Item 1. Business
Item 1. Business
Note: See Glossary of Selected Petroleum Industry Terms starting on page
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General
Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management, and development of producing oil and natural gas properties. The Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisition, while seeking opportunities to maintain and increase production through selective development, production enhancement, and other exploitation efforts on its properties.
Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO 2 enhanced oil recovery (“EOR”) project, our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore central Texas wells.
Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue interest of 26.2%. The field is operated by Denbury Onshore LLC (“Denbury”), a subsidiary of Denbury Inc.
On November 1, 2019, the Company acquired non-operated working interests in the Hamilton Dome field consisting of a 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The field is operated by Merit Energy Company (“Merit”), a private oil and natural gas company, who owns the vast majority of the remaining working interest in the Hamilton Dome field. Our acquired interest in Hamilton Dome aligned with the Company's strategy of adding long-lived, low decline reserves expected to be supportive of our dividend over the long-term.
On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale consisting of approximately 21,000 net acres held by production across nine North Texas counties in the Barnett Shale (the “Barnett Shale Acquisition”). The acreage has an average working interest of 17.3% and associated average revenue interest of 14.2% (inclusive of overriding royalty interests). At the time of the Barnett Shale Acquisition, approximately 90% of the wells acquired were operated by Blackbeard Operating LLC (“Blackbeard”), while the remaining 10% were operated by seven other operators. After the closing of the Barnett Shale Acquisition, Blackbeard announced the sale of its interests to Diversified Energy Company PLC (“Diversified Energy”), which subsequently closed in July of 2021. At present, Blackbeard is still the operator of the assets
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under a transition services agreement with Diversified Energy. However, after the transition, Diversified Energy will take over operations of the assets.
Significant Activity in Fiscal 2021
• Closed the Barnett Shale Acquisition on May 7, 2021, which included total proved reserves of 13.1 MMBOE as of June 30, 2021 as estimated by DeGolyer & MacNaughton (“D&M”), an independent reservoir engineering firm.
• Returned to shareholders $4.3 million in cash dividends in fiscal 2021. The Company has paid out to shareholders more than $74.5 million in cash dividends since inception of the dividend program in December 2013.
• Generated $3.7 million in operating income before impairments.
• Funded our operations, development capital expenditures, and dividends out of operating cash flow.
• Proved oil equivalent reserves at June 30, 2021, were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021.
• Primarily driven by proved oil and gas property impairments of $9.6 million and $15.2 million recorded during the first and second fiscal quarters of 2021, respectively, we recognized a net loss of $16.4 million, or $(0.49) per common share.
• We completed the NYMEX WTI oil swaps entered into during fiscal year 2020, and have not entered into any new oil and natural gas derivatives as of June 30, 2021.
• Denbury, whose subsidiary operates the Delhi field, emerged from bankruptcy on September 18, 2020, and returned to conformance projects with a refreshed capital budget after a period of no conformance spending.
Delhi Field - Enhanced Oil Recovery CO 2 Flood - Onshore Louisiana
The Company purchased the Delhi field in September 2003. In May 2006, the Company conveyed its working interest in the field to Denbury for $50 million for the purpose of installing an EOR project; we retained a 23.9% reversionary working interest upon payout of the project, as defined in the purchase and sale agreements. Today, our interests include a 23.9% working interest and a 7.2% royalty interest with a total net revenue interest of 26.2%. Delhi field is located in northeast Louisiana in Franklin, Madison, and Richland parishes and encompasses approximately 13,600 unitized acres.
The Delhi field was discovered in the mid-1940s and has had a prolific production history totaling approximately 195 MMBbls of oil through primary and limited secondary recovery operations. Since EOR production began in March 2010, the Unit has produced over 23.0 MMBbls of oil. For fiscal 2021, average gross daily oil production at Delhi was 4,281 BOPD and 977 bbls NGLs per day (5,258 BOEPD).
After the May 2006 conveyance, Denbury as the operator originally planned six primary phases for the installation of the CO 2 flood in the Delhi field. Four of these six phases have been completed as of June 30, 2021, and two remain undeveloped. One of
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the remaining two phases (Phase V) is reflected as proved undeveloped in our current reserves report and the other (Phase VI) was removed from proved reserves as it was not deemed economic due to distant location and oil price.
