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 2015, 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 2015, net cash provided by operating activities was $5,425,939. Sales (including lease bonuses), net of production costs, general and administrative costs and income taxes paid were $4,926,433, which accounted for 91% of net cash provided by operations. The remaining components provided 10% of cash flow. In 2015, net cash applied to investing activities was $5,017,556. In 2015, dividend payments and treasury stock purchases totaled $1,674,726 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 decreased $34,752 (8%) to $410,724 in 2015 from $445,476 in 2014. The net decrease is due to $67,643 in unrealized losses, which represent the change in the fair value of the securities from their original cost, offset by $32,891 of 2015 income.
Refundable income taxes increased $333,659 (216%) to $488,052 in 2015 from $154,393 in 2014.
Receivables decreased $1,497,488 (70%) to $644,868 in 2015 from $2,142,356 in 2014. The decrease was due primarily to the use of lower product prices for oil sales accrual estimates for year-end 2015 compared to 2014. Additional information about oil sales for 2015 is included in the “Results of Operations” section that follows.
Accounts payable decreased $593,362 (72%) to $225,648 in 2015 from $819,010 in 2014. This decrease was primarily due to decreased drilling activity due to low oil and gas prices.
Deferred income taxes and other accrued liabilities decreased $224,741 (85%) to $38,493 in 2015 from $263,234 in 2014.
The following is a discussion of material changes in cash flow by activity between the years ended December 31, 2015 and 2014. 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 2015 were $5,425,939, which, when compared to the $14,591,253 provided in 2014, represents a net decrease of $9,165,314 or 63%. The decrease was mostly due to a decrease in oil and gas sales cash flows of $10,235,921, decreased lease bonus cash flows of $1,283,578 and $254,595 decrease in cash distributions from our equity investment in Broadway Sixty-Eight, Ltd. These were offset by a decrease in production costs of $729,782, taxes of $1,586,371 and an increase of $391,290 received from an insurance policy. Additional discussion of the more significant items follows.
Discussion of Selected Material Line Items Resulting in a
Dec
rease in Cash Flows.
The $10,235,921 (53%) decrease in cash received from oil and gas sales to $9,139,958 in 2015 from $19,375,879 in 2014 was the result of a decrease in both 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.
Cash received for lease bonuses decreased $1,283,578 (61%) to $809,980 in 2015 from $2,093,558 in 2014.
The 2015 cash distribution from our equity investment in Broadway Sixty-Eight, Ltd., of $82,500 was primarily for our share of operating profits. The 2014 cash distribution of $337,095 included our share of operating profits plus the profits from the construction and sale of several small office buildings on some land adjacent to our current office building. See Item 8, Note 7 to the accompanying financial statements for additional information regarding Broadway Sixty-Eight, Ltd.
Discussion of Selected Material Line Items Resulting in a
n
In
crease in Cash Flows.
Cash paid for production costs decreased $729,782 (22%) to $2,664,013 in 2015 from $3,393,795 in 2014. This decrease was due to lower lease operating expense of $261,143 and lower production taxes of $468,639 as a result of the decrease in oil and gas sales discussed above.
Cash paid for estimated income taxes decreased $1,586,371 (69%) to $720,544 in 2015 from $2,306,915 in 2014. The lower payments were mostly due to lower net income and current taxable income in 2015.
Investing Activities
Net cash applied to investing activities decreased $1,869,875 (27%) to $5,017,556 in 2015 from $6,887,431 in 2014. This $1,869,875 decrease was due primarily to a $4,207,890 decrease in cash applied to exploration and development expenditures. See the “Exploration and Development Costs” section in the “Results of Operations” section below for more information. This decline in cash applied to exploration and development expenditures and other investments was partially offset by the $1,986,758 purchase of additional available-for-sale securities as a result of the rising short-term interest rates and a $329,815 increase in purchases of equity and other investments. The 2015 purchases include a $656,000 equity investment in Grand Woods Development, LLC. See Item 8, Note 7 to the accompanying financial statements for additional information regarding Grand Woods Development, LLC.
