The Company is affiliated by
common management and ownership with Mesquite Minerals, Inc. (Mesquite), Mid-American Oil Company (Mid-American), Lochbuie Limited
Partnership (LLTD) and Lochbuie Holding Company (LHC). The Company also owns interests in certain producing and non-producing oil
and gas properties as tenants in common with Mesquite, Mid-American and LLTD.
Mason McLain, a director of the
Company, is a director of Mesquite and Mid-American. Robert T. McLain and Jerry Crow, directors of the Company, are directors of
Mesquite and Mid-American. Kyle McLain and Cameron R. McLain are sons of Mason McLain, who owns more than 5% of the Company, and
are officers and directors of the Company. Kyle McLain and Cameron McLain are officers and directors of Mesquite and Mid-American.
Mason McLain and Robert T. McLain, who are brothers, each own an approximate 32% limited partner interest in LLTD, and Mason McLain
is president of LHC, the general partner of LLTD. Robert T. McLain is not an employee of any of the above entities and devotes
only a small amount of time conducting their business.
The above named officers, directors,
and employees as a group, beneficially own approximately 28% of the common stock of the Company, approximately 33% of the common
stock of Mesquite, and approximately 19% of the common stock of Mid-American. These three corporations, each, have only one class
of stock outstanding. See Item 8, Note 12 to the accompanying financial statements for additional disclosures regarding these relationships.
The Company had a 33% partnership
interest in Broadway Sixty-Eight, Ltd. (the “Partnership”) in 2012 and 2013, which it accounted for on the equity method.
In using the equity method, the Company records the original investment in an entity as an asset and adjusts the asset balance
for the Company’s share of any income or loss, as well as any additional contributions to or distributions from the entity.
The Company does not have actual or effective control of the Partnership. The management of the Partnership could, at any time,
make decisions in their own best interests that could affect the Company’s net income or the value of the Company’s
investment.
The Partnership has an indemnity
agreement under which the Company is contingently liable. See Item 8, Note 7 to the accompanying financial statements for related
disclosures and additional information regarding Broadway Sixty-Eight, Ltd.
LIQUIDITY AND CAPITAL RESOURCES
To supplement the following
discussion, please refer to the Balance Sheets and the Statements of Cash Flows included in this Form 10-K.
In 2013, as in prior years,
the Company funded its business activity through the use of internal sources of capital. For the most part, these internal sources
are cash flows from operations, cash, cash equivalents and available-for-sale securities. When cash flows from operating activities
are in excess of those needed for other business activities, the remaining balance is used to increase cash, cash equivalents and/or
available-for-sale securities. When cash flows from operating activities are not adequate to fund other business activities, withdrawals
are made from cash, cash equivalents and/or available-for-sale securities. Cash equivalents are highly liquid debt instruments
purchased with a maturity of three months or less. All of the available-for-sale securities are U.S. Treasury Bills.
In 2013, net cash provided
by operating activities was $12,258,084. Sales (including lease bonuses), net of production, general and administrative costs,
and income taxes paid were $12,218,843, which accounted for 99.7% of net cash provided by operations. The remaining components
provided less than 1% of cash flow. In 2013, net cash applied to investing activities was $10,246,949. In 2013, dividend payments
and treasury stock purchases totaled $2,088,940 and accounted for all of the cash applied to financing activities.
Other than cash and cash equivalents,
other significant changes in working capital include the following:
Trading securities increased
$197,373 (51%) to $586,708 in 2013 from $389,335 in 2012. Most of the increase is due to a $166,804 increase in unrealized gains,
which represent the change in the fair value of the securities from their original cost. The remaining increase of $30,569 represents
the 2013 income.
Refundable income taxes decreased
$181,457 (35%) to $336,620 in 2013 from $518,077 in 2012. This decrease was due to excess 2013 estimated tax payments being less
than in 2012.
Receivables increased $712,879
(41%) to $2,449,048 in 2013 from $1,736,169 in 2012. The increase was due to the use of increased product prices and volumes for
both oil and natural gas sales accrual estimates for year-end 2013 compared to 2012. Additional information about oil and natural
gas sales for 2013 is included in the “Results of Operations” section that follows.