In June 2013, following an adverse fluid release event that consisted of the uncontrolled release of CO 2 , water, natural gas, and a small amount of oil from a previously plugged well in the southwest part of the field, the operator suspended CO 2 injection in most of the southwestern tip of the field. The operator has fully remediated the affected area, and has isolated that part of the field with a water curtain, thus removing the area from the CO 2 flood.
An NGL extraction plant was completed and began processing in December 2016. The plant allows for the sale of NGLs, improves CO 2 flood efficiency, and provides the extracted methane as a source of power for plant reducing operating expenses.
Phase V development started in fiscal 2017 with the water curtain and related infrastructure program. The first pad commenced injections in fiscal 2019 with the second pad starting in the second quarter of fiscal 2020. Additional Delhi Phase V development has been delayed due to Denbury’s restructuring in fiscal 2021.
The total gross purchased CO 2 volume was 18 BCF for fiscal 2021. In February 2020, the CO 2 purchase line to Delhi was shut-in by the pipeline operator for extensive repairs. No CO 2 was purchased from the shut-in date through October 2020. During the pipeline repairs, the CO 2 recycle facilities continued to operate providing approximately 80% of the historic total injected CO 2 volumes to Delhi. The decrease in production within the field was primarily a result of lower injection volumes reducing reservoir pressure. CO2 purchases resumed in November 2020 at a limited level, and resumption of desired purchase volumes is expected during fiscal 2022 which is projected to increase reservoir pressure.
At June 30, 2021, the Company had total proved reserves of 8.5 MMBOE at Delhi, which was comprised of 6.5 MMBOE of oil and 2.0 MMBOE of NGLs as estimated by our independent petroleum engineering firm. The following table sets forth our estimated proved reserves as of June 30, 2021. For additional reserve information see Note 20 to our consolidated financial statements in Item 8.
Reserve Category - Delhi field Oil
(MBbls) NGLs
(MBbls) Natural Gas
(MMcf) Total Reserves
(MBOE)*
PROVED
Developed Producing (79% of Proved) 4,879 1,784 — 6,663
Undeveloped (21% of Proved) 1,605 209 — 1,814
TOTAL PROVED 6,484 1,993 — 8,477
Product Mix 76 % 24 % — % 100 %
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
Hamilton Dome - Historical, Low Decline Waterflood - Hot Springs County, Wyoming
On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field. The Hamilton Dome field is located in the southwest part of the Big Horn Basin in northwest Wyoming about twenty miles northwest of Thermopolis in Hot Springs County.
Our interest includes a 23.5% working interest and an associated 19.7% revenue interest (inclusive of a small overriding royalty interest) in the approximately 3,160 acre unitized field. The Hamilton Dome field has been operated by Merit since 1995. Under Merit's operations, the wells in the Hamilton Dome field are produced using secondary recovery water flood methods via electric submersible pumps (ESP) and rod pumps. Typical workovers in the field include rod repair, ESP repair, injector acid jobs, and wellbore cleanouts.
The Hamilton Dome field was discovered in 1918 and has produced over 160 MMBO. Production from this field is 100% oil and is currently averaging low single-digit decline rates. The primary producing reservoirs in the field are the Tensleep and Phosphoria with an approximate depth of 3,000 feet. Average gross daily production was 1,987 BOPD for the year ended June 30, 2021. Produced oil from the field is subject to Western Canadian Select pricing.
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At June 30, 2021, the Company has total net proved reserves of 1.9 MMBOE at Hamilton Dome which was entirely comprised of oil as estimated by our independent reservoir engineering firm. The following table sets forth our estimated proved reserves as of June 30, 2021 for our Hamilton Dome field. For additional reserve information see Note 20 to our consolidated financial statements in Item 8.
Reserve Category - Hamilton Dome field Oil
(MBbls) NGLs
(MBbls) Natural Gas
(MMcf) Total Reserves
(MBOE)*
PROVED
Developed Producing (100% of Proved) 1,851 — — 1,851
Undeveloped (0% of Proved) — — — —
TOTAL PROVED 1,851 — — 1,851
Product Mix 100 % — % — % 100 %
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
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Barnett Shale - Mature, Low Decline Natural Gas Production - North Texas
On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale from TG Barnett Resources, LP, a wholly owned subsidiary of Tokyo Gas Americas, Ltd. The acquired assets consist 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 Barnett Shale.