Financing Activities
Cash applied to financing activities decreased $1,590,044 (49%) to 1,674,726 in 2015 from $3,264,770 in 2014. Cash applied to financing activities consist of cash dividends on common stock and cash used for the purchase of treasury stock. In 2015, cash dividends paid on common stock amounted to $1,627,930 as compared to $3,097,246 in 2014. Dividends of $10.00 per share were paid in 2015 and $20.00 per share in 2014. Cash applied to purchase treasury stock decreased $120,728 to $46,796 in 2015 from $167,524 in 2014.
Forward-Looking Summary
The Company’s latest estimate of business to be done in 2016 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 Operations in Item 8 of this Form 10-K, in 2015 the Company had a net loss of ($1,885,332) as compared to net income of $6,762,875 in 2014. Net income/(loss) per share, basic and diluted, was ($11.89) in 2015, a decrease of $54.44 per share from $42.55 in 2014. Material line item changes in the Statements of Operations will be discussed in the following paragraphs.
Operating Revenues
Operating revenues decreased $12,716,826 (60%) to $8,450,986 in 2015 from $21,167,812 in 2014. Oil and gas sales decreased $11,433,248 (60%) to $7,641,006 in 2015 from $19,074,254 in 2014. Lease bonuses and other revenues decreased $1,283,578 (61%) to $809,980 in 2015 from $2,093,558 in 2014. This decrease was the indirect result of the declining oil and gas prices. The decrease in oil and gas sales is discussed in the following paragraphs.
The $11,433,248 decrease in oil and gas sales was the net result of a $3,643,150 decrease in gas sales, a $7,347,723 decrease in oil sales and a $442,375 decrease 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 2015 to 2014. Miscellaneous oil and gas product sales of $179,378 in 2015 and $621,753 in 2014 are not included in the analysis.
|
|
|
|
|
|
Variance
|
|
|
|
|
|
Production
|
|
2015
|
|
|
Price
|
|
|
Volume
|
|
|
2014
|
|
Gas –
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MCF (000 omitted)
|
|
|
1,119
|
|
|
|
|
|
|
|
(352
|
)
|
|
|
1,471
|
|
$ (000 omitted)
|
|
$
|
2,810
|
|
|
$
|
(2,101
|
)
|
|
$
|
(1,542
|
)
|
|
$
|
6,453
|
|
Unit Price
|
|
$
|
2.51
|
|
|
$
|
1.88
|
|
|
|
|
|
|
$
|
4.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil –
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls (000 omitted)
|
|
|
106
|
|
|
|
|
|
|
|
(32
|
)
|
|
|
138
|
|
$ (000 omitted)
|
|
$
|
4,652
|
|
|
$
|
(4,568
|
)
|
|
$
|
(2,779
|
)
|
|
$
|
11,999
|
|
Unit Price
|
|
$
|
44.00
|
|
|
$
|
43.21
|
|
|
|
|
|
|
$
|
87.21
|
|
The $3,643,150 (56%) decrease in natural gas sales to $2,810,121 in 2015 from $6,453,271 in 2014 was the result of a decrease in both gas sales volumes and the average price received per thousand cubic feet (MCF). The average price per MCF of natural gas sales decreased $1.88 per MCF to $2.51 in 2015 from $4.39 per MCF in 2014, resulting in a negative gas price variance of $2,100,628. A negative volume variance of $1,542,522 was the result of a decrease in natural gas volumes sold of 351,372 MCF to 1,119,192 MCF in 2015 from 1,470,564 MCF in 2014. The decrease in the volume of gas production was the net result of new 2015 production of about 34,000 MCF, offset by a decline of about 385,000 MCF in production from previous wells. About 90,000 MCF (23%) of this decline is from working interest wells in Van Buren County, Arkansas. 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 2014 but not in 2015.
The gas production for 2014 and 2015 includes production from about 100 royalty interest properties drilled by various operators in Robertson County, Texas. These properties accounted for approximately 304,000 MCF and $1,258,000 of the 2014 gas sales and approximately 244,000 MCF and $621,000 of the 2015 gas sales. These properties accounted for about 20% of the Company’s gas revenues in both years. The Company has no control over the timing of future drilling on the acreage in which we hold mineral interests.
