Item 2. Properties
ITEM 2. PROPERTIES
Coal Reserves
We must obtain permits from applicable regulatory authorities before beginning to mine particular reserves. For more information on this permitting process, and matters that could hinder or delay the process, please read "Item 1. Business—Environmental, Health and Safety Regulations— Mining Permits and Approvals ."
Our reported coal reserves are those we believe can be economically and legally extracted or produced at the time of the filing of this Annual Report on Form 10-K. In determining whether our reserves meet this economic and legal standard, we take into account, among other things, our potential ability or inability to obtain mining permits, the possible necessity of revising mining plans, changes in future cash flows caused by changes in estimated future costs, changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices.
At December 31, 2020, we had approximately 1.653 billion tons of coal reserves. These reserves are owned or held by the complexes they are most closely associated with or Alliance Resource Properties. Alliance Resource Properties has lease agreements with some of the complexes for certain reserves it owns or holds. All of the estimates of reserves which are presented in this Annual Report on Form 10-K are of proven and probable reserves (as defined below) and closely adhere to the standards described in United States Geological Survey ("USGS") Circular 831 and USGS Bulletin 1450-B. For information on the locations of our mines, please read "Coal Operations" under "Item 1. Business."
The following table sets forth reserve information at December 31, 2020 about our coal operations:
Mine
Heat
Status
Content (Btus
Pounds S02 per MMBtu
Classification
Reserve Assignment
Reserve Control
Operations (1)
(2)
per pound)
<1.2
1.2-2.5
>2.5
Total
Proven
Probable
Assigned
Unassigned
Owned
Leased
(tons in millions)
Illinois Basin Operations
Gibson South (IN)
A
11,500
0.6
13.6
40.4
54.6
46.7
7.9
54.6
—
18.2
36.4
Hamilton County (IL)
A
11,650
—
—
540.0
540.0
234.8
305.2
125.0
415.0
52.0
488.0
Henderson/Union (KY)
R
11,400
—
3.1
459.7
462.8
172.9
289.9
—
462.8
62.2
400.6
River View (KY)
A
11,450
—
—
223.9
223.9
124.9
99.0
223.9
—
63.5
160.4
Warrior (KY)
A
12,300
—
—
80.4
80.4
66.0
14.4
80.4
—
19.4
61.0
Dotiki (KY)
C
12,100
—
2.9
73.2
76.1
52.4
23.7
—
76.1
27.6
48.5
Hopkins (KY)
C
12,000
—
—
13.9
13.9
9.7
4.2
—
13.9
4.4
9.5
Sebree - Onton (KY)
I
11,750
—
—
40.3
40.3
22.6
17.7
40.3
—
0.2
40.1
Region Total
0.6
19.6
1,471.8
1,492.0
730.0
762.0
524.2
967.8
247.5
1,244.5
Appalachia Operations
MC Mining (KY)
A
12,600
12.7
1.8
—
14.5
10.2
4.3
14.5
—
0.2
14.3
Mettiki (MD)
A
13,200
—
1.6
3.8
5.4
5.3
0.1
—
5.4
—
5.4
Mettiki (WV)
A
13,200
—
6.4
9.0
15.4
10.2
5.2
9.6
5.8
1.6
13.8
Penn Ridge (PA)
R
12,500
—
—
61.5
61.5
16.7
44.8
61.5
—
61.5
—
Tunnel Ridge (WV)
A
12,600
—
—
64.0
64.0
31.7
32.3
64.0
—
—
64.0
Region Total
12.7
9.8
138.3
160.8
74.1
86.7
149.6
11.2
63.3
97.5
Total
13.3
29.4
1,610.1
1,652.8
804.1
848.7
673.8
979.0
310.8
1,342.0
% of Total
0.8%
1.8%
97.4%
100.0%
48.7%
51.3%
40.8%
59.2%
18.8%
81.2%
(1) Our mining operations, both active and inactive, contain underground mines
(2) A = Active, C = Closed, I = Idled, R = Reserves only
Our reserve estimates are prepared from geological data assembled and analyzed by our staff of geologists and engineers. This data is obtained through our extensive, ongoing exploration drilling and in-mine channel sampling programs. Our drill spacing criteria adheres to standards as defined by the USGS. The maximum acceptable distance from seam data points varies with the geologic nature of the coal seam being studied, but generally the standard for (a) proven reserves is that points of observation are no greater than ½ mile apart and are projected to extend as a ¼ mile wide belt around each point of measurement and (b) probable reserves is that points of observation are between ½ and 1 ½ miles apart and are projected to extend as a ½ mile wide belt that lies ¼ mile from the points of measurement.
Reserve estimates will change from time to time to reflect mining activities, additional analysis, new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other
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factors. We have historically obtained an outside audit of our reserve estimates and calculation methods every five years with the most recent audit being performed by Weir International Mining Consultants ("Weir") in July 2015. Weir is expected to perform this audit again during 2021 in advance of the SEC's new property disclosure requirements for mining companies.