Accounts payable decreased
$152,032 (29%) to $367,622 in 2013 from $519,654 in 2012. This decrease was primarily due to decreased drilling activity at the
end of 2013 compared to 2012.
Deferred income taxes and other
accrued liabilities increased $130,194 (63%) to $337,624 in 2013 from $207,430 in 2012. This increase was primarily due to the
increase in the current deferred tax accrual due to the increase in the oil and gas sales accrual in 2013.
The following is a discussion
of material changes in cash flow by activity between the years ended December 31, 2013 and 2012. Also, see the discussion of changes
in operating results under “Results of Operations” below in this Item 7.
Operating Activities
As noted above, net cash flows
provided by operating activities in 2013 were $12,258,084, which, when compared to the $10,454,012 provided in 2012, represents
a net increase of $1,804,072 or 17%. The increase was mostly due to an increase in oil and gas sales cash flows of $4,723,598,
offset by lower lease bonuses and coal royalties of $1,922,985 and an increase in production costs of $562,326 and taxes of $421,900.
Additional discussion of the more significant items follows.
Discussion of Selected
Material Line Items Resulting in an Increase in Cash Flows.
The $4,723,598 (36%) increase in cash received from oil and
gas sales to $17,728,795 in 2013 from $13,005,197 in 2012 was the result of an increase in both the oil and gas sales volumes and
prices. See “Results of Operations” below for a price/volume analysis and the related discussion of oil and gas sales.
Discussion of Selected
Material Line Items Resulting in a Decrease in Cash Flows.
Cash received for lease bonuses and coal royalties decreased
$1,922,985 (84%) to $372,895 in 2013 from $2,295,880 in 2012. The decrease is due to a decrease in cash received for lease bonuses
of $1,593,692 and coal royalties of $329,293 in 2013 versus 2012. No coal was produced from the Company’s leases in 2013.
Cash paid for production costs
increased $562,326 (24%) to $2,952,670 in 2013 from $2,390,344 in 2012. This increase was mostly due to lease operating and handling
expense on new wells of about $379,000. The remaining increase was due to increased operating expense on previous wells and production
taxes. The increase in production taxes was due to the increase in sales in 2013 versus 2012.
Cash flow decreased due to
an increase in estimated income tax payments of $421,900 (47%) to $1,311,250 in 2013 from $889,350 in 2012. The higher payments
were mostly due to higher net income and current taxable income in 2013.
Investing Activities
Net cash applied to
investing activities increased $3,625,281 to $10,246,949 in 2013 from $6,621,668 of cash applied in 2012. This $3,625,280
increase was due primarily to a $3,258,946 increase in cash applied to exploration and development expenditures, including
$1,917,376 in December 2013 for some producing properties and leasehold. See the “Exploration and Development
Costs” section in the “Results of Operations” section below for more information about this acquisition.
The remaining significant increase in cash applied to investing activities pertains to the decrease in proceeds from property
disposals. This line item decreased $368,153 (74%) to $131,400 in 2013 from $499,553 in 2012. This decrease was the result of
fewer sales of Kansas and Oklahoma non-producing leaseholds in 2013 compared to 2012.
Financing Activities
Cash applied to financing activities
decreased $1,051,835 (33%) to $2,088,940 in 2013 from $3,140,775 in 2012. Cash applied to financing activities consist of cash
dividends on common stock and cash used for the purchase of treasury stock. In 2013, cash dividends paid on common stock amounted
to $1,767,613 as compared to $3,100,835 in 2012. Dividends of $10.00 per share were paid for 2013 and $20.00 per share for 2012.
This $1,333,222 decline in dividends paid was offset by a $281,387 increase in cash applied to purchase treasury stock.
Forward-Looking Summary
The Company’s latest
estimate of business to be done in 2014 and beyond indicates the projected activity can be funded from cash flow from operations
and other internal sources, including net working capital. The Company is engaged in exploratory drilling. If this drilling is
successful, substantial development drilling may result. Also, should other exploration projects which fit the Company’s
risk parameters become available or other investment opportunities become known, capital requirements may be more than the Company
has available. If so, external sources of financing could be required.
