Item 2. Properties
Item 2.
PROPERTIES.
Our executive offices, as well as offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company are located in
leased premises in Houston, Texas.
We maintain district offices in Midland, Texas and Oklahoma City, Oklahoma and have field offices in
Carrizo Springs and Midland, Texas, and Elmore City, Oklahoma.
Substantially all of our oil and gas properties are subject to a mortgage
given to collateralize indebtedness or are subject to being mortgaged upon request by our lenders for additional collateral.
The
information set forth below concerning our properties, activities, and oil and gas reserves include our interests in affiliated entities.
The following table sets forth the exploratory and development drilling experience with respect to wells in which we participated during the
three years ended December 31, 2020. In 2020, we participated in seven new horizontal wells, however, only one well was completed in 2020, and the remaining six wells are to be completed in 2021.
2020
2019
2018
Gross
Net
Gross
Net
Gross
Net
Exploratory:
Oil
Gas
Dry
Development:
Oil
1
0.1
18
1.6
28
6.1
Gas
Dry
Total:
Oil
1
0.1
18
1.6
28
6.1
Gas
Dry
1
0.1
18
1.6
28
6.1
Oil and Gas Production
As of December 31, 2020, we had ownership interests in the following numbers of gross and net producing oil and gas wells (1) .
Gross
Net
Producing wells (1) :
Oil Wells
1,008
788
Gas Wells
273
99
(1)
A gross well is a well in which a working interest is owned. A net well is the sum of the fractional revenue
interests owned in gross wells. Wells are classified by their primary product. Some wells produce both oil and gas.
The
following table shows our net production of oil, NGL and natural gas for each of the three years ended December 31, 2020. Net production is net after royalty interests of others are deducted and is determined by multiplying the
gross production volume of properties in which we have an interest by percentage of the leasehold, mineral or royalty interest owned by us.
2020
2019
2018
Oil (barrels)
733,000
1,242,000
1,187,000
NGL (barrels)
437,000
574,000
463,000
Gas (Mcf)
3,381,000
4,397,000
3,735,000
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The following table sets forth our average sales prices together with our average production
costs per unit of production for the three years ended December 31, 2020.
2020
2019
2018
Average sales price per barrel of oil
$
38.02
$
55.04
$
60.46
Average sales price per barrel of NGL
$
11.22
$
15.87
$
27.79
Average sales price per Mcf of natural gas
$
1.24
$
1.49
$
2.30
Average production costs per net equivalent barrel of oil (1)
$
12.25
$
11.52
$
13.12
(1)
Net equivalent barrels are computed at a rate of 6 Mcf per barrel and costs exclude production taxes.
Average oil, NGL and gas prices received including the impact of derivatives were:
2020
2019
2018
Average sales price per barrel of oil
$
45.79
$
53.58
$
57.39
Average sales price per barrel of NGL
$
11.22
$
16.49
$
27.40
Average sales price per Mcf of natural gas
$
1.38
$
1.51
$
2.23
Acreage
The following table sets forth the approximate gross and net undeveloped acreage in which we have leasehold and mineral interests as of
December 31, 2020. Undeveloped acreage is that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage
contains proved reserves.
Developed
Undeveloped
Total
Gross
Net
Gross
Net
Gross
Net
Leasehold acreage
101,830
28,101
101,830
28,101
Mineral fee acreage
1,640
117
19,257
417
20,897
534
Total
103,470
28,218
19,257
417
122,727
28,635
Total Net Undeveloped Acreage Expiration
As of December 31, 2020, we have no acreage subject to expiration during the years ending 2021 through 2023.
Reserves
Our interests in proved
developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2020. The professional qualifications of the
technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrants Reserves Estimates. In matters related to the preparation of our
reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates
of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between
approximately twenty and thirty-five years of industry experience, and between eight and twenty-five years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation
of reserves estimates, has over thirty years of experience, holds a Bachelor degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. See Part II, Item 8
Financial Statements and Supplementary Data, for additional discussions regarding proved reserves and their related cash flows.
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All of our reserves are located within the continental United States. The following table
summarizes our oil and gas reserves at each of the respective dates:
Reserve Category
Proved Developed
Proved Undeveloped
Total
As of December 31,
Oil
(MBbls)
NGLs
(MBbls)
Gas
(MMcf)
Total
(MBoe)
Oil
(MBbls)
NGLs
(MBbls)
Gas
(MMcf)
Total
(MBoe)
Oil
(MBbls)
NGLs
(MBbls)
Gas
(MMcf)
Total
(MBoe)
2018
6,404
2,707
21,065
12,622
10
12
124
43
6,414
2,719
21,189
12,665
2019
4,381
2,914
19,995
10,268
1,833
1,017
4,547
3,608
6,214
3,931
24,542
14,235
2020
2,684
2,258
13,633
7,214
1,784
787
3,897
3,221
4,468
3,045
17,530
10,435
(a)
In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its
relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil.
