenue Recognition
The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the Delhi Field in Northeast Louisiana, the Hamilton Dome Field in Wyoming, the Barnett Shale properties located in North Texas, the Williston Basin properties in North Dakota, and the Jonah Field in Sublette County, Wyoming. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties historically provided de minimis revenue, with the exception of the three months ended December 31, 2021 in which the Company received $1.1 million break-up fee uponfor past royalties that accumulated over a period of approximately three years. These past royalties were recorded as operating revenues within the closing of a higher bidder's purchase transaction. During May 2018, the Company had entered into a Purchase and Sale Agreement ("PSA"), to acquire, as the "stalking horse" bidder, certain oil and gas assets from an affiliate of Enduro Resource Partners LLC ("Enduro") for a purchase price of $27.5 million, subject to the outcome of Enduro's Chapter 11 process. Contemporaneous with executing the PSA, the Company made a $2.75 million deposit to an acquisition escrow account which, together with interest earned, comprised the restricted cash balance on the Company's June 30, 2018 consolidated statement of financial position. Earlier in the first quarter of 2019, the Company was repaid its deposit together with related earned interest when a higher bidder first emerged in the bidding process.
| | | | | | |
| | Years Ended June 30, | ||||
|
| 2022 |
| 2021 | ||
Revenues | | | | | | |
Crude oil | | $ | 52,683 | | $ | 26,411 |
Natural gas | | | 39,174 | | | 2,629 |
Natural gas liquids | | | 17,069 | | | 3,662 |
Total revenues | | $ | 108,926 | | $ | 32,702 |
As of June 30, 20192022, as a non-operator, the Company did not take production in-kind and June 30, 2018 our receivables consisteddid not negotiate contracts with customers for its production from the Delhi Field, the Hamilton Dome Field, the Barnett Shale properties or the Willison Basin properties. The Company recognizes crude oil, natural gas, and NGL production revenue at the point in time when custody and title (“control”) of the following:product transfers to the customer. The sales of oil and natural gas are made under contracts which the Company’s third-party operators of its wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production one to two months after delivery.
In the Jonah Field, the Company has elected to take its natural gas and NGL working interest production in-kind and markets separately to different purchasers for natural gas and to Enterprise Products Partners L.P. (“Enterprise”) for its NGLs.
56
| June 30, 2019 | June 30, 2018 | ||||||
| Receivables from oil and gas sales | $ | 3,168,116 | $ | 3,940,998 | |||
| Other | — | 918 | |||||
| Total receivables | $ | 3,168,116 | $ | 3,941,916 | |||
| June 30, 2019 | June 30, 2018 | ||||||
| Prepaid insurance | $ | 206,198 | $ | 198,558 | |||
| Prepaid federal and state income taxes | 121,679 | 231,920 | |||||
| Retainers and deposits | 8,019 | 11,089 | |||||
| Other prepaid expenses | 122,382 | 82,940 | |||||
| Prepaid expenses and other current assets | $ | 458,278 | $ | 524,507 | |||
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Judgments made in applying the guidance in ASC 606, Revenue from Contracts with Customers, relate primarily to determining the point in time when control of product transfers to the customer. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.
The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied at a point in time upon control transferring to a customer at a specified delivery point. Consideration is allocated to completed performance obligations at the end of an accounting period.
Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received by field operators before distributing the Company’s share one to two months after production has occurred, which is typical in the oil and natural gas industry. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for the sale of the product. To estimate accounts receivable from operators’ contracts with customers, the Company uses knowledge of its properties, information from field operators, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Because the contractual performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with field operators as “Receivables from crude oil, natural gas, and natural gas liquids sales” on the consolidated balance sheets. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser as remitted to the Company by field operators.