RESULTS OF OPERATIONS
As disclosed in the Statements
of Income in Item 8 of this Form 10-K, in 2013 the Company had net income of $6,068,042 as compared to a net income of $4,553,845
in 2012. Net income per share, basic and diluted, was $37.90 in 2013, an increase of $9.60 per share from $28.30 in 2012. Material
line item changes in the Statements of Income will be discussed in the following paragraphs.
Operating Revenues
Operating revenues increased
$3,678,292 (24%) to $18,812,673 in 2013 from $15,134,381 in 2012. Oil and gas sales increased $5,494,876 (42%) to $18,443,984 in
2013 from $12,949,108 in 2012. Lease bonuses and other revenues decreased $1,816,584 to $368,689 in 2013 from $2,185,273 in 2012.
This decrease was the result of a decrease in lease bonuses of $1,593,692 primarily from leases in Texas. In addition, coal royalties
from North Dakota leases declined $222,893 (99%) to $1,443 in 2013 from $224,336 in 2012. The increase in oil and gas sales is
discussed in the following paragraphs.
The $5,494,876 increase in
oil and gas sales was the result of a $1,889,973 increase in gas sales, a $3,597,493 increase in oil sales and a $7,410 increase
in miscellaneous oil and gas product sales. The following price and volume analysis is presented to explain the changes in oil
and gas sales from 2013 to 2012. Miscellaneous oil and gas product sales of $362,263 in 2013 and $354,853 in 2012 are not included
in the analysis.
|
|
|
|
|
Variance
|
|
|
|
|
Production
|
|
2013
|
|
|
Price
|
|
|
Volume
|
|
|
2012
|
|
Gas –
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MCF (000 omitted)
|
|
|
1,459
|
|
|
|
|
|
|
|
331
|
|
|
|
1,128
|
|
$ (000 omitted)
|
|
$
|
5,129
|
|
|
$
|
939
|
|
|
$
|
951
|
|
|
$
|
3,239
|
|
Unit Price
|
|
$
|
3.51
|
|
|
$
|
0.64
|
|
|
|
|
|
|
$
|
2.87
|
|
Oil –
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls (000 omitted)
|
|
|
142
|
|
|
|
|
|
|
|
35
|
|
|
|
107
|
|
$ (000 omitted)
|
|
$
|
12,953
|
|
|
$
|
551
|
|
|
$
|
3,047
|
|
|
$
|
9,355
|
|
Unit Price
|
|
$
|
90.97
|
|
|
$
|
3.87
|
|
|
|
|
|
|
$
|
87.10
|
|
The $1,889,973 (58%) increase
in natural gas sales to $5,128,702 in 2013 from $3,238,729 in 2012 was the result of an increase in both gas sales volumes and
the average price received per thousand cubic feet (MCF). The average price per MCF of natural gas sales increased $0.64 per MCF
to $3.51 in 2013 from $2.87 per MCF in 2012, resulting in a positive gas price variance of $939,323. A positive volume variance
of $950,650 was the result of an increase in natural gas volumes sold of 331,237 MCF to 1,459,622 MCF in 2013 from 1,128,385 MCF
in 2012. The increase in the volume of gas production was the net result of new 2013 production of about 367,000 MCF, offset by
a decline of about 36,000 MCF in production from previous wells. As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental
Financial Information included in Item 8 below, working interests in natural gas extensions and discoveries were adequate to replace
working interest reserves produced in 2012 but not in 2013.
The gas production for 2012 and
2013 includes production from about 100 royalty interest properties drilled by various operators in Robertson County, Texas. These
properties accounted for approximately 387,000 MCF and $965,000 of the 2012 gas sales and approximately 370,000 MCF and $1,257,000
of the 2013 gas sales. These properties accounted for about 30% of the Company’s 2012 gas revenues compared to 25% of 2013
gas revenues. The Company has no control over the timing of future drilling on the acreage in which we hold mineral interests.