The $7,347,723 (61%) decrease in crude oil sales to $4,651,507 in 2015 from $11,999,230 in 2014 was the result of a decrease in both the average price per barrel (Bbl) and the oil sales volumes. The average price received per Bbl of oil decreased $43.21
to $44.00 in 2015 from $87.21 in 2014, resulting in a negative oil price variance of $4,568,388. A decline in oil sales volumes of 31,869 Bbls to 105,716 Bbls in 2015 from 137,585 Bbls in 2014 resulted in a negative volume variance of $2,779,335. The decrease in the oil volume production was the net result of new 2015 production of about 10,000 Bbls, offset by a 41,900 Bbl decline in production from previous wells. Of the new 2015 production, approximately 3,500 Bbls (35%) was from new working interest wells in Woods County, Oklahoma. 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 not adequate to replace working interest reserves produced in 2015 or 2014.
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 decreased $544,278 (4%) to $11,917,416 in 2015 from $12,461,694 in 2014, primarily due to a decrease in production and exploration expense. The material components of operating costs and expenses are discussed below.
Production Costs.
Production costs decreased $776,768 (23%) to $2,601,044 in 2015 from $3,377,812 in 2014. The decrease was primarily the result of a $468,639 (60%) decrease in gross production tax to $310,921 in 2015 from $779,560 in 2014 and a decrease in lease operating expense of $215,374 (11%) to $1,788,733 in 2015 from $2,004,107 in 2014. Of the decrease in lease operating expense, $260,883 was the result of decreased expenses for existing wells offset by $45,509 of expenses for new wells. 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 $1,467,772 in 2015 and $6,350,095 in 2014. See Item 8, Note 8 to the accompanying financial statements for a breakdown of these costs. Exploration costs charged to operations were $584,705 in 2015 and $1,284,483 in 2014, inclusive of unsuccessful exploratory well costs of $374,066 in 2015 and $598,900 in 2014, and geological and geophysical costs of $210,639 in 2015 and $685,583 in 2014.
Update of Oil and Gas Exploration and Development Activity from December
31, 20
14
.
For the year ended December 31, 2015, the Company participated in the drilling of 12 gross exploratory and 11 gross development working interest wells with working interests ranging from a high of 16% to a low of 8%. Of the 12 exploratory wells, 5 were completed as producing wells and 7 as dry holes. Of the 11 development wells, 6 were completed as producing wells and 5 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 March 7, 2016, updating both exploration and development activity from December 31, 2014, for the period ended December 31, 2015.
The Company participated with its 16% working interest in the drilling of a development well on a Woods County, Oklahoma prospect. The well was completed as a commercial oil and gas producer. Capitalized costs for the period were $68,293.
The Company participated with an 8% working interest in the completion of a development well that was drilled in 2014 on a Woods County, Oklahoma prospect. The well is a commercial oil and gas producer.
The Company participated with 10.3% and 10.7% working interests in the drilling of two development wells on a Woods County, Oklahoma prospect. Completions are in progress on both wells. Capitalized costs for the period were $71,264.
The Company participated with its 10.5% working interest in the drilling of two exploratory wells on a Cimarron County, Oklahoma prospect. Both wells were completed as dry holes. No further drilling is planned on the prospect. Costs expensed to dry hole costs were $132,554. Leasehold impairment expense for the prospect was $120,675.
The Company participated with its 10.5% working interest in the completion of an exploratory well that was drilled in 2014 on a Logan County, Oklahoma prospect. The well is a marginal oil and gas producer. Capitalized costs for the period were $60,435.
The Company participated with its 10.5% working interest in the drilling of a development well on a Seminole County, Oklahoma prospect. The well has been completed and is being tested. The Company also participated in operations to plug back and repair a salt water disposal well that has been returned to service, and in the installation of submersible pumping equipment in another well that is now a commercial oil producer.
The Company participated with its 10.5% working interest in the drilling of three development wells on a Seminole County, Oklahoma prospect. One well has been completed and tested and appears to be noncommercial. Another has been completed and is being tested, and the third is awaiting the installation of pumping equipment. Capitalized costs for the period were $289,244.
The Company participated in the drilling of three exploratory wells on a Creek County, Oklahoma prospect. Two of these wells were completed as dry holes and the other as a marginal oil producer. Dry hole costs for the period were $56,052 and capitalized costs were $53,590.
The Company participated with its 8.4% interest in a 3-D seismic survey on a Thomas County, Kansas prospect. The Company also participated in the drilling of an exploratory well on the prospect that was completed as a dry hole, and in the acquisition of additional acreage. Additional 3-D seismic data has been acquired and is being processed. Costs expensed to dry hole costs were $29,259. Leasehold costs for the period were $15,023 and seismic costs were $19,783.