Note 6 – Property4. Acquisitions
On April 1, 2022, the Company closed the acquisition of non-operated interests in the Jonah Field in Sublette County, Wyoming from Exaro Energy III, LLC (the “Jonah Field Acquisition”). After taking into account customary closing adjustments and Equipment
On January 14, 2022, the Company completed the acquisition of non-operated working interests in the Williston Basin in North Dakota from Foundation Energy Fund VII-A, LP and Foundation Energy Management, LLC (the “Williston Basin Acquisition”). After taking into account customary closing adjustments and an effective date of June 30, 20191, 2021, cash consideration was $25.2 million which included $0.3 million of capitalized transaction costs related to the acquisition. The Company accounted for the transaction as an asset acquisition and June 30, 2018, ourallocated all of the purchase price (including capitalized transaction costs) to proved oil and natural gas properties. The Company also recognized $2.4 million in non-cash asset retirement obligations. The transaction was funded with cash on hand and $16.0 million in borrowings under the Company’s Senior Secured Credit Facility.
On May 7, 2021, the Company acquired an approximate 17% average net working interest and a 14% average net revenue interest in non-operated oil and natural gas properties in the Barnett Shale from Tokyo Gas Americas for net cash consideration of $17.4 million, after taking into account customary closing adjustments, and other propertyalso recognized $2.8 million in non-cash asset retirement obligations (the “Barnett Shale Acquisition”). The Company determined that the properties acquired did not meet the definition of a business; therefore, the transaction was accounted for as an asset acquisition. During the nine months ended March 31, 2022, the Company recorded a downward purchase price
57
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
adjustment of $0.9 million related to its acquisition of the Barnett Shale properties as a result of the completion of the final settlement statement.
In accordance with the FASB’s authoritative guidance on asset acquisitions, the Company allocated the cost of the acquisition to the assets acquired and liabilities assumed based on a relative fair value basis of the assets acquired and liabilities assumed, with no recognition of goodwill or bargain purchase gain recorded. Incremental legal and professional fees related directly to the acquisitions were capitalized as part of the acquisition cost. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize market assumptions of market participants.
Note 5. Property and Equipment
Property and equipment as of June 30, 2022 and 2021 consisted of the following:
| June 30, 2019 | June 30, 2018 | ||||||
| Oil and natural gas properties: | |||||||
| Property costs subject to amortization | $ | 95,622,153 | $ | 90,392,918 | |||
| Less: Accumulated depreciation, depletion, and amortization | (35,275,687 | ) | (29,153,172 | ) | |||
| Unproved properties not subject to amortization | — | — | |||||
| Oil and natural gas properties, net | 60,346,466 | 61,239,746 | |||||
| Other property and equipment: | |||||||
| Furniture, fixtures and office equipment, at cost | 154,731 | 143,223 | |||||
| Less: Accumulated depreciation | (128,313 | ) | (112,816 | ) | |||
| Other property and equipment, net | $ | 26,418 | $ | 30,407 | |||
| | | | | | |
|
| June 30, 2022 |
| June 30, 2021 | ||
Oil and natural gas properties | | |
| | |
|
Property costs subject to amortization | | $ | 188,634 | | $ | 129,123 |
Less: Accumulated depletion, depreciation, and amortization | | | (78,126) | | | (70,607) |
Oil and natural gas properties, net | | $ | 110,508 | | $ | 58,516 |
Other property and equipment | | |
| | |
|
Furniture, fixtures and office equipment, at cost | | $ | 148 | | $ | 155 |
Less: Accumulated depreciation | | | (148) | | | (144) |
Other property and equipment, net | | $ | — | | $ | 11 |
As of June 30, 20192022 and 2018,2021, all oil and natural gas property costs were being amortized.
During the years ended June 30, 20192022 and 2018,2021, the Company incurred development capital expenditures of $5.2$2.6 million and $5.4$0.6 million, respectively,respectively. In addition, during the year ended June 30, 2022, the Company recorded a downward $0.9 million purchase adjustment related to its acquisition of the Barnett Shale properties. The Company received $0.9 million during the year ended June 30, 2022 primarily related to effective date net revenues received from the previous owner of the properties.
The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas and properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs result in an impairment charge.