In 2018, the Company drilled and completed 17 horizontal wells in West Texas and 11 horizontal wells in Oklahoma. In addition, the Company
added reserves through overriding royalty interest in 16 wells, primarily in Oklahoma and Texas. At year-end 2018, thirteen of the seventeen wells completed in 2018 were designated as Shut-In: eight located in our West Texas horizontal development program that were brought on production in February, 2019, and five in our Oklahoma Scoop-Stack development program, which were brought on production
in March, 2019.
At December 31, 2018, our reserve report included 43 MBoe of proved undeveloped reserves attributable to eight
horizontal wells that had been drilled but not yet been completed: three of these were completed in 2019, converting 24 Mboe of undeveloped reserves to proved developed, and four remained uncompleted as of December 31, 2020, which account for
18 Mboe of the 43 Mboe. The Company has 9% ownership in one of these four wells and less than 1% in three wells.
In 2019, in West Texas,
in addition to the eight wells classified as Shut-in at year-end 2018 that were brought on production in February, we participated in the drilling and completion of
three wells on our Kashmir tract: two wells with an average 49% interest, and a third well for 5.3% interest. One of each of these wells was completed in the Wolfcamp A, Jo Mill, and Lower Spraberry. All three wells were brought on
production in May of 2019.
In 2020, in West Texas we participated in the drilling of seven wells: one for 8.6% which was brought into
production in July of 2020, and six wells with an average 47.5% interest that were shut-in and are planned for completion in mid-2021 with production to start early in
the third quarter of 2021. The Company invested approximately $4.5 million in these seven wells in 2020. Also in 2020, reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we
receive 0.56% to 1% over-riding royalty interest.
In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and
completion of six wells on our WM Wallace tract for 7.67% interest, and nine wells, included on Slash, Osborn, and Leon tracts, with an average 1.34% interest. In addition, three wells drilled in Oklahoma in 2018, designated as proved undeveloped at
year-end 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma, six wells designated as Shut-in on December 31, 2018,
were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract.
In 2019, in our Gulf Coast region, we
added production through the recompletion of three vertical wells in Polk County, Texas: one operated by the Company in which we have 72.5% interest, and two operated by Unit Petroleum in which the Company owns 2.81% working interest and 3.77 net
revenue interest. In 2020, the Company successfully recompleted one additional operated well in the Segno field with a 72.5% interest.
At
December 31, 2020, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, three of which are new wells, spud in 2020 but not drilled until the first quarter of 2021 and 10 of which were drilled as
of year-end. The three new horizontals along with six uncompleted wells are located in Upton County, Texas and are in the process of being completed and we expect them to be placed on production by the end of
the second quarter of 2021. Apache Corporation is the operator of these wells. These nine PUD wells account for 3,127 Mboe of the total undeveloped reserves. The nine wells mentioned above are located on our 1,300 acre Kashmir tract in Upton County,
operated by Apache Corporation. Our average 47.5% share of the total cost of these nine horizontal wells will be approximately $26 million. The four remaining PUD wells, drilled but not completed, are located in Grady County, Oklahoma and
account for 95 Mboe of the total undeveloped reserves.
Additional drilling and future development plans will be
established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.
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We employ technologies to establish proved reserves that have been demonstrated to provide
consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well test
data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using
performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.
The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10%
discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2020, are summarized as follows (in thousands of dollars):
Proved Developed
Proved Undeveloped
Total
As of December 31,
Future Net
Revenue
Present
Value 10
Of Future
Net
Revenue
Future Net
Revenue
Present
Value 10
Of Future
Net
Revenue
Future Net
Revenue
Present
Value 10
Of Future
Net
Revenue
Present
Value 10
Of Future
Income
Taxes
Standardized
Measure of
Discounted
Cash flow
2018
$
239,337
$
161,376
$
767
$
525
$
240,104
$
161,901
$
23,992
$
137,909
2019
$
116,592
$
82,155
$
42,700
$
17,876
$
159,292
$
100,031
$
18,419
$
81,612
2020
$
43,886
$
34,717
$
37,346
$
21,823
$
81,232
$
56,539
$
14,920
$
41,619
The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas
reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (GAAP), we believe that the presentation of the PV10 Value is relevant and useful to investors
because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment
related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 Value versus the GAAP measure presented in the standardized measure of
discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved
oil and natural gas reserves after income tax, discounted at 10%.