Our interest includes an average working interest of 17.3% and associated average revenue interest of 14.2%. At the time of acquisition, approximately 90% of the wells acquired were operated by Blackbeard, while the remaining 10% were operated by seven other operators. After the close of the Barnett Shale Acquisition, Blackbeard announced the sale of its interests to Diversified Energy, which closed in July 2021.
The Barnett Shale was discovered as a natural gas resource play in the Newark East field in 1981; following completions of technology advancements in the 1990s, development of the Barnett Shale began in earnest in 1998. The majority of the wells included in our Barnett Shale assets were completed between 2007 and 2010 and are horizontals. The assets are characterized by mature, low-decline production. Average net daily production from the acquisition date of May 7, 2021 to June 30, 2021, was 4.3 MBOE per day. Commodities produced from our Barnett Shale assets include natural gas, oil and NGLs that are sold to Gulf Coast markets.
At June 30, 2021, the Company has total net proved reserves of 13.1 MMBOE in the Barnett Shale which is comprised of natural gas and NGLs with a small amount of oil, as estimated by our independent reservoir engineering firm. The following table sets forth our estimated proved reserves as of June 30, 2021 for our Barnett Shale assets. For additional reserve information, see Note 20 to our consolidated financial statements in Item 8.
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Reserve Category - Barnett Shale field Oil
(MBbls) NGLs
(MBbls) Natural Gas
(MMcf) Total Reserves
(MBOE)*
PROVED
Developed Producing (100% of Proved) 85 4,879 48,571 13,059
Undeveloped (0% of Proved) — — — —
TOTAL PROVED 85 4,879 48,571 13,059
Product Mix 1 % 37 % 62 % 100 %
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues
The 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 2021
Our proved reserves at June 30, 2021, denominated in barrels of oil equivalent (BOE) using six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio, were estimated by our independent reservoir engineer, DeGolyer and MacNaughton (“D&M”) which was formed in 1936. D&M has completed more than 23,000 projects in more than 100 countries. D&M was selected to estimate reserves primarily due to their expertise in CO 2 -EOR projects and to ensure consistency with the operator of the Delhi field. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.1 to this Annual Report on Form 10-K.
The following table sets forth our estimated proved reserves as of June 30, 2021. For additional reserve information, see Note 20 to our consolidated financial statements in Item 8. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $49.72 per barrel of oil and $2.46 per MMBtu of natural gas. The net price per barrel of NGLs was $19.81, which does not have any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used comparable pricing in the geographic area. Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product.
Reserves as of June 30, 2021
Reserve Category - Combined Oil
(MBbls) NGLs
(MBbls) Natural Gas
(MMcf) Total Reserves
(MBOE)*
PROVED
Developed Producing (92% of Proved) 6,815 6,663 48,571 21,573
Undeveloped (8% of Proved) 1,605 208 — 1,813
TOTAL PROVED 8,420 6,871 48,571 23,386
Product Mix 36 % 29 % 35 % 100 %
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
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The following table presents a reconciliation of changes in our proved reserves by major property, on the basis of equivalent MBOE quantities.
Reconciliation of Changes in Proved Reserves by Major Property
Delhi Field Proved
Total
Proved reserves, MBOE MBOE
June 30, 2020 8,746
Purchases —
Production (504)
Revisions (a) 235
Sales of minerals in place —
Improved recovery, extensions and discoveries —
June 30, 2021 8,477
(a) Positive revisions of 235 MBOE at Delhi field reflect operating cost reductions and improved NGL differential extending the reserves life of the field.
Hamilton Dome Field Proved
Total
Proved reserves, MBOE MBOE
June 30, 2020 1,473
Purchases —
Production (143)
Revisions (a) 521
Sales of minerals in place —
Improved recovery, extensions and discoveries —
June 30, 2021 1,851
(a) Positive revisions of 521 MBOE reflect improved trailing twelve month SEC pricing and differentials, reactivation of shut-in production throughout the year, and reduced operating expenses. These factors resulted in wells remaining economic longer, extending the reserves life of the field.