At June 30, 2022, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2022 of the West Texas Intermediate (“WTI”) crude oil spot price of $85.82 per barrel and Henry Hub natural gas spot price of $5.19 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $44.24, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, the Company’s net book value of oil and natural gas properties as of June 30, 2022 did not exceed the current ceiling. There was no impairment on oil and natural gas properties for the year ended June 30, 2022.
At June 30, 2021, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2021 of the WTI crude oil spot price of $49.72 per barrel and Henry Hub natural gas spot price of $2.46 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $19.81, which was based on historical differentials to WTI as NGLs do not have any single comparable reference
58
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
index price. Using these prices, the Company’s net book value of oil and natural gas properties at June 30, 2021 did not exceed the current ceiling. At December 31, 2020 and September 30, 2020, the Company recorded ceiling test impairment charges of $15.2 million and $9.6 million, respectively. The ceiling test impairments were driven by decreases in the Delhi field.
Note 7
On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility, as amended, (the “Senior Secured Credit Facility”) with MidFirst Bank in an amount up to $50.0 million with a current borrowing base of $50.0 million. On November 2, 2020, the Company entered into the Fifth Amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2024. The borrowing base will be redetermined semiannually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The Senior Secured Credit Facility included a placement fee of 0.50% on the initial borrowing base amounting to $50.0 million and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s option, at either London Interbank Offered Rate ("LIBOR") plus 2.75%, subject to a minimum LIBOR of 0.25%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.
The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Secured Credit Facility without premium or penalty. Amounts outstanding under the Senior Secured Credit Facility are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the properties of the Company and its subsidiaries. Borrowings under the Senior Secured Credit Facility may be used for the acquisition and development of oil and natural gas properties, investments in cash flow generating properties complimentary to the production of oil and natural gas, and for letters of credit or other general corporate purposes.
The Senior Secured Credit Facility contains certain events of default, including non-payment; breaches or representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Secured Credit Facility also contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (i) a maximum total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. As of June 30, 20192022, the Company had $21.3 million borrowings outstanding under its Senior Secured Credit Facility, resulting in $28.7 million of available borrowing capacity. As of June 30, 2022, the Company was in compliance with the financial covenants under the Senior Secured Credit Facility.
The Company is currently working on its annual redetermination with MidFirst Bank. It expects that the borrowing base will remain at $50.0 million and the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, will be set at $125.0 million. The Company is required to enter into hedges on a rolling 12-month basis when the borrowings exceed 25% of the Margined Collateral Value. Based on the current amount outstanding, the utilization percentage under the required hedging covenant is below the minimum utilization threshold of 25% and as a result the Company is not required to enter into additional hedges at this time.
On February 7, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required the Company to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.
59
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby the Company must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the Ninth Amendment, as discussed above.
On August 5, 2021 the Company entered into the Seventh Amendment to the Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.
On January 5, 2021, and effective as of December 28, 2020, the Company entered into the Sixth Amendment to the Senior Secured Credit Facility which replaced the debt service coverage ratio (as defined therein) maintenance covenant with a new covenant requiring current ratio (as defined therein) of not less than 1.00 to 1.00.
Note 7. Income Taxes
The Company files a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.
There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2022 and 2021. The Company believes that it has appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on its assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the fiscal years ended June 30, 2018 our other assets consistedthrough June 30, 2021 for federal tax purposes and for the fiscal years ended June 30, 2017 through June 30, 2021 for state tax purposes. To the extent the Company utilizes net operating losses (“NOLs”) generated in earlier years, such earlier years may also be subject to audit.