Proved developed oil and gas reserves are reserves that can
be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are 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. Our reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of
our reserves.
In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month
average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity,
sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.
While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in
this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from
consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.
Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $1.985 per MMBtu in 2020 as
compared to $2.58 per MMBtu in 2019, and $3.10 per MMBtu in 2018. Oil prices, based on the NYMEX first of the month average price, were $39.57 per barrel in 2020 as compared to $55.69 per barrel in 2019, and $65.56 per barrel in 2018. Since
January 1, 2020, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.
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District Information
The following table represents certain reserve and well information as of December 31, 2020.
Gulf
Coast
Mid-
Continent
West
Texas
Other
Total
Proved Reserves as of December 31, 2020 (MBoe)
Developed
517
1,575
5,116
6
7,214
Undeveloped
95
3,126
3,221
Total
517
1,670
8,242
6
10,435
Average Daily Production (Boe per day)
297
788
3,178
2
4,265
Gross Productive Wells (Working Interest and ORRI Wells)
239
549
556
170
1,514
Gross Productive Wells (Working Interest Only)
209
485
518
69
1,281
Net Productive Wells (Working Interest Only)
124
217
263
2
606
Gross Operated Productive Wells
158
209
325
692
Gross Operated Water Disposal, Injection and Supply wells
9
53
6
68
In several of our producing regions we have field service groups to service our operated wells and locations
as well as third-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water
transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.
Gulf Coast Region
Our development,
exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, San Miguel, Olmos,
and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 239 producing wells (124 net) in the Gulf Coast region as of December 31, 2020, of which 158 wells are operated by us. Average net daily production in our Gulf Coast
Region in 2020 was 297 Boe. At December 31, 2020, we had 517 MBoe of proved reserves in the Gulf Coast region, which represented 5% of our total proved reserves. We maintain an acreage position of over 12,700 gross (5,120 net) acres in this
region, primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, nineteen water transport trucks, two saltwater disposal wells and several
trucks and excavating equipment. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and
locations. As of March 31, 2021, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.
Mid-Continent Region
Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our
office in Oklahoma City, Oklahoma. As of December 31, 2020, we had 549 wells (217 net) in the Mid-Continent area, of which 209 wells are operated by us. Principal producing intervals are in the Roberson,
Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. Average net daily production in our Mid-Continent Region
in 2020 was 788 Boe. At December 31, 2020, we had 1670 MBoe of proved reserves in the Mid-Continent area, or 16% of our total proved reserves. We maintain an acreage position of approximately 56,000 gross
(10,355 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties. We operate a field service group in this region from a field office in Elmore City, utilizing one workover rig and one saltwater hauling truck.
Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the Stack and Scoop plays of
Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, and Woodford formations. As of March 31, 2021, in the Mid-Continent region, the Company was participating in the completion
of four wells included as Proved Undeveloped in the 2020 year-end reserve report.
West Texas Region
Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. The Spraberry field was discovered in 1949,
encompasses eight counties in West Texas and the Company believes it is the largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet,
and the gas produced is casing-head gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from five intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700
feet to 11,300 feet. This
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region is managed from our office in Midland, Texas. As of December 31, 2020, we had 556 wells (263 net) in the West Texas area, of which 325 wells are operated by us. Principal producing
intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet. Average net daily production in Our West Texas Region in 2020 was 3,178 Boe. At December 31, 2020, we had 8,242 MBoe of proved
reserves in the West Texas area, or 79% of our total proved reserves. We maintain an acreage position of approximately 19,679 gross (12,461 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and
believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, four hot oiler trucks, one kill truck
and two roustabout trucks. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and locations.
At December 31, 2020, the Company was committed to participate with Apache Corporation in the drilling of three Proved Undeveloped
horizontal locations in Upton County, Texas and the completion of these along with six other wells drilled in 2020 on the same tract. The three new horizontals have been drilled and cased as of April 1, 2021. Completion operations for all nine
are scheduled for June 2021.
Item 3.
LEGAL PROCEEDINGS.
None.
Item 4.
MINE SAFETY DISCLOSURES.
Not applicable.
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PART II
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.