However, if natural gas prices continue to recover, the Company expects that drilling activity in Robertson County will increase
also.
The $3,597,493 (38%) increase
in crude oil sales to $12,953,019 in 2013 from $9,355,526 in 2012 was the result of an increase in the average price per barrel
(Bbl) and an increase in oil sales volumes. The average price received per Bbl of oil increased $3.87 to $90.97 in 2013 from $87.10
in 2012, resulting in a positive oil price variance of $550,969. An increase in oil sales volumes of 34,977 Bbls to 142,384 Bbls
in 2013 from 107,407 Bbls in 2012 resulted in a positive volume variance of $3,046,524. The increase in the oil volume production
was the net result of new 2013 production of about 49,300 Bbls, offset by a 14,300 Bbl decline in production from previous wells.
Of the new 2013 production, approximately 12,200 Bbls (25%) was from Woods County, Oklahoma; about 17,500 Bbls (35%) was from new
working interest wells in Oklahoma (in counties other than Woods); 9,000 Bbls (18%) was from new royalty interest wells in Oklahoma;
and about 10,600 Bbls (22%) was from new royalty interest and working interest wells in Arkansas, Kansas, South Dakota and Texas.
As disclosed in Supplemental Schedule 1 of the Unaudited Supplemental Financial Information included below in Item 8, working interests
in oil extensions and discoveries were adequate to replace working interest reserves produced in 2012 and 2013.
For both oil and gas sales, the
price change was mostly the result of a change in the spot market prices upon which most of the Company’s oil and gas sales
are based. These spot market prices have had significant fluctuations in the past and these fluctuations are expected to continue.
Operating Costs and Expenses
Operating costs and expenses
increased $1,746,348 (18%) to $11,239,428 in 2013 from $9,493,080 in 2012, primarily due to an increase in production and depreciation,
depletion and amortization expense. The material components of operating costs and expenses are discussed below.
Production
Costs.
Production costs increased $595,192 (25%) to $3,009,953 in 2013 from $2,414,761 in 2012. The increase was
the result of a $127,357 (23%) increase in gross production tax (net of production tax refunds) to $678,015 in 2013 from
$550,658 in 2012; an increase in lease operating expense of $265,036 (18%) to $1,729,973 in 2013 from $1,464,937 in 2012; and
an increase in handling expense of $202,799 (51%) to $601,965 in 2013 from $399,166 in 2012. Of the increase in lease
operating expense, $258,565 was the result of new wells with the remaining $6,471 due to an increase in expenses for existing
wells. Of the increase in handling expense, $120,227 was the result of new wells with the remaining $82,572 due to an increase
in expenses for existing wells. Handling expense is comprised of gas gathering, treating, transportation, and compression
costs. Gross production taxes are state taxes, which are calculated as a percentage of gross proceeds from the sale of
products from each producing oil and gas property; therefore, they fluctuate with the change in the dollar amount of revenues
from oil and gas sales.
Exploration and Development
Costs.
Under the successful efforts method of accounting used by the Company, geological and geophysical costs are expensed
as incurred as are the costs of unsuccessful exploratory drilling. The costs of successful exploratory drilling and all development
costs are capitalized. Total costs of exploration and development, excluding asset retirement obligations but inclusive of geological
and geophysical costs, were $7,485,378 in 2013 and $7,197,753 in 2012. See Item 8, Note 8 to the accompanying financial statements
for a breakdown of these costs. Exploration costs charged to operations were $663,627 in 2013 and $316,465 in 2012, inclusive of
unsuccessful exploratory well costs of $199,144 in 2013 and $316,465 in 2012 and geological and geophysical costs of $464,483 in
2013, with no geological and geophysical costs in 2012.
Update of Oil and Gas
Exploration and Development Activity from December 31, 2012.
For the year ended December 31, 2013, the Company
participated in the drilling of 17 gross exploratory and 34 gross development working interest wells with working interests
ranging from a high of 18% to a low of 0.2%. Of the 17 exploratory wells, 10 were completed as producing wells, 5 as dry
holes and 2 were in progress. Of the 34 development wells, 32 were completed as producing wells and 2 were in progress. In
management’s opinion, the exploratory drilling summarized above has produced some possible development drilling
opportunities.