Income tax (expense) benefit for the years ended June 30, 2022 and 2021 is comprised of the following:following (in thousands):
| | | | | | |
|
| June 30, 2022 |
| June 30, 2021 | ||
Current: | | |
| | |
|
Federal | | $ | (6,309) | | $ | 334 |
State | | | (1,062) | | | (454) |
Total current income tax (expense) benefit | | | (7,371) | | | (120) |
Deferred: | | |
| | | |
Federal | | | (913) | | | 3,987 |
State | | | (229) | | | 1,117 |
Total deferred income tax (expense) benefit | | | (1,142) | | | 5,104 |
Total income tax (expense) benefit | | $ | (8,513) | | $ | 4,984 |
For the year ended June 30, 2022 the Company recognized income tax expense of $8.5 million and had an effective tax rate of 20.7% compared to an income tax benefit of $5.0 million and an effective tax rates of 23.3% for the year ended June 30, 2021.
In certain prior years, the Company undertook a project to seek potential cash tax savings opportunities identifying available Enhanced Oil Recovery credits (“EOR credits”) related to its interests in the Delhi Field. To take advantage of the EOR credits, the Company amended federal and state tax returns for the years ended June 30, 2017 and 2018 and incorporated the associated impacts into its 2019 tax returns. Principally as a result of the EOR credits, the Company recorded a net tax benefit of $2.8 million during fiscal 2020, all of which was received during the year ended June 30, 2022. During year ended June 30, 2022, the Company recognized an income tax benefit of $0.4 million attributable to the EOR credit.
60
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| June 30, 2019 | June 30, 2018 | ||||||
| Royalty rights | 108,512 | 108,512 | |||||
| Less: Accumulated amortization of royalty rights | (47,474 | ) | (33,910 | ) | |||
| Investment in Well Lift Inc., at cost | 108,750 | 108,750 | |||||
| Deferred loan costs | 168,972 | 168,972 | |||||
| Less: Accumulated amortization of deferred loan costs | (141,927 | ) | (126,771 | ) | |||
| Software license | 20,662 | 20,662 | |||||
| Less: Accumulated amortization of software license | (7,462 | ) | (1,380 | ) | |||
| Other assets, net | $ | 210,033 | $ | 244,835 | |||
The Company’s effective tax rate will typically differ from the separationstatutory federal rate as a result of our artificial lift technology operationsstate income taxes, primarily in December 2015. We conveyed our patentsthe states of Louisiana and Texas, due to percentage depletion in excess of basis, valuation allowance, enhanced oil recovery credit, and other intellectual property to WLI and retained a 5% royalty on future gross revenues associatedpermanent differences. The following table presents the technology. We own 17.5%reconciliation of the common stockCompany’s income taxes calculated at the statutory federal tax rate to the income tax (expense) benefit (in thousands).
| | | | | | | | | | | | |
| | | | | % of Income | | | | | % of Income | | |
| | | | | Before | | | | | Before | | |
|
| June 30, 2022 |
| Income Taxes |
| June 30, 2021 |
| Income Taxes | | |||
Income tax (expense) benefit computed at the statutory federal rate: | | $ | (8,640) | | | 21.0 | % | $ | 4,499 | | 21.0 | % |
Reconciling items: | | |
| | | | | | | | | |
Return to provision adjustments | | | (2) | | | — | % | | (20) | | (0.1) | % |
Depletion in excess of tax basis | | | 190 | | | (0.5) | % | | 176 | | 0.8 | % |
State income taxes, net of federal tax benefit | | | (1,020) | | | 2.5 | % | | 523 | | 2.4 | % |
Permanent differences related to stock-based compensation and other | | | 3 | | | — | % | | (55) | | (0.3) | % |
Federal valuation allowance | | | 623 | | | (1.5) | % | | (570) | | (2.7) | % |
EOR credit benefit | | | 377 | | | (0.9) | % | | 336 | | 1.6 | % |
Other | | | (44) | | | 0.1 | % | | 95 | | 0.6 | % |
Income tax (expense) benefit | | $ | (8,513) | | | 20.7 | % | $ | 4,984 | | 23.3 | % |
Deferred income taxes primarily represent the net tax effect of WLItemporary differences between the carrying amounts of assets and accountliabilities for our investmentfinancial reporting purposes and the amounts used for income tax purposes. The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands):
| | | | | | |
|
| June 30, 2022 |
| June 30, 2021 | ||
Deferred tax assets: | | |
| | |
|
Non-qualified stock-based compensation | | $ | 106 | | $ | 310 |
Net operating loss carry-forwards and other carry-forwards | | | 8 | | | 365 |
Derivative losses | | | 427 | | | — |
Asset retirement obligations | | | 3,128 | | | 1,285 |
Other deferred tax assets | | | 238 | | | 161 |
Gross deferred tax assets | | | 3,907 | | | 2,121 |
| | | | | | |
Valuation allowance | | | — | | | (862) |