Reserves represent that part of a mineral deposit that can be economically and legally extracted or produced, and reflect estimated losses involved in producing a saleable product. All of our reserves are thermal coal, except for reserves at Mettiki that can be delivered to the thermal or metallurgical markets. The 12.7 million tons of reserves listed at MC Mining as <1.2 pounds of SO 2 per MMBtus are marketable as compliance coal under Phase II of CAA. Btu values are reported on an as shipped, fully washed basis. Shipments that are either fully or partially raw will have a lower Btu value.
We own or control certain leases for coal deposits that do not currently meet the criteria to be reflected as reserves but may be reclassified as reserves in the future. These tons are classified as non-reserve coal deposits and are not included in our reported reserves. We have total non-reserve coal deposits of 289.2 million tons of which the Henderson/Union Reserves account for 157.4 million tons. Our remaining non-reserve coal deposits include the following: Dotiki—16.2 million tons, Elk Creek—7.8 million tons, Gibson South—1.7 million tons, Gibson North—21.4 million tons, Hamilton—33.7 million tons, Mettiki—1.0 million tons, Penn Ridge––15.9 million tons, Riverview—2.1 million tons, Sebree - Onton—4.6 million tons, Sebree—7.0 million tons, Tunnel Ridge—16.2 million tons and Warrior—4.2 million tons.
We lease most of our reserves and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal reserve area. These leases provide for royalties to be paid to the lessor at a fixed amount per ton or as a percentage of the sales price. Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if no mining activities have begun. These minimum royalties are normally credited against the production royalties owed to a lessor once coal production has commenced.
Mining Operations
The following table sets forth production and other data about our mining operations:
Tons Produced
Operations
Location
2020
2019
2018
Transportation
Equipment
(in millions)
Illinois Basin Operations
Dotiki (1)
Kentucky
—
1.3
2.5
CSX, PAL, truck, barge
CM
Gibson North (1)
Indiana
—
1.8
0.9
CSX, NS, truck, barge
CM
Gibson South
Indiana
2.3
5.5
6.9
CSX, NS, truck, barge
CM
Hamilton
Illinois
2.6
5.9
6.3
CSX, EVW, barge
LW, CM
River View
Kentucky
9.4
11.3
9.8
Truck, barge
CM
Warrior
Kentucky
3.6
3.7
3.5
CSX, PAL, truck, barge
CM
Region Total
17.9
29.5
29.9
Appalachia Operations
MC Mining
Kentucky
0.5
1.0
1.3
CSX, truck, barge
CM
Mettiki
WV, MD
1.8
2.1
2.3
CSX, truck
LW, CM
Tunnel Ridge
West Virginia
6.8
7.4
6.8
CSX, NS, barge
LW, CM
Region Total
9.1
10.5
10.4
TOTAL
27.0
40.0
40.3
(1) Closed
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CSX
-
CSX Railroad
EVW
-
Evansville Western Railroad
NS
-
Norfolk Southern Railroad
PAL
-
Paducah & Louisville Railroad
CM
-
Continuous Miner
LW
-
Longwall
Oil & Gas Reserves
Our mineral interests are primarily located in three basins, which are also our areas of focus for future development. These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) Basins. At December 31, 2020, we had approximately 41,000 developed and undeveloped net acres held at a weighted average royalty of 16.8%. Our net acres standardized to 1/8th royalty equates to approximately 55,500 net royalty acres, including approximately 3,988 net royalty acres owned through our equity interest in AllDale III.
The following table presents our estimated net proved oil & gas reserves, including our share of reserves owned through our equity interest in AllDale III, as of December 31, 2020 based on the reserve report prepared by our internal engineering team. The reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve report are located in the continental United States.
As of December 31, 2020
Crude Oil
Natural Gas
Natural Gas Liquids
Total
(MBbl)
(MMcf)
(MBbl)
(MBOE) (2)
Estimated proved developed reserves
5,073
23,505
2,252
11,244
Estimated proved undeveloped reserves
2,071
9,565
868
4,533
Total estimated proved reserves (1)
7,144
33,069
3,120
15,777
(1) Proved reserves of approximately 972 MBOE were attributable to noncontrolling interests as of December 31, 2020.
(2) Natural gas reserve volumes are converted to BOE based on a 6:1 ratio: 6 Mcf of natural gas converts to one BOE.
Estimates of reserves as of December 31, 2020 were prepared using product prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period from January through December 2020. The average realized product prices weighted by production over the remaining lives of the properties are $36.95/Bbl for oil, $0.88/Mcf of natural gas and $7.99 per barrel of NGL. These prices are adjusted for energy content, associated average differential and transportation deducts by producing area to arrive at the net realized prices by product. For 2020, NGL prices averaged approximately 26% of the posted oil prices during the course of the year with an additional $2.30/Bbl deducted for transportation costs.
The following table summarizes our changes in proved undeveloped reserves (in MBOE):
Beginning balance, January 1, 2020
3,110
Transfers of PUDs to estimated proved developed
(115)
Extensions and discoveries
1,221
Revisions of previous estimates
317
Ending balance, December 31, 2020
4,533
During the year ended December 31, 2020, we converted 115 MBOE of PUD reserves to proved developed reserves as applicable wells began production. Extensions and discoveries contributed 2,238 MBOE resulting in a net increase of 1,221 MBOE despite a reduction of 1,017 MBOE due to expired permits. Revisions of previous estimates of 317 MBOE is a result of type curve changes.