The following is a summary as
of February 28, 2014, updating both exploration and development activity from December 31, 2012, for the period ended December
31, 2013.
The Company participated with
its 18% working interest in the drilling of seven development wells on a Barber County, Kansas prospect. Four of these wells were
completed as commercial gas producers, one as a commercial oil and gas producer, one as a commercial oil producer and one as a
marginal oil producer. Three additional development wells will be drilled starting in March 2014. Capitalized costs for the period
were $655,584, including $47,912 in prepaid drilling costs.
The Company participated with
14%, 14%, 8% and 16% working interests in the drilling of four step-out wells on a Woods County, Oklahoma prospect. The first three
wells were completed as commercial oil and gas producers and a completion is in progress on the fourth. The Company will participate
with 16% and 8% working interests in the drilling of two additional step-out wells starting in March 2014. Capitalized costs for
the period were $363,120, including $71,757 in prepaid drilling costs.
The Company participated with
13.7% working interests in the drilling of three development wells and with a 17.9% interest in the drilling of a fourth on a Woods
County, Oklahoma prospect. All four of these wells were completed as commercial oil and gas producers. Capitalized costs for the
period were $425,106, including $28,073 in prepaid drilling costs.
The Company participated with
its 16% working interest in the drilling of a step-out well on a Woods County, Oklahoma prospect. The well was completed as a marginal
oil and gas producer. Capitalized costs were $75,340 for the period.
The Company participated with
its 16% working interest in the drilling of two step-out wells on a Hodgeman County, Kansas prospect. Both wells were completed
as commercial oil producers. Capitalized costs for the period were $172,286.
The Company participated with
its 8.3% interest in the drilling of two additional horizontal wells in a Harding County, South Dakota waterflood unit. Both wells
were completed as commercial oil producers. Capitalized costs for the period were $430,705.
The Company participated with
its 10.5% working interest in the drilling of a step-out horizontal well on a Garfield County, Oklahoma prospect. The well was
completed as a commercial oil and gas producer. Capitalized costs for the period were $136,984.
The Company participated with
its 7% working interest in the drilling of two exploratory wells on a Grayson County, Texas prospect. The first well was drilled
and completed as a horizontal well and is a marginal oil producer. For geologic reasons, the planned horizontal section of the
second well was not drilled and it was completed as a vertical well. The initial completion resulted in marginal oil production.
Additional completion operations are in progress. Capitalized costs for the period were $969,939, including $201,901 in prepaid
drilling costs, and a $510,000 impairment loss was recorded for the horizontal well.
The Company participated with
fee mineral interests in completion operations on two exploratory horizontal wells in Beaver County, Oklahoma (the wells were drilled
in 2012). The Company has interests of 12.6% and 10.2% in the wells, which were both completed as commercial oil producers. Capitalized
costs for the period were $606,009.
The Company participated with
a 5.7% working interest in the drilling of a horizontal development well on a Dewey County, Oklahoma prospect. The well was completed
as a commercial oil and gas producer. Capitalized costs for the period were $269,889.
The Company participated with
its 16% interest in a 3-D seismic survey on a Hodgeman County, Kansas prospect. An exploratory well was drilled and completed as
a marginal oil producer. Capitalized costs for the period were $88,000, including $13,220 in prepaid drilling costs. Seismic costs
of $15,533 were expensed.
The Company participated with
its 10.5% interest in a 3-D seismic survey on a Cimarron County, Oklahoma prospect. An exploratory well was drilled and completed,
testing oil and water. Temporary pumping equipment will be installed to further test the well. A second exploratory well was drilled
and completed as a dry hole. The prospect is under evaluation for the possible drilling of an additional exploratory well. Seismic
costs of $91,822 were expensed for the period. Capitalized costs were $131,953, including $28,784 in prepaid drilling costs. Dry
hole costs for the period were $59,600.