Barnett Shale Field Proved
Total
Proved reserves, MBOE MBOE
June 30, 2020 —
Purchases 13,299
Production (240)
Revisions —
Sales of minerals in place —
Improved recovery, extensions and discoveries —
June 30, 2021 13,059
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company'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 President and Chief Executive Officer, Jason Brown, who has over 20 years of experience in the energy industry and is a Registered Professional Engineer (Petroleum) in the State of Texas. He earned his B.S. degree in chemical engineering from the University of Tulsa and his M.B.A. from the Mendoza School of
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Business at the University of Notre Dame. Such reserves estimates comply with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.
The reserves information in this filing is based on estimates prepared by D&M. The person responsible for the preparation of the reserve report is a Senior Vice President and Division Manager of North America at D&M. He received a Bachelor 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 gas reservoir studies and evaluations.
We provide D&M with our property interests, production, current operating costs, current production prices, and other information in order to prepare the reserve estimates. This information is reviewed by our President and Chief Executive Officer, designated operations personnel, and other members of management to ensure accuracy and completeness of the data prior to submission to D&M. The scope and results of D&M's procedures, as well as their professional qualifications, are summarized in the letter included as Exhibit 99.1 to this Annual Report on Form 10-K.
Proved Undeveloped Reserves
Our proved undeveloped reserves were 1,813 MBOE at June 30, 2021, with associated future development costs of approximately $8.6 million, which are associated with the Phase V development of Delhi field. The Company does not have any proved undeveloped reserves associated with its Hamilton Dome field or Barnett Shale asset.
During the year ended June 30, 2021 our proved undeveloped reserves changed as follows:
Oil
(MBbls) NGLs
(MBbls) Natural Gas
(MMcf) Total Reserves
(MBOE)
June 30, 2020 1,648 216 — 1,864
Revisions to previous estimates (43) (8) — (51)
Conversion to proved developed reserves — — — —
June 30, 2021 1,605 208 — 1,813
Fiscal year 2020 price declines resulted in a reclassification of a small volume of oil reserves from PDP to PUD at June 30, 2020. The decline in price led to currently producing wells becoming uneconomic at an earlier point in time than previously estimated. Due to the EOR unit nature of Delhi, this PDP reduction shifts those reserves to our PUD oil reserves as they are considered proved and expected to be recovered as a result of the development of our Phase V project. During fiscal year 2021, we experienced reductions in expenses and improvement of the NGL differential at Delhi which extended the economic life of the PDP reserves. This caused a revision to PUD reserves by shifting them from PUD to PDP. Additionally, changes to Phase V development timing, as further discussed below, have slightly decreased PUD reserves.
The initial assignment of proved undeveloped reserves in the Delhi field was made on June 30, 2010, which encompassed a large-scale CO 2 enhanced oil recovery project. The operator’s original development plans for the field to be completed by June 30, 2015, within five years from the initial recording of such proved reserves, has not proceeded as originally scheduled as a result of the adverse fluid release event in the field in June 2013 and the resulting delay in reversion of our working interest. Expansion of the CO 2 flood to the remaining undeveloped eastern portion of the field commenced subsequent to reversion of our working interest in late calendar 2014 but was electively deferred by the operator shortly thereafter due to reductions in its cash flows and capital spending from the significant drop in oil prices. This project was further electively deferred as we began work on the NGL recovery plant field in February 2015. It was determined that the economics of development of the remaining eastern portion of the field would be significantly improved after the NGL plant was completed.
Authorization for construction of the NGL plant project occurred in fiscal 2015 and was completed in December 2016. Since completion of the plant, we have resumed work that had been suspended in late 2014 and further deferred until the NGL recovery plant was complete, including construction of the six-well water curtain program and related infrastructure required to precede the development of Phase V. All injection wells have been completed and injections from the second pad began in second quarter of fiscal 2020.
As of June 30, 2021, we have estimated total future net capital expenditures of approximately $8.6 million for remaining development of Phase V in the eastern part of the field, which we expect to commence in fiscal year 2023, however the timing is dependent on the field operator's available funds, capital spending plans, and priorities within its portfolio of properties.