In April 2015, the Company purchased a 16% interest in 1,861 net acres of leasehold on a Chase County, Nebraska prospect for $40,191. The Company participated in the drilling of an exploratory well on the prospect that was completed as a commercial oil producer and in the drilling of a step-out well that is awaiting completion. Capitalized costs for the period were $147,309.
In July 2015, the Company purchased a 10.5% interest in 18,069.51 net acres of leasehold on a Thomas County, Kansas prospect for $218,189. A 3-D seismic survey of the prospect has been conducted and the data is being processed. After processing and analysis, decisions about exploratory drilling will be made. Seismic costs for the period were $106,718.
In October 2015, the Company purchased a 14% interest in 1,280 net acres of leasehold and a producing well on a Hansford County, Texas prospect for $108,385. The acreage has been unitized and will be developed for waterflooding. Development plans have been delayed by low oil prices, but drilling should commence sometime in 2016.
In November 2015, the Company purchased a 16% interest in 320 net acres of leasehold on two Kingman County, Kansas prospects for $5,120. The Company participated in the re-entry and washdown of an old dry hole on each prospect. Completion attempts on both wells were unsuccessful and both will be plugged. Dry hole costs for the period were $40,683.
In February 2016, the Company purchased a 16% interest in 12,252.36 net acres of leasehold on a Chase County, Nebraska prospect for $151,929 and paid $88,704 in seismic costs. A 3-D seismic survey of the prospect will be conducted starting in March 2016.
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 $329,871 in 2015 and $310,413 in 2014. Of the 2015 provision, $301,052 was due to the annual amortization of undeveloped leaseholds and $28,819 was due to specific leasehold impairments. The 2014 provision was due to the annual amortization of undeveloped leaseholds of $190,407 and specific leasehold impairments of $120,006.
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 2015 and 2014. The 2015 impairment loss was $3,726,267 and the 2014 impairment loss was $1,928,548. The $1,797,719 increase in impairments in 2015 was mainly due to the decline in oil and 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 2014, approximately 17% of the working interest wells in which the Company participated were horizontal wells. In 2015, the Company did not participate in any horizontal working interest 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 declined $854,022 (22%) to $3,003,193 in 2015 from $3,857,215 in 2014. This decrease is due to the reasons discussed above. The provision also includes $135,088 for 2015 and $90,151 for 2014 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
,
Net.
See Item 8, Note 11 to the accompanying financial statements for an analysis of the components of this line item for 2015 and 2014. Other income, net decreased $37,136 (35%) to $70,278 in 2015 from $107,414 in 2014. The line items responsible for this net decrease are described below.
Net realized and unrealized gain (loss) on trading securities increased $106,781 to a net loss of ($35,741) in 2015 from a net loss of ($142,522) in 2014. 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 2015, the Company had realized gains of $31,902 and unrealized losses of $67,643. In 2014, the Company had realized gains of $58,192 and unrealized losses of $200,714.
Income from investments increased $40,000 to $60,000 in 2015 from $20,000 in 2014.
Interest and other expenses increased $2,999 to $48,047 in 2015 from $45,048 in 2014. The increase was due primarily to a $2,929 increase in the accretion expense to $47,531 in 2015 from $44,602 in 2014.
Gains on asset sales decreased $51,202 to $68,487 in 2015 from $119,689. The gains in 2014 included a sale of approximately $99,000 for some non-producing leasehold that had been fully amortized. There were no similar sales in 2015.
Interest income decreased $3,824 to $13,353 in 2015 from $17,177 in 2014. This decrease was the net result of a decline in the average interest rate, partially offset by an increase 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 interest rate declined from 0.14% in 2014 to 0.11% in 2015. The average balance outstanding increased $9,082 to $11,850,477 in 2015 from $11,841,395 in 2014.
Class action settlements declined $125,585 to $5,593 in 2015 from $131,178 in 2014.
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 2015, the Company had an estimated income tax benefit of $1,472,545 as the result of a current tax provision of $386,886, offset by a deferred tax benefit of $1,859,431. In 2014, the Company had an estimated provision for income taxes of $2,117,241 as the result of a current tax provision of $2,489,141, partially offset by a deferred tax benefit of $371,900.