Starting in January 2013, the
Company purchased a 14% interest in 12,404 net acres of leasehold on a Ford and Gray Counties, Kansas prospect for $167,097. A
3-D seismic survey was conducted on the prospect. The Company participated in the drilling of two exploratory wells that were both
completed as dry holes. Dry hole costs for the period were $81,447. Seismic costs of $185,187 were expensed.
The Company is participating
in the development of a Grayson County, Texas prospect with an 8.75% interest. The first phase of acreage acquisition has been
completed. The second phase will involve selling a portion of the acreage to an industry partner, additional acreage acquisition
and the drilling of exploratory wells. Prospect costs for the period were $175,000.
In July 2013, the Company purchased
an 18% interest in 1,440 net acres of leasehold on a Meade County, Kansas prospect for $24,624. The Company participated in the
drilling of an exploratory well that was completed as a dry hole. The leasehold cost was written off to impairment expense. Dry
hole costs for the period were $45,575.
The Company participated with
a 7.5% working interest in the drilling of a step-out horizontal well on a Woods County, Oklahoma prospect. The well was completed
as a commercial oil and gas producer. Capitalized costs for the period were $430,800.
The Company participated with
a 9% working interest in the drilling of a step-out horizontal well on a Roger Mills County, Oklahoma prospect. The well was completed
as a commercial gas and condensate producer. Capitalized costs for the period were $712,754.
In September 2013, the Company
paid $4,320 to renew and extend its 18% interest in 320 net acres of leasehold on a Kiowa County, Kansas prospect. The Company
participated in the drilling of two exploratory wells. The first well was completed as a commercial oil producer. The second has
been completed, testing gas, and is awaiting pipeline connection. Capitalized costs for the period were $215,550, including $77,180
in prepaid drilling costs.
The Company participated with
its 18% working interest in the drilling of a development well on a Woods County, Oklahoma prospect. A completion is in progress.
Capitalized costs were $133,200, including $82,780 in prepaid drilling costs.
The Company participated with
a fee mineral interest in the drilling of an exploratory horizontal well in Kingfisher County, Oklahoma. The Company has a 3.5%
interest in the well, which was completed as a commercial oil and gas producer. Capitalized costs for the period were $460,541.
In November 2013, the Company
purchased a 10.5% interest in 718 net acres of leasehold and 8.5 square miles of 3-D seismic data on a Logan County, Oklahoma prospect
for $120,549. An exploratory well will be drilled in the second quarter of 2014.
In December 2013, the Company
purchased a 7% interest in 2,083 net acres of leasehold and 11 square miles of 3-D seismic data on a Garvin County, Oklahoma prospect
for $155,285. The Company is participating in an exploratory well that is currently drilling. Prepaid drilling costs for the period
were $322,371.
In December 2013, the Company
purchased a 10.5% interest in a five prospect package in Seminole County, Oklahoma covering 1,240 acres, paying a $58,590 up-front
fee (50% of its ultimate cost if all of the acreage is acquired). The Company will participate in the drilling of an exploratory
well and a salt water disposal well on one of the prospects starting in March 2014.
In December 2013, the Company
purchased a 14% interest in 7,290 net acres of producing leasehold and interests ranging from 5.9% to 12.5% in 50 producing wells
in Woods County, Oklahoma and Barber County, Kansas for $1,917,376. The Company will participate with a 5.9% working interest in
the drilling of a development well in the second quarter of 2014.
In February 2014, the Company
purchased a 10% interest in 250 net acres of leasehold on a McClain County, Oklahoma prospect for $11,875. An exploratory well
will be drilled starting in March or April 2014.
In February 2014, the Company
agreed to purchase a 14% interest in 1,705 net acres of leasehold and 70 square miles of 3-D seismic data on a Creek County, Oklahoma
prospect for $684,376. Seismic interpretation and additional leasehold acquisition are in progress, and exploratory wells will
be drilled in the second half of 2014.
Depreciation, Depletion,
Amortization and Valuation Provisions (DD&A).