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As a mineral interest owner we have no transparency into or control over our operators' investments and operational progress to convert PUDs to proved developed producing reserves. We do not incur any capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by our operators. As a result, during the year ended December 31, 2020, we did not have any expenditures to convert PUDs to proved developed reserves. PUDs that have not been developed within two years of permitting are reviewed and removed from proved reserves as necessary. As of December 31, 2020, approximately 28.73% of our total proved reserves were classified as PUDs.
Evaluation and Review of Reserves
Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.
Under SEC rules, proved reserves are those quantities of oil & gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible–from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations–prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered." All of our proved reserves as of December 31, 2020 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil & gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil & gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods:
(1) performance-based methods,
(2) volumetric-based methods and
(3) analogy.
These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production data. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
To estimate economically recoverable proved reserves and related future net cash flows, our engineering team considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, and radioactivity logs.
Our 2020 year-end proved reserves were prepared by our internal engineering team. Our engineering team works to ensure the integrity, accuracy, and timeliness of the data used to calculate our estimated proved reserves. Approximately 95% of our total 2020 year end proved reserve estimates were audited by NSAI. Our engineering team met with NSAI periodically during the period covered by the above referenced reserve report to discuss the assumptions and methods used in the reserve estimation process. Our engineering team provided historical information to NSAI for our properties, such as oil & gas production, well test data, and realized commodity prices. Our engineering team also provided ownership interest information with respect to our properties. Our internal petroleum engineer, primarily responsible for overseeing the petroleum reserves preparation, has over 20 years of engineering and operations experience in the oil & gas sector and a Bachelor of Science in Petroleum Engineering.
The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
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● review and verification of historical data, which is based on actual production as reported by our operators;
● verification of property ownership by our land department;
● review of all our reported proved reserves semi-annually including the review of all significant reserve changes and proved undeveloped reserves additions by our internal petroleum engineer;
● internally prepared reserve estimates compared to reserves audit by NSAI;
● review of changes in reserves semi-annually by our internal petroleum engineer and by senior management; and
● no employee ' s compensation is tied to the amount of reserves booked.
NSAI, an independent third-party petroleum engineering firm, does not own an interest in any of our properties and is not employed on a contingent basis. When compared on a well-by-well basis, some of our estimates are greater and some are less than the NSAI estimates. NSAI is satisfied with our methods and procedures used to prepare the December 31, 2020 reserve estimates and future revenue, and noted nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, prepared by us. NSAI's audit report with the respect to our proved reserve estimates as of December 31, 2020 is included as an exhibit to this Annual Report on Form 10-K.
NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Acreage Concentration
Our mineral interests, which include both proved reserves discussed above and unproved reserves, are primarily located in three basins, which are also our areas of focus for future operator development. These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) Basins. Below is a chart reflecting our gross, net mineral and net royalty acreage associated with our mineral interests in each of our primary basins as of December 31, 2020.
Developed Acreage
Undeveloped Acreage
Gross
Net Mineral
Net Royalty
Gross
Net Mineral
Net Royalty
Basin
Permian Basin
207,026
4,382
5,626
569,554
14,817
19,364
Anadarko Basin
137,341
4,957
7,069
299,796
11,053
15,745
Williston Basin
102,530
1,706
2,230
124,486
1,931
2,538
Other
22,581
496
635
49,723
1,893
2,334
Total
469,477
11,541
15,560
1,043,560
29,693
39,980
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Oil & Gas Production Prices and Production Costs
For the year ended December 31, 2020, 50.1% of our production and 81.2% of our oil & gas revenues were related to oil production and sales, respectively. The following table sets forth information regarding production of oil & gas and certain price and cost information for each of the periods indicated:
Year Ended
December 31,
2020
2019
Production:
Oil (MBbls)
948
741
Natural gas (MMcf)
3,635
3,664
Natural gas liquids (MBbls)
337
364
BOE (MBbls)
1,892
1,716
Average Realized Prices:
Oil (per Bbl)
$
39.04
$
54.30
Natural gas (per Mcf)
$
1.52
$
2.01
Natural gas liquids (per Bbl)
$
9.08
$
20.17
BOE (MBbls)
$
24.10
$
32.02
Unit cost per BOE:
Production and ad valorem taxes
$
2.64
$
4.82
Productive Wells
As of December 31, 2020, 6,169 gross productive horizontal wells and 4,121 gross productive vertical wells were located on the acreage in which we have a mineral interest. Of our productive horizontal wells, 912 are considered natural gas wells, while the remaining 5,257 primarily produce oil. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. We do not own any material working interests in any wells. Accordingly, we do not own any net wells.
Drilling Results
As a holder of mineral interests, we generally are not provided with information as to whether any wells drilled on the acreage associated with our mineral interests are classified as exploratory or as developmental wells. We are not aware of any dry holes drilled on the acreage associated with our mineral interests during the relevant period.