Net deferred tax assets | | | 3,907 | | | 1,259 |
Deferred tax liability: | | |
| | |
|
Oil and natural gas properties | | | (11,006) | | | (7,216) |
Total deferred tax liability | | | (11,006) | | | (7,216) |
| | | | | | |
Net deferred tax liability | | $ | (7,099) | | $ | (5,957) |
As of June 30, 2022, the Company had a federal tax loss carryforward of approximately $0.6 million that it acquired through a reverse merger in this private companyMay 2004. The majority of the tax loss carryforwards from the reverse merger expired without being utilized. The remaining deferred tax asset and valuation allowance of $0.1 million related to the portion of the NOLs that were limited by IRC Section 382 was written off during the year ended June 30, 2022. The Company has considered all positive and negative evidence to assess the likelihood that it will be able to realize its deferred tax assets. Realization is dependent on generating sufficient taxable income over the period the deferred tax assets are deductible. For the three-year period ending June 30, 2022, the Company is in a cumulative income position. Based on the weight of available evidence, the Company believes that it is more likely than not that the deferred tax assets will be realized. As result, the Company has released the valuation allowance of $0.6 million.
Note 8. Derivatives
The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and interest rate risk. In accordance with the Company’s policy and the requirements under the Senior Secured Credit
61
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Facility (as discussed in Note 6, “Senior Secured Credit Facility”), it may hedge or may be required to hedge a varying portion of anticipated oil and natural gas production for future periods. Derivatives are carried at cost less impairment, if any, plusfair value on the consolidated balance sheets as assets or minus changes resulting from observable priceliabilities, with the changes in orderly transactionsthe fair value included in the consolidated statements of operations for the identicalperiod in which the change occurs. The Company’s hedge policies and objectives may change significantly as its operational profile changes. The Company does not enter into derivative contracts for speculative trading purposes.
It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of June 30, 2022, the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s Senior Secured Credit Facility.
The Company has in the past and may utilize in the future costless put/call collars and fixed-price swaps to hedge a similar investmentportion of its anticipated future production. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for the volumes under contract. The Company has elected not to designate its open derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of the same issuer, if such were to occur. derivative contracts and all payments and receipts on settled derivative contracts in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.
All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820, Fair Value Measurement ("ASC 820") and included in the consolidated balance sheets as assets or liabilities. The “Derivative contract assets” and “Derivative contract liabilities” represent the difference between the market commodity prices and the hedged prices for the remaining volumes of production hedges as of June 30, 2022 (the “mark-to-market valuation”). The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of June 30, 2022 and 2021 (in thousands):
| | | | | | | | | | | | | | | | |
Derivatives not designated | | | | | | | | | ||||||||
as hedging contracts | | Balance sheet | | Derivative Contract Asset | | Balance sheet | | Derivative Contract Liability | ||||||||
under ASC 815 |
| location |
| June 30, 2022 |
| June 30, 2021 |
| location |
| June 30, 2022 |
| June 30, 2021 | ||||
Commodity contracts | | Current assets - derivative contract assets | | $ | 170 | | $ | — | | Current liabilities - derivative contract liabilities | | $ | 2,164 | | $ | — |
Commodity contracts | | Other assets - derivative contract assets | | | — | | | — | | Long term liabilities - derivative contract liabilities | | | — | | | — |
Total derivatives not designated as hedging contracts under ASC 815 | | | | $ | 170 | | $ | — | | | | $ | 2,164 | | $ | — |
The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations (in thousands). "Realized gain (loss) on derivative contracts" represents all receipts (payments) on derivative contracts settled during the period. "Unrealized gain (loss) on derivative contracts" represents the net change in the mark-to-market valuation of the derivative contracts.