Major DD&A components are the provision for impairment of undeveloped
leaseholds, provision for impairment of long-lived assets, depletion of producing leaseholds and depreciation of tangible and intangible
lease and well costs. Undeveloped leaseholds are amortized over the life of the leasehold (most are 3 years) using a straight line
method, except when the leasehold is impaired or condemned by drilling and/or geological interpretation of seismic data; if so,
an adjustment to the provision is made at the time of impairment. The provision for impairment of undeveloped leaseholds was $215,861
in 2013 and $136,456 in 2012. Of the 2013 provision, $174,048 was due to the annual amortization of undeveloped leaseholds and
$41,813 was due to specific leasehold impairments. The 2012 provision was due to the annual amortization of undeveloped leaseholds
of $101,596 and specific leasehold impairments of $34,860.
As discussed in Item 8, Note 10
to the accompanying financial statements, accounting principles require the recognition of an impairment loss on long-lived assets
used in operations when indicators of impairment are present. Impairment evaluation is a two-step process. The first step is to
measure when the undiscounted cash flows estimated to be generated by those assets, determined on a well basis, is less than the
assets’ carrying amounts. Those assets meeting the first criterion are adjusted to estimated fair value. Evaluation for impairment
was performed in both 2013 and 2012. The 2013 impairment loss was $1,644,142 and the 2012 impairment loss was $1,811,732. The $167,590
decline in impairments in 2013 was mainly due to the improved natural gas prices.
The depletion
and depreciation of oil and gas properties are computed by the units-of-production method. The amount expensed in any year
will fluctuate with the change in estimated reserves of oil and gas, a change in the rate of production or a change in the
basis of the assets. In 2012, approximately 40% and in 2013, approximately 34% of the working interest wells in which the
Company participated were horizontal wells. A horizontal well may cost five to eight times as much as a vertically drilled
well. In addition, horizontal wells’ initial production rates tend to be greater and their production decline rates are
usually higher than in vertical wells. The larger investment in the costlier horizontal wells and the increased production
rates result in an increase in depreciation expense. The provision for depletion and depreciation increased $901,893 (28%) to
$4,071,720 in 2013 from $3,169,827 in 2012. This increase is due to the reasons discussed above. The provision also includes
$88,457 for 2013 and $116,048 for 2012 for the amortization of the Asset Retirement Costs. See Item 8, Note 2 to the
accompanying financial statements for additional information regarding the Asset Retirement Obligation.
Other Income (Loss),
Net.
See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for
2013 and 2012. Other income, net decreased $134,281 (27%) to $357,081 in 2013 from $491,362 in 2012. The line items responsible
for this decrease are described below.
Net realized and unrealized gains
(losses) on trading securities increased $207,017 to a net gain of $195,721 in 2013 from a net loss of $(11,296) in 2012. Realized
gains or losses result when a trading security is sold. Unrealized gains or losses result from adjusting the Company’s carrying
amount in trading securities owned at the reporting date to estimated fair value. In 2013, the Company had realized gains of $28,917
and unrealized gains of $166,804. In 2012, the Company had realized gains of $6,359 and unrealized losses of $(17,655).
Gains on sales or disposals
of assets decreased $334,579 (74%) to $118,011 in 2013 from gains of $452,590 in 2012. This was due to lower sales of the Company’s
interests in certain non-producing leaseholds in Oklahoma and Kansas.
Interest income decreased $9,601
(30%) to $22,833 in 2013 from $32,434 in 2012. This decrease was the result of a decrease in the average balance of cash equivalents
and average balance of available-for-sale securities from which most of the interest income is derived. The average balance outstanding
decreased $666,735 to $11,822,785 in 2013 from $12,489,520 in 2012.
Provision for Income Taxes.
See Item 8, Note 6 to the accompanying financial statements for an analysis of the various components of income taxes. In 2013,
the Company had an estimated provision for income taxes of $1,897,487 as the result of a current tax provision of $1,492,708 and
a deferred tax provision of $404,779. In 2012, the Company had an estimated provision for income taxes of $1,651,821 as the result
of a current tax provision of $1,187,398 and a deferred tax provision of $464,423.