We have been continuously developing the Delhi field and have spent over $48 million subsequent to reversion of our working interest in November 2014. Given the long-term nature of CO 2 EOR development projects, we believe that the remaining undeveloped reserves in the Delhi field satisfy the conditions to continue to be treated as proved undeveloped reserves because (1) we initially established the development plan for the Delhi field in 2010 and continue to follow that plan, as adjusted to
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incorporate the completion of the NGL plant in late 2016 and delays relating to the 2013 adverse fluid release event; (2) we have had significant ongoing development activities at this project that, as budgeted and currently being expended, reflect a significant and sufficient portion of remaining capital expenditures to convert proved undeveloped reserves to proved developed reserves; and (3) the operator has a historical record of completing the development of comparable long-term projects.
As of June 30, 2021, no proved reserves were attributed to (a) the area beneath the inhabited portion of the town of Delhi in the northeast and (b) the farthest east of the two remaining undeveloped sites in the eastern portion of the field (Phase VI) due to the current economics and other technical aspects of our future development plans. In addition, no proved reserves are currently attributed to three smaller reservoirs within the Unit in similar formations with similar production history due to the lower oil price utilized in our reserves calculation. We also do not have any proved reserves associated with our interests in the Mengel Sand, a separate interval within the Unit that is not currently producing, but has produced oil in the past.
Sales Volumes, Average Sales Prices and Average Production Costs
The following table shows the Company's sales volumes and average sales prices received for oil, NGLs, and natural gas for the periods indicated:
Year Ended
June 30, 2021 Year Ended
June 30, 2020 Year Ended
June 30, 2019
Product Volume Price Volume Price Volume Price
Oil (Bbls) 554,888 $ 47.60 638,464 $ 44.76 626,879 $ 65.05
NGL (Bbls) 171,451 $ 21.36 106,159 $ 9.59 112,013 $ 21.87
Natural gas (Mcf) 963,496 $ 2.73 1,087 $ 1.90 459 $ 2.64
Average price per BOE* 886,922 $ 36.87 744,804 $ 39.74 738,968 $ 58.50
Production costs Amount per BOE Amount per BOE Amount per BOE
Production costs, excluding ad valorem and production taxes $ 15,414,166 $ 17.38 $ 12,966,923 $ 17.41 $ 14,027,461 $ 18.98
Total production costs, including ad valorem and production taxes $ 16,587,052 $ 18.70 $ 13,505,502 $ 18.13 $ 14,266,784 $ 19.31
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
Drilling Activity
Our productive drilling activity at Delhi field during the past three fiscal years ended June 30, 2021, was limited to five (1.2 net) producer wells completed in fiscal 2019. We completed one (0.24 net) CO 2 injection well during fiscal 2019. No dry wells were drilled in the past three fiscal years. There were no new wells drilled in fiscal 2020 or fiscal 2021.
In connection with establishing a six-well water curtain on two pads in advance of Phase V site development, during fiscal 2019 our operator drilled two (0.48 net) wells and completed three (0.72 net) wells. A pad consists of one gross water source well and two gross water injector wells. The northern pad commenced injection during fiscal 2019 and the southern pad became fully operational late in the second quarter of fiscal 2020 when capital expenditures for completion work concluded.
Barnett Shale acreage contains potential drilling locations; however, they are not included within our proved reserves as of June 30, 2021. Diversified Energy has recently acquired the assets and has not yet formalized a capital drilling budget for fiscal year 2022.
Hamilton Dome field is considered fully developed. No wells were drilled in fiscal 2021, and there are no plans to drill wells in fiscal 2022.
Present Activities
Starting in late third quarter 2021, the operator of the Delhi field resumed some capital conformance work to recomplete existing wells into different production zones, including recompleting a temporarily abandoned well in Test Site V. This work is still ongoing and too early to quantify the impact of these projects on the patterns. There are no significant drilling plans until Phase V development, expected to commence in 2023.
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The Hamilton Dome operator is performing expense workovers within the field to maintain production and expects to plug four wells in first half of fiscal year 2022. There are currently no capital projects proposed within the field for fiscal year 2022.
The primary Barnett Shale operator has recently taken over as operator and has yet to formalize a budget, however they have expressed interest in identifying and performing remedial workovers to maintain and restore production.
For further discussion, see “Highlights for our fiscal year 2021” and “Capital Expenditures” within Item 7.