| | | | | | | | |
Derivatives not designated | | Location of gain (loss) | | | | | | |
as hedging contracts | | recognized in income on | | Years Ended June 30, | ||||
under ASC 815 |
| derivative contracts |
| 2022 |
| 2021 | ||
Commodity contracts: | | | | | | | | |
Realized gain (loss) on derivative contracts | | Other income and expenses - net gain (loss) on derivative contracts | | $ | (1,769) | | $ | (2,526) |
Unrealized gain (loss) on derivative contracts | | Other income and expenses - net gain (loss) on derivative contracts | | | (1,994) | | | 1,911 |
Total net gain (loss) on derivative contracts | | | | $ | (3,763) | | $ | (615) |
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of June 30, 2022, the Company had the following open crude oil and natural gas derivative contracts:
| | | | | | | | | | | | |
| | | | | | | | Weighted Average | | Weighted Average | ||
| | | | | | Volumes in | | Floor Price per | | Ceiling Price per | ||
Period |
| Instrument |
| Commodity |
| MMBTU/Bbl | | MMBTU/Bbl |
| MMBTU/Bbl | ||
July 2022 - October 2022 | | Collar | | Natural Gas | | 471,640 | | $ | 3.75 | | $ | 5.05 |
November 2022 - February 2023 | | Collar | | Natural Gas | | 443,750 | | | 3.75 | | | 7.30 |
July 2022 - October 2022 | | Collar | | Natural Gas | | 317,579 | | | 5.25 | | | 6.67 |
November 2022 - March 2023 | | Collar | | Natural Gas | | 374,072 | | | 5.25 | | | 7.50 |
July 2022 - February 2023 | | Collar | | Crude Oil | | 122,389 | | | 70.00 | | | 87.50 |
The Company evaluatespresents the investment for impairment when it identifies any events or changesfair value of its derivative contracts at the gross amounts in circumstances that might have a significant adverse effectthe consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the investment.Company’s derivative contracts as of June 30, 2022 and 2021 (in thousands):
| | | | | | | | | | | | |
| | Derivative Contract Asset | | Derivative Contract Liability | ||||||||
Offsetting of Derivative Assets and Liabilities |
| June 30, 2022 |
| June 30, 2021 |
| June 30, 2022 |
| June 30, 2021 | ||||
Gross amounts presented in the Consolidated Balance Sheet | | $ | 170 | | $ | — | | $ | 2,164 | | $ | — |
Amounts not offset in the Consolidated Balance Sheet | | | (170) | | | — | | | (170) | | | — |
Net amount | | $ | — | | $ | — | | $ | 1,994 | | $ | — |
The Company enters into an ISDA with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.
Note 9. Fair Value Measurement
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
The three levels are defined as follows:
Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2—Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3—Unobservable inputs for which there are little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable (Level 1) market corroborated (Level 2), or generally unobservable (Level 3). The Company classifies fair value balances based on observability of those inputs.
63
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and Other
| | | | | | | | | | | | |
| | June 30, 2022 | ||||||||||
|
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||
Assets | | | | | | | | | | | | |
Derivative contract assets | | $ | — | | $ | 170 | | $ | — | | $ | 170 |
| | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | |
Derivative contract liabilities | | $ | — | | $ | 2,164 | | $ | — | | $ | 2,164 |
Derivative contracts listed above as Level 2 include costless put/call collars that are carried at fair value. The Company records the net change in fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and other consistedimplied volatility factors related to changes in the forward curves. See Note 8, “Derivatives,” for additional discussion of derivatives.
The Company’s derivative contracts are with large utilities with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.