Delivery Commitments
As of June 30, 2021, we were not committed to provide a fixed and determinable quantity of oil, NGLs, or natural gas under existing agreements, nor do we currently intend to enter into any such agreements.
Productive Wells
The following table sets forth the number of productive oil and gas wells in which we own a working interest as of June 30, 2021.
Company Operated Non-Operated Total
Gross Net Gross Net Gross Net
Oil — — 326 77 326 77
Natural gas — — 1,074 186 1,074 186
Total — — 1,400 263 1,400 263
Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2021. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would allow production of oil and 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 gas in commercial quantities whether or not the acreage contains proved reserves.
Field (1) 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
Hamilton Dome Field, Wyoming 5,908 1,389 — — 5,908 1,389
Barnett Shale, Texas 123,777 20,918 — — 123,777 20,918
Total(2) 138,811 24,487 4,510 1,077 143,321 25,564
(1) 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 later fiscal 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.
When the Company acquired the Delhi field in 2003, the field had been fully developed through primary and secondary recovery methods and all of such acreage was reflected as developed acreage. With the addition of a CO 2 -EOR project in the field, certain acreage is now reflected as undeveloped, due to the transition to using tertiary recovery methods. We estimate that our developed acreage currently includes 9,126 gross (2,180 net) acres in the Delhi field, with approximately 4,510 gross (1,077 net) acres attributable to the remaining undeveloped areas in the eastern part of the field.
At the Delhi field, our interests include all depths from the ground surface to the top of the Massive Anhydride. These depth rights include the Delhi Holt Bryant Unit (Tuscaloosa and Paluxy formations) which is currently under CO 2 flood, and the Mengel Sand Interval which is within the boundary of the field but is currently not producing. As the Delhi field is unitized per the State of Louisiana Department of Conservation order number 96-G-5, all acreage, including any undeveloped, non-productive or undrilled acreage is held by existing production as long as continuous production is maintained in the unit.
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When the Company acquired its interests in the Hamilton Dome field on November 1, 2019, the field had been fully developed through primary recovery and therefore all acreage is reflected as developed acreage. The Tensleep and Phosphoria were permitted for commingling and unitized in 1996 following purchase of the field by Merit Energy in 1995. The Company estimates that our developed acreage includes 5,908 gross (1,389 net) acres in the Hamilton Dome field, with no acres attributable as undeveloped. As Hamilton Dome is unitized, all acreage is held by existing production as long as continuous production is maintained in the unit.
The Company acquired the Barnett Shale field on May 7, 2021, which is currently being developed through primary recovery. The Company estimates that our developed acreage includes 123,777 gross (20,918 net) acres in the Barnett Shale field, with no acres attributable as undeveloped.
For more complete information regarding current year activities, including oil and natural gas production, refer to Item 7.
Markets and Customers
Our production is marketed to third parties in a manner consistent with industry practices. In the United States of America market where we operate, oil, natural gas, and NGLs are readily transportable and marketable. We do not currently market our share of oil, natural gas, or NGLs production from the Delhi field, the Barnett Shale or from the Hamilton Dome field separately from the operators' shares of production. Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts. Under such arrangements, we typically do not know the identity of the buyers of production except in the case of the Delhi field where there is a sole buyer for oil and another for NGL's, and in the case of the Barnett Shale where there is a sole buyer for approximately all of the natural gas.
The oil from Delhi is currently transported from the field by pipeline, which results in better net pricing than the alternative of transportation by truck. Delhi oil production sells at Louisiana Light Sweet (“LLS”) pricing which generally trades at a premium to West Texas Intermediate (“WTI”) oil pricing. However, due to global market conditions, this premium was reduced during fiscal year ended 2021 versus fiscal year 2020. The LLS Gulf Coast average price differential over WTI, as quoted daily on the New York Mercantile Exchange (“NYMEX”), was approximately $1.75 during our fiscal year ended June 30, 2021, compared to $3.70 for the prior year. In the current fiscal year, the differential was impacted by market conditions over the fiscal year. NGL production is sold to a midstream processing company that fractionates the stream and sells the resulting hydrocarbons. The NGL revenues we receive are substantially reduced when the field oil realized price falls below $60 due to a capital recovery agreement with the operator; however, the impact is partially offset by corresponding reduced gas plant operating expense.