Other Fair Value Measurements. The following disclosure of the following:
| June 30, 2019 | June 30, 2018 | ||||||
| Accrued incentive and other compensation | $ | 369,719 | $ | 415,182 | |||
| Accrued severance | — | 160,089 | |||||
| Asset retirement obligations due within one year | 50,244 | 35,539 | |||||
| Accrued royalties, including suspended accounts | 11,554 | 11,498 | |||||
| Accrued franchise taxes | 5,738 | 162,805 | |||||
| Accrued ad valorem taxes | 100,500 | 89,773 | |||||
| Accrued liabilities and other | $ | 537,755 | $ | 874,886 | |||
The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial measurement and any subsequent revision of ARO for which fair value is calculated using discounted future cash flows derived from historical costs and management’s expectations of future cost environments. Significant Level 3 inputs used in the calculation of ARO include the costs of plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values. See Note 10, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s ARO.
Note 9 –10. Asset Retirement Obligations
The Company’s ARO represents the estimated present value of the amount we will incurexpected to be incurred to plug, abandon, and remediate our producingits oil and natural gas properties at the end of their productive lives in accordance with applicable laws. laws and regulations. The Company records the ARO liability on the consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties, net” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and amortization” expense in the consolidated statements of operations.
64
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is a reconciliation of the beginning and ending asset retirement obligationsactivity related to the Company’s ARO liability (inclusive of the current portion) for the years ended June 30, 20192022 and 2018:
| Years Ended | |||||||
| 2019 | 2018 | ||||||
| Asset retirement obligations — beginning of period | $ | 1,422,955 | $ | 1,288,743 | |||
| Liabilities incurred | 31,268 | 44,700 | |||||
| Accretion of discount | 101,506 | 90,290 | |||||
| Revisions to previous estimates | 55,116 | (778 | ) | ||||
| Asset retirement obligations — end of period | 1,610,845 | 1,422,955 | |||||
| Less: current asset retirement obligations | (50,244 | ) | (35,539 | ) | |||
| Long-term portion of asset retirement obligations | $ | 1,560,601 | $ | 1,387,416 | |||
| Fiscal Year | |||
| 2019 | 2018 | ||
| Fourth quarter ended June 30, | $0.100 | $0.100 | |
| Third quarter ended March 31, | $0.100 | $0.100 | |
| Second quarter ended December 31, | $0.100 | $0.075 | |
| First quarter ended September 30, | $0.100 | $0.075 | |
| Fiscal Year | |||||||
| 2019 | 2018 | ||||||
| Number of treasury shares acquired | 18,424 | 73,208 | |||||
| Average cost per share | $ | 8.51 | $ | 7.80 | |||
| Total cost of treasury shares acquired | $ | 156,791 | $ | 571,083 | |||
| Year Ended June 30, | |||
| 2019 | |||
| Weighted average fair value of market-based awards granted | $ | 8.24 | |
| Risk-free interest rate | 2.69 | % | |
| Expected life in years | 2.82 | ||
| Expected volatility | 41.8 | % | |
| Dividend yield | 4.0 | % | |
| | | | | | |
| | Years Ended | ||||
|
| June 30, 2022 |
| June 30, 2021 | ||
Asset retirement obligations — beginning of period | | $ | 5,583 | | $ | 2,589 |
Liabilities incurred | | | 219 | | | — |
Liabilities settled(1) | | | (17) | | | (99) |
Liabilities acquired(2) | | | 5,400 | | | 2,806 |
Accretion of discount | | | 531 | | | 210 |
Revisions of previous estimates(3) | | | 2,205 | | | 77 |
Asset retirement obligations — end of period | | | 13,921 | | | 5,583 |
Less: current asset retirement obligations | | | (22) | | | (44) |
Long-term portion of asset retirement obligations | | $ | 13,899 | | $ | 5,539 |
| Award Type | Number of Restricted Shares | Weighted Average Grant-Date Fair Value | ||||
| Service-based awards | 112,381 | $ | 8.52 | |||
| Market-based awards | 64,302 | 7.35 | ||||
| Unvested at June 30, 2019 | 176,683 | $ | 8.09 | |||