On November 1, 2019, Evolution acquired a non-operated interest in the Hamilton Dome field in Wyoming. All the field’s production is sour heavy oil which is the sole component of the field’s reserves. Oil is transported by pipeline primarily to purchasers in Casper, Wyoming. As a result of transportation differentials, the high sulfur content and low API gravity, this oil trades at a discount to WTI, averaging $9.60 lower for the year ended June 30, 2021, and $17.62 lower for the eight months ended June 30, 2020. Although we have the option of taking our production in-kind, we have elected to have the operator market our share of production. Our realized price is net of transportation and marketing costs.
On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale field in North Texas. The asset's production has various zones of wet and dry gas. The wet gas is gathered and transported by pipeline to a processing facility to process the wet gas into NGL components, oil condensate, and residue gas. Although we have the option of taking our production in-kind, we have elected to have the operator market our share of production.
The following table sets forth purchasers of our oil, natural gas, and NGL production for the years indicated:
Year Ended June 30,
Customer 2021 2020
Plains Marketing L.P. (Delhi field oil) 62 % 87 %
Merit Energy Company (Hamilton Dome field oil) 19 % 10 %
All others 19 % 3 %
Total 100 % 100 %
As the purchase of the Barnett Shale occurred on May 7, 2021, the Company expects purchases of our natural gas and NGL production from the Barnett Shale to represent a larger percentage of total sales in fiscal year 2022 and beyond. The loss of a purchaser at the Delhi field, Barnett Shale, or the Hamilton Dome field or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.
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Market Conditions
Prices we receive for oil, natural gas, and NGLs 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 few years have fluctuated widely and been extremely volatile. For example, average daily prices for WTI oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel over our last two fiscal years. The price of oil per barrel dropped substantially in fiscal 2020 as a result of the impact of the COVID-19 pandemic and geopolitical factors but recovered to average above $66 per barrel during the fiscal fourth quarter of 2021. The severe drop in oil price during the pandemic and market share competition between OPEC+ members in the Spring of 2020 substantially and adversely impacted oil, gas, and NGL prices during the balance of 2020, thus impacted the trailing twelve-month commodity prices required for reserves and ceiling tests for asset carrying value which in 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, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, influence prices for oil, natural gas, and NGLs. Local factors also influence prices for 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 oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staff and greater capital 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 areas and geologic systems and the ability to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves, and obtain capital at rates that allow economic investments.
Risk Management
Derivative 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 have designed a risk management policy to use derivative instruments from time to time during periods of extraordinary price volatility and when such instruments are needed to ensure the Company can meet its current dividend policy, fund its capital expenditures commitments, and maintain liquidity. We determine the duration of derivative positions to approximate the anticipated period of volatility and the percentage of our production to be hedged based on our view of current and future market conditions. We do not enter into derivative contracts for speculative trading purposes.
While there are many different types of derivatives available, we typically use fixed-price swaps and costless collars to attempt to manage price risk. 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. 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.
During fiscal 2020, we entered into NYMEX WTI oil swaps that covered approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel. As of June 30, 2021, we did not have any open fixed-price swaps or costless collars. In the future, we may add additional swaps or other derivative positions covering a variable portion of our anticipated future production during subsequent periods.
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. For the year ended June 30, 2021, we did not post collateral under any of our derivative contracts as they are uncollateralized trades. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A and Note 18 to our consolidated financial statements in Item 8 for additional information.
Government Regulation
Numerous federal and state laws and regulations govern the oil and natural gas industry, including environmental laws and regulations. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory environment is often difficult and costly; substantial penalties may be incurred for
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noncompliance. To the best of our knowledge, we are in compliance with all federal and state-level laws and regulations applicable to our operations. 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. We do not currently anticipate that continued and future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.
See discussion captioned “Government regulation and liability for oil and gas operations and environmental matters may adversely affect our business and results of operations” in Item 1A.
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 general liability, excess liability, control of well, operators extra expense, casualty, fraud, and directors and 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 lost profits coverage, and we do not have coverage for consequential damages.
Employment
At June 30, 2021, we had five 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 believes that it has good relations with its 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.
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”). 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 (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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